Good International Petroleum Industry Practices (2016) by DG of Hydrocarbon, India
Good International Petroleum Industry Practices (2016) by DG of Hydrocarbon, India
Good International Petroleum Industry Practices (2016) by DG of Hydrocarbon, India
GOOD
INTERNATIONAL
PETROLEUM
INDUSTRY PRACTICES
(GIPIP)
Prepared by
Table of Contents
PREAMBLE
PREAMBLE .............................................................................................................................................................15
EXPLORATION ..............................................................................................................................................21
1.1 GEOPHYSICAL PRACTICES – MAPPING STANDARDS, GEODETIC POSITIONING AND DATA MANAGEMENT .............................. 21
1.8 GEOLOGICAL PRACTICES – PETROPHYSICAL PARAMETERS (LOG-DERIVED AND LABORATORY DATA DERIVED)........................ 97
1.15 GLOBAL OILFIELD PRACTICES FOR ALTERNATE/SUBSTITUTE DATA TYPES AGAINST THE CONTRACT COMMITTED DATA TYPES OF
THE MINIMUM WORK PROGRAM BID BY CONTRACTOR ..................................................................................................... 146
1.17 STANDARD GUIDELINES ON THE TYPE OF TAPES/MEDIA FOR THE OPERATORS TO SUBMIT THEIR
ACQUIRED/PROCESSED/INTERPRETED DATA .................................................................................................................... 150
1.18 CHOICE OF ACCOUNTING SYSTEM (SUCCESSFUL EFFORTS, FULL COST) ................................................................... 152
1.19 STANDARDS FOR SENDING GEOPHYSICAL DATA ABROAD ONLINE FOR PROCESSING/INTERPRETATION .......................... 159
1.22 DATA ACQUISITION IN ADJOINING AREAS TO ESTABLISH REGIONAL GEOLOGICAL CONTEXT ........................................ 175
1.23 CONTINUED EXPLORATION THROUGHOUT THE LIFE OF THE PSC ............................................................................ 177
1.24 STANDARDS FOR WORK PROGRAM APPROVAL PROCESS WITH RESPECT TO BID, BUDGETED AND ACTUAL COST IN A PSC
REGIME 178
2.1 STANDARDS FOR AREA DEMARCATION FOR DEVELOPMENT, DISCOVERY AND MINING LEASE ........................................... 180
2.2 STANDARDS FOR DECLARATION OF “DISCOVERY”, “COMMERCIAL DISCOVERY” AND “POTENTIAL COMMERCIAL INTEREST (PCI)”
AND ITS ACCEPTANCE BY REGULATORS ............................................................................................................................ 183
2.3 INTERNATIONAL NORMS FOR WELL FLOW TESTS SUCH AS DST AND ANY OTHER TEST PROCEDURES IN OPEN HOLE, CASED HOLE,
GRAVEL PACK, FRAC PACK REQUIRED FOR EVALUATING OR APPROVING THE “DISCOVERY”....................................................... 184
2.5 HOW TO REDUCE TIMELINES BETWEEN DISCOVERY(IES) TO DELIVERY PERIOD (COMMERCIAL PRODUCTION)? .................... 191
2.6 BEST PRACTICES ON MAXIMUM TIME ALLOWED TO THE CONTRACTOR TO RETAIN THE DISCOVERY AREA FOR DISCOVERIES NOT
MONETIZED .............................................................................................................................................................. 192
3.1 BEST PRACTICES REGARDING VARIOUS METHODS OF APPRAISAL CONSIDERING THE EXTENT OF RESERVOIR, HYDRODYNAMIC
SYSTEMS AND CONNECTIVITY, AND DIFFERENT FAULT BLOCKS............................................................................................. 194
3.2 WHETHER DURING APPRAISAL OF A DISCOVERY, THE CONTRACTOR CAN EXPLORE OTHER RESERVES/POOLS ....................... 196
4.1 DATA REQUIREMENT AT THE TIME OF SUBMISSION OF DOC/FDP WHICH IS COMPREHENSIVE AND TRANSPARENTLY KNOWN TO
OPERATOR AND APPROVING BODY IN ADVANCE SO THAT THE ENTIRE DATASET IS SUBMITTED IN A SINGLE INSTANCE ........................ 201
4.2 STRATEGIES TO ALLOW DOC AND EXPLOITATION OF MARGINAL FIELDS ....................................................................... 204
4.3 INTERNATIONAL GUIDELINES FOR CLASSIFICATION AND EVALUATION OF RESOURCES AND RESERVES ................................. 208
4.4 RELIABLE TECHNOLOGY TO ESTABLISH RESERVES UNDER SEC GUIDELINES ................................................................... 214
5.1 INTERNATIONAL NORMS FOR MONETIZATION OF RESERVES IN PROBABLE & POSSIBLE CATEGORIES .................................. 218
5.2 IMPROVED OIL RECOVERY (IOR) / ENHANCED OIL RECOVERY (EOR) PRACTICES .......................................................... 219
5.3 PRACTICES FOR PROMPT AND ORDERLY FIELD DEVELOPMENT ................................................................................... 222
6.1 INTERNATIONAL PRACTICES FOR SUBMITTING LONG TERM PRODUCTION PROFILE AND MEDIUM TERM PRODUCTION FORECAST
AND MID-COURSE CHANGES ........................................................................................................................................ 226
6.2 ISSUES RELATED TO UNDERPRODUCTION AND OVERPRODUCTION FROM FDP APPROVED PRODUCTION PROFILE AND SUGGESTED
REMEDIAL MEASURES BASED ON INTERNATIONAL BEST PRACTICES ...................................................................................... 227
6.4 BEST PRACTICES ON WORKOVERS: WELL INTERVENTIONS, AND STIMULATIONS ............................................................ 233
6.6 QUANTITY AND QUALITY MEASUREMENT: APPLICABLE STANDARDS AND BEST PRACTICES FOR MEASUREMENT OF OIL, GAS AND
WATER..................................................................................................................................................................... 244
6.7 BEST PRACTICES FOR PRODUCTION, MEASUREMENT AND ALLOCATION IN CASE OF PRODUCTION OF DIFFERENT HYDROCARBONS
(OIL/GAS, CBM, SHALE OIL/GAS) FROM THE SAME WELLS OR DIFFERENT WELLS IN THE SAME FIELD ....................................... 248
6.9 WELL PRODUCTION AND RESERVOIR PRESSURE PERFORMANCE REPORTING PRACTICES .................................................. 253
6.12 FLUID PROPERTIES AND COMPOSITION:OIL, GAS, AND WATER ............................................................................. 255
6.13 GUIDELINES FOR RESERVOIR MANAGEMENT FOR OPTIMUM EXPLOITATION RATE AND MAXIMUM RECOVERY OF RESERVES
……………………………………………………………………………………………………………………………………………………………257
6.14 BEST PRACTICES FOR TESTING INDIVIDUAL PRODUCTION WELLS, ESPECIALLY SUB-SEA WELLS: NORMS FOR EXTENDED WELL
TESTING (EWT) AND DISPOSAL OF OIL/GAS DURING TESTING PERIODS ................................................................................ 258
7.4 CORE STUDIES AND SPECIAL CORE ANALYSIS – CORE PREPARATION AND SCREENING ..................................................... 273
7.5 CORE STUDIES AND SPECIAL CORE ANALYSIS – CAPILLARY PRESSURE .......................................................................... 274
7.6 CORE STUDIES AND SPECIAL CORE ANALYSIS – ROCK WETTABILITY ............................................................................. 276
7.7 CORE STUDIES AND SPECIAL CORE ANALYSIS – RELATIVE PERMEABILITY ...................................................................... 278
7.8 CORE STUDIES AND SPECIAL CORE ANALYSIS – ELECTRICAL PROPERTIES ...................................................................... 280
7.9 CORE STUDIES AND SPECIAL CORE ANALYSIS – PORE VOLUME COMPRESSIBILITY........................................................... 281
7.10 CORE STUDIES AND SPECIAL CORE ANALYSIS – APPLICATION OF CAPILLARY PRESSURE: DETERMINATION OF WATER
SATURATION ............................................................................................................................................................. 282
8.1 HSE BEST PRACTICES IN PETROLEUM OPERATIONS: GUIDELINES FOR CONDUCTING PETROLEUM ACTIVITIES/OPERATIONS TO
MINIMIZE THE RISK OF ENVIRONMENTAL DAMAGE ........................................................................................................... 296
8.2 HSE BEST PRACTICES IN PETROLEUM OPERATIONS: GUIDELINES FOR CONDUCTING PETROLEUM ACTIVITIES/OPERATIONS TO
MAXIMIZE HEALTH AND SAFETY .................................................................................................................................... 318
8.3 INTERNATIONAL TIMELINES FOR VARIOUS PERMISSIONS RELATED TO ENVIRONMENTAL CLEARANCES ............................... 331
8.4 PREPARATION OF CONTINGENCY PLAN, EMERGENCY RESPONSE PLAN (ERP) AND DISASTER MANAGEMENT PLAN (DMP) FOR OIL
SPILLS, FIRES, BLOW-OUTS, ACCIDENTS AND EMERGENCIES IN ACCORDANCE WITH INTERNATIONAL PRACTICES ........................... 334
10.3 ARE THERE ANY UNIDENTIFIED GAPS AND AMBIGUITIES IN THE INDIAN PSCS / CONTRACTS? ...................................... 370
10.4 INTERNATIONAL NORMS FOR INSURANCE FOR PETROLEUM OPERATIONS TAKEN BY CONTRACTOR TO PROVIDE FOR LIABILITIES
AND INDEMNIFY THE GOVERNMENT ............................................................................................................................... 371
10.7 APPROPRIATE PHYSICAL AND ENVIRONMENTAL SECURITY CONTROLS FOR THE INFORMATION ASSETS TO ENSURE PROPER
SAFEGUARDS FOR THE E&P INDUSTRY ............................................................................................................................ 388
10.8 PROTECTION OF INFORMATION ASSETS BASED ON THEIR CONFIDENTIALITY, INTEGRITY AND AVAILABILITY (CIA)
REQUIREMENTS FOR THE E&P INDUSTRY ........................................................................................................................ 390
10.9 APPROPRIATE FOLLOWING TECHNICAL CONTROLS DURING THE LIFECYCLE (CREATE, PROCESS, STORE, ARCHIVE, AND DESTROY)
OF INFORMATION AS PER ITS VALUATION AND ASSOCIATED RISK FOR THE E&P INDUSTRY ........................................................ 391
10.10 ESTABLISHMENT AND IMPLEMENTATION OF APPROPRIATE CONTROLS TO ENSURE THAN EMPLOYEES AND THIRD PARTIES
UNDERSTAND THEIR RESPONSIBILITIES AND RISK OF THEFT, FRAUD AND MISUSE OF INFORMATION............................................ 393
10.13 PRACTICES REGARDING OBLIGATIONS OF GOVT. / REGULATOR IN CONTRACT MANAGEMENT ..................................... 409
10.15 GENERAL GUIDELINES ON TIGHT OIL/GAS, CBM, SHALE OIL/GAS EXPLORATION AND EXPLOITATION STRATEGIES ......... 422
10.16 PRACTICES FOR EXTENSION OF PSCS TO EXTRACT MAXIMUM OIL/GAS FOR IMPORTING COUNTRIES ............................ 436
10.17 BEST PRACTICES OF THE GOVERNING BODIES OF DIFFERENT FISCAL REGIMES WITH REGARDS TO THE MANAGEMENT
COMMITTEE .............................................................................................................................................................. 439
10.18 IF SUBSEQUENT TO THE AWARD OF CONTRACT, ACCESS TO THE AREA IS RESTRICTED DUE TO ANY REASON, WHAT ARE THE
BEST PRACTICES RELATING TO RIGHTS AND RESPONSIBILITY OF CONTRACTOR? ...................................................................... 441
Preamble
In India, Oil and Gas Exploration and Production (E&P) activities are carried out under a
Production Sharing Contract (PSC) regime. The PSC prescribes adoption of Good International
Petroleum Industry Practices (GIPIP), Modern Engineering Practices in carrying out petroleum
operations efficiently, safely, prudently and in an environmentally sustainable manner.
The issues related to codification of “GIPIP” were also examined by Comptroller and Auditor
General (CAG) during the audit of a block for 2006-07 and 2007-08 and the following conclusion
was made in the final report of CAG:
“…….Clearly, GIPIP is not a clear, unambiguous and self evident “gold standard”, but “reasonable
judgement” exercised by operators.”
Rangarajan Committee in its report on the “Production Sharing Contract Mechanism in Petroleum
Industry”, has recommended the following on the issue of codification of GIPIP:
“On technical and safety related issues, the Committee recommends Directorate General of
Hydrocarbons (DGH) may undertake codification of Good International Petroleum Industry
Practices (GIPIP) that are of relevance to the Indian geological set-up.”
So far, there is no codified set of “GIPIP” standards in the areas of exploration, development and
production activities. However, the Safety Regulations and Standards have been formulated by Oil
Industry Safety Directorate (OISD). The guidelines of GIPIP would go a long way in establishing
high standards in E&P operations. Such guidelines would also help the Contractors as well as the
Government to remove ambiguities and hence help improving PSC administration.
In the absence of codification of such guidelines by DGH, enforcement and adherence to GIPIP is
fraught with subjectivity and prone to unnecessary disputes. Such guidelines will render objectivity
to the decisions of the regulator, operator and other stakeholders.
Ministry of Petroleum & Natural Gas (MoPNG), Government of India vide Office Memorandum
no. O-23012/8/2013-ONG-I dated 27.12.2013 has set up a “Standing Committee on Petroleum
Industry Practices” under the Chairmanship of Director General, DGH.
The Standing Committee on Petroleum Industry Practices will have the following terms of
reference:
i. To identify the areas requiring codification of GIPIP.
ii. Preparation of national codes for petroleum operations.
iii. Revivew of the code every two years to update in line with evolution of international
standards.
Subsequently, the Standing Committee identified the areas requiring codification of GIPIP to
suggest specific guidelines in conformance with the best international practices and applicable
standards/legislations and prevalent regulatory regime. The Standing Committee formulated the
scope of work for hiring of a consultant by DGH. Pursuant to an International Competitive Bidding
(ICB) tender, DGH awarded the “Consultancy for Study of Good International Practices in
Petroleum Industry” to M/s PetroTel Inc., USA.
PetroTel Inc. is a geoscience and engineering consulting company with headquarters in Plano,
Texas, USA providing professional consulting and advisory services along with integrated project
management support to domestic and international petroleum companies. Their experience
includes working with NOCs, independent, and major oil companies in India, North and South
America, Africa, South Asia, Russia, the Far East, Europe, and the Middle East.
Their study used a combination of their expertise, published documents, worldwide industry
standards, and governmental regulations in various countries. Their report incorporated feedback
from the regulatory body in India, representatives of the Operators in India, and independent
experts.
The objective of this work is to provide guidelines for practices that are considered technically and
contractually reasonable for different aspects of E&P. The guidelines are generally accepted
practices that are used worldwide. The best and most applicable guideline for a particular scenario
will be based on specific field and reservoir conditions.
This report provides a review of Good International Petroleum Industry Practices (GIPIP) in the
following areas:
1. Exploration
2. Discovery
3. Appraisal
4. Declaration of Commerciality
5. Field Development
6. Production
7. Testing and Analysis – Reservoir and Production
8. Health, Safety and Environment (HSE) / Abandonment
9. Procurement Procedure
10. Other Areas
a. Codes or standards are made and published for specific activities by Statutory agencies or
world recognized bodies. The extant PSC provisions, several MoPNG notifications and
other standards/ rules currently facilitate the E&P operations to a large extent. Moreover,
the best practices cannot be laid down as codes immediately for the Indian E&P sector.
However, they may evolve into codes/standards for petroleum operations in India in due
course of time to be issued by appropriate authorities. As per PSC, all E&P operators are
expected to exercise best-in-class techniques and technologies for obtaining the best results.
Hence the Standing Committee recommends adoption of a compendium of “GIPIP-2016”
for the time being, which will act as guiding principles for several facets of E&P activities,
to be used by E&P operators in India, DGH and MoPNG.
b. In a rapidly evolving hydrocarbon scenario, the potential of lack of familiarity with the
latest practices is real. There are a wide array of operators with varying experience working
in India and some guidelines in the form of compendium should be in place to facilitate
stakeholders in conducting petroleum operations.
c. These guidelines for GIPIP cannot be taken to over-ride the PSC provisions or the law of
India or active MoPNG notifications or any other statutory provision of India including
Indian Accounting Standards and Indian commercial practices, which will continue to
prevail under all circumstances unless the competent authority issues a separate
notification.
d. These guidelines are generally applicable for E&P operations in the realm of conventional
hydrocarbons. Some of these guidelines may not apply partially or totally to E&P operations
for unconventional hydrocarbons.
e. There could be variances from the guidelines provided in this report for technical or
commercial reasons and with evolving technologies. It is recommended that discussions
amongst DGH, MoPNG and the operator be held in case of unresolved variances.
f. In line with MoPNG office memorandum, it is recommended that these guidelines may be
reviewed after two years.
g. This compendium is a joint effort of Government and the E&P industry, and hence should
not be used as a basis for initiating any legal proceedings by any party. In case of any
litigation, this compendium could, at best, be used as a reference book.
h. It is also understood that “Good International Petroleum Industry Practices”, “Modern Oil
filed and Petroleum Industry Practices” or any other similar phrase in any upstream
hydrocarbon sector contracts or otherwise, would mean the same and will be guided by
these guidelines.
Exploration
Oil and gas exploration as a process involves developing an understanding of the geological
potential of an area and then evaluating the economic potential for producing hydrocarbons within
that area. The process as a whole involves gathering data from different sources to create an
integrated, complex model of the subsurface. Disciplines involved in the exploration process start
with the geology and geophysics and with the evolution from a general understanding of the basin
architecture through the detailed definition of prospective reservoirs and resources contained within
them.
Direction labels at both ends of cross section (i.e. NE, SW, etc.)
Indicate and label casing points and mud weights on logs when
available to the Contractor
All horizons or faults which are colored should be colored the same
as the seismic interpretation
o Title Block
Name of cross section or name of prospect
Location (country, state, block)
Horizontal and vertical scales and vertical exaggeration
Author(s) and/or company name
Legend for colors and symbols used for annotation should be displayed
adjacent to the title block.
o Seismic Sections
Basic Rules
Fully interpret the seismic section (i.e. mark all the fault traces and
their extents on dip and strike lines)
Use consistent colors on each seismic line for both horizons and
faults and all other illustrations used for the project
Line name
Post all line ties for lines used in interpretation (highlight key ties for
presentations) NOTE: The above items are frequently annotated
automatically using seismic interpretation software.
Post all wells which may impact interpretation (highlight key wells
for presentation).
Well Annotation on Seismic Sections
Operator
Directly beneath or adjacent to the well symbol, post ‘CS’ if the time
depth curve used to display the well is from a check shot survey for
that well, SYN if it is posted based on a synthetic tie and VSP if
based on a vertical seismic profile. No annotation would indicate the
well and tops are posted on the seismic using an estimated time depth
relation not specifically measured at that well (i.e. a shared time
depth curve from a nearby or regional well or best estimate)
If the well is not on the seismic line, indicate the direction and
distance projected to the well (i.e. projected 120 m NW to line, etc.)
For deviated wells, the annotation should state the distance the
marker of interest is projected onto the line.
Plot the well trace on the seismic section and indicate the TD by
ending the well trace at a short horizontal line
Label horizons
conversion and average velocity map that relates the two maps. Some depth
conversion methods, such as maps created directly from PSDM or depth
maps derived by a constant average velocity will not need to provide an
average velocity map.
Use correct industry standard well symbols (see seismic software section).
Post the subsea marker value for the mapping horizon. If the well did not
drill deep enough to reach the horizon post ‘NR’ together with an estimate
of the top, if used in gridding the map (e.g. NR -2180 m est.).
If the mapping horizon is faulted out of the well should post ‘FO’
If there is a check shot survey in the well post ‘CS’, if there is a synthetic
calculated for the well post ‘SYN’, if there is a VSP in the well post ‘VSP’.
Display all seismic data used to create the structure map. All lines posted on
the map should be interpreted. Uninterpretable seismic data should be
annotated on the maps as “poor seismic data”.
Color maps should display an annotated color bar consistent with the grid
color (i.e. color depth structure map would have a color bar in meters).
Seismic attribute maps used for prospect analysis should post a color bar
related to the displayed attribute and depth contours to show conformance
to prospective fluid contacts.
For prospects near or within existing fields of similar reservoir targets the
known oil fields should be displayed with a solid green polygon line and/or
shading over the extent of the productive area. Red polygons should be used
for gas fields/gas caps. Potential gas fields (discovered but not
delineated/developed) should be displayed with dashed polygon lines and/or
striped red shaded area. Potential oil fields should be displayed with green
dashed polygon lines and/or striped green areas. Only fields relevant to the
mapped horizon should be shown on prospect maps.
Prospects should be shaded orange. The estimate of the most reasonable area
should be solid polygon line and/or solid shaded area and the potential
upside should be dashed line and/or striped area (if displayed on the map).
Opacity may be used to show polygons and underlying map details.
Prospects that have wells within the prospective area must post standard
abbreviations for fluid contacts as follows (provided the information is
available to the interpreter and relevant to the prospect):
Type of map
Date
Contour interval
North arrow
Type of map
Date
Contour interval
North arrow
Geodetic Positioning
o There are no specific standards that have been developed or adopted worldwide;
however, there are best practices that have been developed for each of the
disciplines, namely the geophysical industry and the drilling / rig positioning
contractors. Current industry standards are primarily driven by the use of Global
Positioning Systems and in most cases then reference the WGS84 standard. The
UTM projection and WGS84 datum are widely used for international projects and
have standard parameters. Less widely used projection should specify the
parameters used including the projection used to include:
Semi major Axis
Semi minor Axis
Inverse Flattening
Datum
False Easting
False Northing
Central Meridian
Standard Parallel (if any)
Scale Factor and Latitude of Origin
o It is particularly important to include a complete description of the positioning
system employed, the reference datum, and the projection system. This is true
whether the data being transmitted is in Latitude / Longitude or in X Y Z projection
format since both require an accurate description of the Geodetic Datum.
The best practices mentioned above are recommended; however, there may be geologic or
economic reasons to deviate from the above standards. It is recommended that these
standards be made available to the Operators and that Operators follow the standards that
are relevant to their exploration objectives.
Documentation of the positioning system used for any data must be clearly stated on all
data that is presented and archived. Universal Transverse Mercator (UTM) projection
system is primarily used worldwide where the projection is effective. In areas where
multiple UTM zones cover a prospect or regional map it may be appropriate to use a
Transverse Mercator projection with a central meridian that allows for less convergence
within the mapped area.
1.1.3 References
1. Tearpock, D. J., Bischke, R. E., 2002, Applied Subsurface Geological Mapping with
Structural Methods (2nd Edition), Prentice-Hall PTR, Upper Saddle River, New Jersey
07458
2. For positioning related questions please visit http://www.apsg.info/ for Technical
Resources and Official Publications.
Travel Time – Travel time is the basic unit of measurement for seismic data. Travel time is
the elapsed time from a source event (explosives shot, airgun blast, etc.) until the wavefield
is detected at the receiver. Travel time is used as the basis for determining the length of
seismic record, insuring that all of the events of interest have been received during the
period over which the signal is recorded. Two-way travel time is measured in surface
seismic since it is the time for a signal to travel downwards to a formation and then travel
upwards to the receivers.
Group Interval – the group interval is the spacing between adjacent traces in the seismic
acquisition geometry deployed in the field. This is a measurement of the lateral offset
between two traces and is normally a consistent distance set to properly sample the
wavefield.
Sample Interval – the sample interval in seismic data is selected based on the Nyquist
frequency that is needed to faithfully record all of the seismic frequencies of interest. For
surface seismic data the sample interval is normally 2 milliseconds that should be sufficient
to sample the wavefield up to 250 hertz. For high resolution and site survey data the sample
interval is normally 1 millisecond as well as for VSPs. The sample interval may be chosen
upto 0.25 millisecond for CBM surveys. During processing, data is resampled to 4
milliseconds to reflect the usable bandwidth and for compensating less storage capacity.4
milliseconds is rarely used in data acquisition due to the fact that storage (tape) is relatively
inexpensive and the increased cost of preserving higher frequencies is minimal.
Amplitude – Amplitude in a seismic signal represents the amount of energy that is reflected
from a formation boundary. Amplitude is a measure of the properties of the formations
(porosity, rigidity, density, etc.) and the fluid contained within the formations (oil, gas, and
water) and is therefore an important measurement in seismic data. Amplitudes must be
preserved starting with the seismic acquisition system. Current 24 bit A/D systems are
capable of 144 dB of dynamic range.
Velocity – the key unknown in a seismic survey is the velocity at which the sound wave
propagates through the earth. To estimate velocities, there are methods used in seismic
processing that can provide insights to the formation velocities. Likewise, from well data it
is possible to measure the velocity of the formations directly using sonic or VSP / Checkshot
data. Velocity is used in the seismic processing as well as for time to depth conversion in
mapping reservoir targets based on seismic data.
CDP or CMP – These parameters are Common Depth Point or Common Mid-Point and
refer to the point in the subsurface that a down going seismic signal reflects off of a
formation interface before traveling upward to the receiver. The CMP or CDP is the basis
for seismic data processing of reflection seismic data. The CMP or CDP is normally
assumed to be mid-way between the source location and the receiver location which is true
for flat-lying formations.
Fold – When processing surface seismic data to improve signal quality of the data, multiple
traces that come from the same CMP are gathered. Fold is the number of traces that have
come from the same point but have been acquired by using different source and receiver
point locations. Adding these traces together will improve the signal level in the processed
seismic section.
Stack – A stacked seismic section is created by first applying a time correction based on
estimated velocity in processing to the data in a CMP that has different travel paths so that
all traces represent the travel time based on a wavefield that propagates vertically from the
surface position of the CMP to the formations imaged by the seismic traces. Stacked data
do not always reflect the accurate positioning of the events in the subsurface.
Seismic Surveys –The figure below illustrates the typical geometry for seismic data
acquisition. This figure shows a typical land seismic geometry on the left where there is a
recording unit and a source unit that operate independently. On the right a simplified
illustration of a marine seismic operation is shown. In both cases, a source is activated to
generate the down going elastic wavefield that propagates through the earth, reflecting off
of geological interfaces and the up going wavefield is recorded via sensors distributed either
on the land surface or in a marine streamer. A third case, Transition Zone, where there might
be land type receivers onshore and underwater marine type receivers, that use either a land
or marine based source depending upon the geology of the area.
2D surveys are comprised of a series of seismic lines that create a grid over the survey area
(see figure below). In areas of strong structural dip it is important to consider the location
of the axis of the structures in designing the program. 2D seismic data is acquired as vertical
profiles through the geological section. The data represents the wavefield that has the
shortest travel time from source to receiver, and in areas of dip, that travel time to the
formation is normally to a position up dip from the location of the line. Strike lines allow
the data to be tied together during interpretation. Strike lines should be located in areas
where the structural dip is minimized if possible. A best practice is to focus more of the
seismic program in the dip direction and to remain as orthogonal to structural dip as
possible. Since seismic data records the reflected energy based on the shortest travel time
from the source to the receiver that shortest distance is normally up dip of the line, if
shooting parallel to strike. The net result is the strike and dip lines may not tie well at line
intersections.
2D Seismic Grid
Crooked Line 2D Survey: Logistically difficult and hostile terrain of frontier areas poses terrific
challenges ahead of explorationist and our most reliable seismic method of hydrocarbon
exploration. Crooked line survey is outcome of that modification where seismic profiles meander
along the existing roads and possible paths. It has better solution for no. of reasons in spite of further
complication of reflection pattern due to irregular acquisition geometry inclusion at the time of
acquisition. It requires special processing technique to deal with irregular geometry.
3D Seismic Surveys – Three Dimensional seismic surveys are used to obtain detailed
subsurface images. The advantage of 3D seismic surveys is primarily in that they are able
to provide much greater lateral resolution. In areas of complex geology or unusual velocity
overburdens, 3D seismic is able to provide better insights into the geology.
o Bins – In 3D seismic the data are acquired and processed based on Bins. A bin is
the equivalent of the CDP or CMP in a 2D survey in that it is the center point
between the source and receiver. Bins however are defined in advance of the
acquisition with the concept that sufficient sources and receivers will be deployed
to allow for the fold within a bin to meet the survey objectives.
o Marine 3D seismic surveys are acquired by vessels that tow multiple streamers &
sources to collect a swath of data at a single pass as shown in the figure below. The
survey samples a volume of the earth rather than a single vertical profile. Marine
3D seismic is normally very cost effective due to the ability to acquire data over the
survey area in a short period of time. Current 3D seismic acquisition vessels may
tow as many as 20 streamers simultaneously providing both lateral and temporal
high resolution in the data.
o Land 3D seismic surveys are acquired by laying receivers over an area and then
shooting vibroseis or explosives sources into the spread, repeating this process until
the bin has been filled with the planned distribution of traces based on the distance
from source to receiver (offset) and in some cases the azimuth between source and
receiver. Because the receiver and source operate independently (unlike a marine
survey) the design options are much more extensive. Designs for land 3D surveys
incorporate establishing binning criteria such as offset & azimuth distribution, bin
size, and fold, determining the most efficient layout of the receivers, and identifying
the proposed location for sources. In land surveys, there are frequently locations
where it may not be possible to locate sources and these may be identified during
the design stage. Model output from the design tools can be used to test the geometry
and determine whether it is possible to meet the survey objectives. If it is not
possible then recovery source may be planned to meet survey objective.
o Full Azimuth Surveys – The use of properties of the rocks that provide different
reflected responses based on the orientation of the wave field as it reflects from an
interface enables the geophysicist to extract additional information from the 3D
data. Full azimuth surveys are designed to obtain reflection data from a wide range
of reflection angles and azimuths into each bin. These data may then later be
processed to estimate fracture density and orientation or anisotropic velocity
behavior.
3D Seismic
Wide Azimuth Surveys – the objective of wide azimuth surveys is to acquire data that
incorporates the greatest effects from non-normal incident reflections. In studying the
properties of the formations, the geophysicist can model the impact on seismic reflection
data due to effects at very wide reflection angles. These data provide greater insights into
the rock properties and fluid content of the formations.
Nowadays it is used for monitoring the changes of reservoir properties during production
so that further production strategy can be planned. It can be used in logistically challenged
areas where conventional seismic method is difficult to apply.
Transition Zone Seismic – Transition zone seismic surveys can be 2D or 3D programs that
incorporate both land and marine operational characteristics. The operation is typically
managed more like a land survey than a marine streamer operation since there will be
sources and receivers deployed in an uncoupled fashion. Design efforts will need to address
both the types of sources and receivers required for each of the environments.
High Resolution (HR) Seismic Surveys – High resolution seismic surveys are designed to
acquire data that can resolve small scale geologic features. These can be surveys designed
for site investigations and geohazard identification, or in non-oil and gas industries may be
used for mapping coal seams. Normally these surveys are designed for engineering
purposes and not for mapping subsurface oil and gas accumulations although the techniques
used in acquisition and processing High Resolution surveys can be incorporated into
conventional 2D or 3D seismic surveys to obtain higher fidelity data that can resolve thin
beds and small scale geologic features. It is also used in CBM exploration. Typical
differences in acquisition approach for HR surveys include a source that has a wider
frequency range, a streamer may be towed more shallow to avoid surface ghosts, group
interval spacing may be closer, and sample interval for the recorded digital signal may be
reduced to 0.5 milliseconds (or less if necessary). In certain cases, a recent 3D seismic
survey may be reprocessed using high resolution techniques to provide the reflection
seismic data for a site investigation survey.
High Definition (HD) Seismic Surveys – High definition surveys are designed to ensure
geologic features are properly sampled in the subsurface so that they may be resolved in the
interpretation and mapping process. HD surveys typically mean that the group interval
spacing between traces or the line interval between adjacent lines, or the bin spacing in a
3D survey are reduced to oversample a subsurface feature. HD survey planning typically
involves first considering the complexity of the geological environment and then designing
a survey that oversamples the geology such that the imaging step can effectively address
the degree of complexity encountered by the wave field during acquisition. The concept of
the Fresnel Zone and how features are resolved in the subsurface comes into play and will
be considered in the survey design.
Ocean Bottom Cable (OBC) / Ocean Bottom Node (OBN) Seismic Surveys – OBC or OBN
surveys are a subset of marine seismic surveys wherein receivers are located on the ocean
floor. OBC surveys utilize a cable that is placed on the seafloor similar to a land seismic
survey with the cable is connected to a stationary vessel recording the data while a source
vessel traverses the area and shoots into the cable (see figure below). Once all of the source
locations are recorded for a given cable location, the cable is picked up, re-deployed and
additional source points are recorded. The difference between an OBC and OBN survey is
that the OBN survey uses individual nodes that are deployed on the seafloor. In most cases,
these nodes record and retain the data on internal memory until the node is retrieved and
the data is downloaded. All source point Time Zero (T0) are recorded based on an internal
clock that is normally synchronized to a GPS time signal and an internal clock in the node
is used to synchronize the recorded traces to the source T0. OBC / OBN surveys are used
for a variety of purposes, but one must recognize that there is a surface ghost notch in the
data. The advantage of the bottom referenced acquisition is that a gimballed geophone may
be used along with a hydrophone. These two signals can be combined in processing to
remove much of the impact of the ghost. OBC Surveys are also useful for collecting multi-
component seismic data in marine settings. Shear wave energy does not propagate through
water, therefore OBC/OBN surveys are a useful means of recording shear wave data at the
sea floor interface. The figure below depicts the use of receiver groups on the sea floor for
recording converted Shear wave energy.
Uphole Surveys / Seismic refraction survey (LVL surveys) – Uphole surveys are frequently
acquired during land seismic programs. These surveys are designed to determine the near
surface velocity & depth of weathered and sub-weathered layer at pre-determined surface
locations in the survey area. The acquisition of an uphole survey requires first a hole drilled
depending upon the assumed low velocity layer thickness (normally to a depth of 75 to 100
meters), second a recording system, and third a source. There are two methods employed -
either a string of receivers lowered into the hole at a preset interval between receivers with
a source on the surface located close to the hole, or small charges (sources) are placed in
the hole at pre-set depths and a geophone at the surface to record the arrival from the shots.
In both methods, the direct arrival time at the receiver is recorded and plotted as shown
below. Based on this information the near surface velocity can be determined and an
estimated depth to the base of the Low Velocity Layer (LVL) is calculated. This information
can subsequently be used in calculating the statics model and for dynamite surveys to
determine what depth the charge should be placed in the hole (normally just beneath the
LVL).The same principle applies in seismic refraction method. The receivers are laid on
pre-determined location and different sources like light explosive, hammer etc. may be used
to generate elastic wave on planned location. This also gives the velocity of LVL and depth
of base of LVL.
Environmental Impact Assessment - In most cases worldwide there are now requirements
for an Environmental Impact Assessment (EIA) or Environmental Impact Report (EIR)
prior to the start of a project. The survey design documentation will be used as a part of the
input to the Environmental agency to understand how the seismic contractor will be
operating in the field. Each country has their own processes and organizations in place for
both the conduct of the assessments and for the approval of the project based on the
assessment. Guidelines for field operations to minimize environmental impact are provided
by the International Association of Geophysical Contractors (IAGC) (http://www.iagc.org).
IAGC is the international trade association representing the industry that provides
geophysical services geophysical data acquisition, seismic data ownership and licensing,
geophysical data processing and interpretation, and associated service and product
providers to the oil and gas industry. Their guidelines are not strict rules but are the
international standards that most seismic contractors have knowledge of and will agree to
operate under.
Contractor Selection, Audit and Award - After award or during the analysis for awarding
an acquisition contractor a program, an audit of the contractor’s capabilities is performed
before starting the survey. This purpose of the audit is to ensure the equipment is
functioning properly, the personnel are capable of conducting the survey, and that the
contractor understands the complexity of the program they will conduct. Audit is a
necessary function and expertise in seismic instrumentation, surveying, operations, and
HSE are all needed to verify the seismic contractor can perform the work. This is an integral
part of the seismic survey and the cost of the audit is incorporated in the overall seismic
project costs.
Permitting – Before a Contractor can begin work in any area, proper permits for access are
needed. Statutory permission from state and central govt are required. In land surveys this
normally means receiving permission from the land holder to cross the land. Permitting also
includes receiving authorization from other operators if the survey will be crossing into an
adjoining contract area. In marine surveys, permits may be required from the military to
operate in an area. Permit is also required from competent authority of rigs, platform, oil
installation which falls within the area. In any survey, permit is required from local and
state authority.
Marine Seismic Survey Parameter Selection – Apart from design, the survey results depend
on selection of marine source and receiver. Marine receivers are selected basically on its
dynamic range and characteristic response. Normally the spacing between two receivers is
fixed in streamers. Marine sources are normally planned based on the energy output such
that the formations of interest may be imaged. Airgun arrays are measured in bar-meter
output and are easily monitored. They are currently the most actively used source
worldwide. There are different models of air guns although most work in the same fashion.
The differences are primarily in operating pressure, chamber size, output energy and
consistency of the wavefield generated.
of the survey to aid in establishing the appropriate points at which a marine vessel
will need to veer off of a line to avoid a hazard. Operationally, this also means that
the captain of the vessel must have experience working in these types of
environments because they have the ultimate say as to when a vessel will turn off
line. Lack of communication before and during the survey will result in poor
coverage.
actuator and impart the signal into the ground. Part of the start-up exercise
for a new survey is to test the sweep frequencies, selecting a range that
minimizes the noise the vibrators generate and maximizes the reflected
energy across all frequencies in the sweep. Each sweep may last from just a
few seconds to 30 seconds or more while in most instances they last between
10 and 16 seconds. The vibrators may execute multiple sweeps at a single
location with all of the data summed together in the recording unit to
increase signal to noise (s/n). Positioning of the vibrators is initially
surveyed during layout and then the final position is determined using GPS
and transmitted to the recording unit.
Other sources that may still be in use include weight drop, land air gun, and
for shallow investigation, sources like the sledge hammer,
and the shotgun source shown in the picture. These are not normally used in
oil and gas operations but may be effective for surveys such as shallow
refraction spreads.
o Land survey design criteria
Surface Consistency – one part of designing a seismic acquisition program
on land is that the design will address the requirements for a surface
consistent processing approach. This is significant in that failure to meet
these requirements may result in inconsistencies in statics calculations,
amplitude and wavelet stability. Surface consistency dictates that there must
be within the survey points which provide reciprocity between source and
receivers that couple the entire line or 3D survey.
Offset requirements – for Land data the same criteria as referenced above
for marine data holds. Offset distances are key to imaging both for depth of
investigation and migration apertures as well as velocity determination.
Multiple attenuation is a separate issue for land data as the dominant
multiple type in land data is inter-bed multiples and offset is not in all cases
sufficient to attenuate inter-bed multiples.
Azimuth requirement- It is very important parameter to study fractures,
faults and anisotropic behavior of formation. It depends on the receiver line
interval and length of the receiver line. It is basically planned during
acquisition phase.
Source interval – the source effort in many cases has the most significant
cost impact. If explosives data is being shot, the time involved in drilling the
shot holes and handling the explosives add to costs. For vibroseis surveys
the time on each source point is dependent on the number of sweeps and
length of each sweep and the listen time. For a 10 second sweep and 6 second
listen – six sweeps per VP with move-up between each sweep, the time per
VP can exceed 5 minutes. Add to this the time for preparing the line, and
although it is a very efficient process, the time quickly adds up. However,
the source interval helps define the fold that will be acquired for the survey.
Receiver Group Interval – The receiver group interval is designed with the
primary goal of establishing the trace spacing that images the subsurface
without aliasing. Aliased data provides ambiguous results in terms of the dip
of a formation in the stacked or migrated data and in the pre-stack data may
result in ambiguity in the velocity determined in processing. Modern
acquisition crews have high channel count and are able to provide a
sufficient number of channels to design for tight group intervals. The group
interval defines the CMP interval in the processed data. It is possible in
processing to combine two adjacent CMPs (which would increase the fold),
if desired, to improve signal to noise of the data.
The Sample Interval and Record length are selected to ensure sufficient data
is acquired to image the formations of interest and normally to allow for
imaging to basement unless the data is in a very deep clastic basin.
Field Filters are normally not selected to aggressively filter the data in the
field for the reasons discussed below about the use of 24 bit A/D converters.
Severe ground roll may dictate some filtering in the field but this is a
parameter that should be tested in the field before finalizing parameters.
Geophone arrays – Seismic data onshore and at times in transition zone
surveys are recorded using geophones or accelerometers that detect motion.
The geophones are in most cases strung with multiple geophones on a single
cable wired in series or series/parallel. The geophone array in theory is
designed to attenuate unwanted noise and enhance signal. They do this by
spreading the geophones over an area or along a line. Principally, the array
attenuates a horizontally propagating wavefield since the geophones wired
in series are all receiving the signal at different times based on the spacing
of the geophones. Theoretically, the array enhances the reflected seismic
signal since the assumption is the signal is received simultaneously on all
geophones as a vertically propagating wavefield. Small intra-array statics
caused by elevation differences or velocity differences in the near surface
can cause the “signal” to also be attenuated to some degree. Geophone array
designs must be carefully considered since they provide minimal attenuation
to horizontal wavefields (typically ~13 dB) and can have an impact on the
amplitude of the desired vertically propagating wavefield.
Seismic Acquisition Systems –All modern seismic acquisition equipment has evolved to
use a minimum of a 24 bit A/D converter. The number of bits in the A/D converter directly
relate to the dynamic range that the recording instrument is capable of faithfully recording.
Older seismic acquisition systems going back as far as the DFS V systems used a gain
ranging amplifier as the front end to the A/D converter. While this allowed the recording of
a wide range of amplitudes, it resulted in data that did not faithfully record the relative
amplitudes in all cases and if there was a high amplitude event (such as a direct arrival) the
system may not be able to detect the smaller amplitude signals in the presence of the larger
amplitude events. This also drives decisions about the recording filter used because if
ground roll is an issue and it is overwhelming the signal, the use of the filter meant that
even though there might be seismic signal desired in that low cut filter range, the data was
attenuated along with the noise.
o Marine Systems – most marine systems utilize streamers with the A/D converters
located in the streamer. This technology allows the digital signal to be translated
through the streamer wiring and eliminates the issue of cross-feed between channels
in the streamer. The recording system on the vessel collects all of the data. All
collected data are written to a permanent media on the vessel itself for further usage
and storage. The recording system is where the validation of the seismic streamer
functionality takes place as the observer is able to review shot records as well as
system tests to ensure all channels are functioning properly. Seismic acquisition
contracts have specifications established by the Operator to define the number of
bad or dead traces that may be allowed during the survey. Failure to maintain the
system operating at that standard will require the contractor to reshoot data that is
outside of specifications.
o Land Systems – There are basically two types of land systems – cabled and wireless.
The cabled systems have physical cables that are connected with receivers
throughout the field to bring the data to the recording unit. Typically there are
remote receiver units in the field that have the A/D converters and filters set and
those units transmit the data at the end of each shot. In some cases, there are units
that are able to retain historic information for a given period of time before that data
is overwritten by subsequent shots. The primary issue in very high channel count
systems is the bandwidth of the cable / remote unit systems to transmit all of the
data to the recording unit before the next shotpoint or vibrator point is activated.
Wireless systems come in two types, those that can transmit the data to the recording
unit and those that maintain all data within the unit until it is downloaded through
either a wired connection, radio link, or physical connection to the recording system.
o Selecting a recording system – the recording system selected for a seismic survey is
normally based on the availability for the Contractor with the winning bid on a
survey. In all cases, the system selected should be using the 24 bit technology.
Wireless systems that do not send data back to the recording unit immediately can
be of concern due to the uncertainty of whether data was successfully recorded. In
these cases the best solution is to ensure the geometry design in the field can tolerate
missing traces and still achieve the survey objectives.
Transition Zone surveys are a hybrid between the marine and land survey techniques.
Special consideration must be made to determine the optimal source and receiver
relationship and considerations for how the data will be collected and ultimately processed.
Typically in Transition Zone surveys the dominant factor will be the land and shallow
marine segments as they follow the same sort of design rules for the receiver configuration
as a land survey. The source in the transition zone can be more problematic and there are
options to use shallow water source vessels as well as shooting into the land / transition
zone spread from the streamer vessel simultaneously as it is surveying offshore. This special
case requires unique skills and capabilities and cannot be covered to a full extent here.
Selection of the right contractor is going to be critical and often that does not lead to the
lowest cost option.
Seismic Field Operations – Seismic operations whether they are marine or land based are
complex operations. During the conduct of the survey the Contractor is working under the
design parameters provided by the Operator to generate the raw data. Critical steps in the
field operations are overseen using specially trained Quality Assurance personnel. The
Quality Assurance representative works alongside the seismic crew to verify they execute
the survey to the Operator’s specifications. In most cases, the QA staff are third party
Contractors hired by the Operator. A QA representative has specialized skills and
knowledge of the instrumentation, survey, and the operational needs for a survey. These
individuals do not have the skillset that the operating company geophysicist has but
complement those skills.
HSE - IAGC has published HSE standards for marine and land seismic operations and these
standards are widely adopted by IOCs, they are available for download from the IAGC
(http://www.iagc.org/free-view-downloads/).
Seismic Acquisition is a significant component of most work programs in PSCs. The quality
of the data and ability to evaluate the hydrocarbon potential of a block is directly dependent
on the effort placed on the planning, quality assurance, and execution of these projects. The
following areas are minimum requirements for a successful program:
Select a seismic method that meets the needs of the exploration or development program.
2D seismic is normally used for regional grids and 3 D seismic is used to further define the
identified prospects as part of exploration projects. 3D seismic is usually carried out when
the geological structures are complex and for development projects to optimize well
placement and improve the understanding of the fields under development. 3D surveys will
also aid in full field reservoir description by better sampling the subsurface and can be used
for mapping reservoir properties using seismic inversion to demonstrate lateral changes in
the formations of interest. Selection of these methods also depends on the geographical and
geological set up of the area.
Design seismic surveys to meet the spatial and temporal resolution requirements of the
exploration and development programs.
o Optimize the survey design to ensure the subsurface geology is best imaged.
Consider strike versus dip orientations and optimize the design based on imaging
criteria.
Model the acquisition plan and validate the parameters to address any anomalous velocity
characteristics of the subsurface. Consider whether an anomalous (e.g. low or high velocity)
zone requires undershooting and determine whether the geometry selected will enable
imaging beneath that zone.
Pre-plan the seismic processing flow to address identified subsurface issues and test the
acquisition parameters in the field to ensure the methods being employed meet the program
objectives. If amplitude studies are part of the processing and interpretation flow, consider
the requirements those studies place on the raw field data. Design the survey with adequate
migration aperture to ensure the final imaged dataset covers the exploration or development
area.
Pre-Tendering planning of the seismic project will include determining the geological
objectives for the survey, determining the appropriate technique to be employed and in
many cases modeling the expected seismic response to ensure the survey can meet the
objectives. Operators are responsible for ensuring the survey parameters are clearly defined
and communicated to the seismic contractor.
Pre-Survey audit of the seismic contractor’s equipment, personnel and processes are
normally conducted by a seismic Quality Assurance specialist. The assessment will include
consideration of the HSE, hardware capabilities being able to meet specifications, and
environmental impact risks posed by the Contractor.
Onboard or Onsite representation by the PSC Operator is imperative to ensure the seismic
contractor is operating according to plan and meeting the environmental and HSE
stipulations. The QA representative is also responsible for ensuring the data quality meets
the survey requirements.
A final report from the Operator is required and should be submitted along with the data
forwarded for archival. The report should summarize operational details and parameters;
HSE Statistics; issues during the acquisition project along with their resolution; surveying
and positioning systems used; and include the final report from the contractor, Quality
Assurance, and Marine Mammal Observer if required.
Seismic operations particularly on land can impact local land owners and in agricultural
areas may result in some crop damage. A Particle Motion sensor may be deployed during
surveys near buildings or bridges to monitor that actual impact of the seismic sources and
may prove instrumental in proving to local building owners that a seismic source was not
responsible for damage. Compensation for damages is an issue that must be managed
carefully to avoid damaging relations in the local community and potentially impacting the
ability to continue exploration activities in the area.
Offshore seismic operation frequently encounter fish nets or traps and all reasonable effort
to manage the impact is suggested. Early and frequent communication with local fishermen
may help to eliminate some of the claims for damaged or lost equipment.
1.2.3 References
1. Cooper, Norman M; December 2002, CSEG Recorder Vol 27 no 10, “Seismic Instruments
– What’s New?...And What’s True”
2. IAGC Land Safety Manual, International Association of Geophysical Contractors
3. IAGC Marine Safety Manual, International Association of Geophysical Contractors
4. Caldwell, J., Dragoset, W., August 2000, The Leading Edge, pp 896-902
5. Bagini, C., Bunting, T., El-Enam, A., Laake, A., Strobbia, C., Summer 2010, Land Seismic
Techniques for High-Quality Data, Oilfield Review
6. Stone, D.G., Designing Seismic Surveys in Two and Three Dimensions, SEG, Tulsa, OK.
7. Vermeer G.J.O., 3D Seismic Survey Design, SEG, Tulsa, OK.
at the earliest stage possible in the processing flow such that noise does not propagate through
subsequent processing steps.
One key consideration with seismic data is comprehending the resolution of the data. Processing is
the art of retaining and emphasizing the resolution that was obtained in the acquisition phase. There
are many discussions about seismic resolution, both temporal and spatial. The Temporal Resolution
is the vertical resolution of the data or a measure of how thin a bed may be either detected or have
the top and base of the unit resolved. Thin bed analysis uses tools like amplitude analysis for
calculating bed thickness based on the amplitude variations when the data is calibrated to wells and
can be consistently mapped. The Spatial resolution is the ability to detect the presence or absence
of a unit based on the sampling of the data. Narrow channels may require denser sampling in order
to first detect and then resolve the presence of a particular channel sand body.
High Density or High Resolution surveys as discussed in Section 1.2 are special cases in the use of
reflection seismic data. They specifically referred to either the spacing of the seismic traces or the
ability to resolve thin bed units through greater seismic bandwidth and in fact result in a
combination of both. The approach to process these types of data is not distinctly different from
any other exploration processing project; however, the level of detail in the desired survey results
dictates a higher degree of quality assurance to ensure the veracity of the data remains intact.
Imaging criteria, intervals between velocity locations, and selection of parameters to maintain
bandwidth all must be addressed.
Definitions of key terms is shown below:
Seismic Processing Datum – Seismic sources and receivers are normally not co-located on
the same vertical level. This is true for both land and marine seismic data. To account for
the differences, a datum correction is applied to processed seismic data to shift the data to
a known horizontal surface. To move the data, a correctional velocity is used. Land data is
normally processed at a floating datum which means that the data is shifted to a datum that
is relative to the surface elevation at the CMP location. One of the final steps in the
processing is to move the data to a flat datum that is defined by the operator. This datum is
called SRD (Seismic reference datum).
Uphole Times – in processing explosives data, a common step is to add the travel time
captured by the uphole geophone for each shot to move the shots to the surface elevation.
The uphole times are reflective of the shallow velocity field in the survey area and may be
used to develop a near surface statics model.
Surface Consistent algorithms as discussed in the seismic acquisition section are important
for land processing since they provide a means to address variability in the near surface in
the statics correction, variability in the wavelet in the surface consistent Decon, and
amplitude differences that are consistent at specific recording stations using the surface
consistent amplitude corrections. The amplitude correction is at times used on marine data.
Even though it does not obey the source criteria for surface consistency, it enables balancing
of traces to eliminate amplitude differences due to electronic circuitry or receiver
sensitivity.
Both the land and marine data processing flows show Pre-Stack Time Migration (PSTM).
It deals with complex geological structure where stacking does not work well. Nowadays it
is routine practice to run PSTM. It gives seismic volume in time domain.
Both the land and marine data processing flows show the optional Pre-Stack Depth
Migration (PSDM). PSDM is used for several reasons:
o To address abrupt velocity variations (mainly lateral velocity variation)that cannot
be resolved through PSTM;
o It addresses significant velocity inversions such as the effect of salt above
sedimentary section of interest; and
o For significant structural deformation it may yield better imaging of sub-thrust
stratigraphic sections.
PSDM does however require a velocity model that is more rigorous than PSTM as a starting
point. The PSDM velocity field is more closely attuned to the geological model of the
subsurface, so interaction with the interpretation team is critical to success.
2D land data in some instances is recorded such that the source and receivers are not in a
straight line and they do not lie on the same vertical plane. As a result, crooked line
processing is used in which the data are treated more like 3D sampling and the data are
“binned” with the data gathered into Common Midpoint (CMP) gathers for processing, with
the CMP centers being off of the line of source and receivers.
available technology needs to be ingrained in the processes for managing the processing and
interpretation of geophysical data.
The objective of the processing step is to insure the best possible image of the geology is developed.
This requires participation by the geologists and geophysicists working on the interpretation of the
area along with the seismic processing specialists. Imaging is the focusing of the data that was
acquired into a properly positioned and accurate representation of the structure and stratigraphy in
the exploration area.
The best practice for processing seismic data is at its most basic level to ensure that the processing
flow employed fits the demands of the data and the imaging criteria for the final product. Every
geological environment has a unique set of challenges and as such a processing flow that will
address the challenge is developed during the processing of that data. Processing tests are designed
to evaluate the parameters to be used at each step of the flow and are revised if the results are found
to not resolve data quality issues. Every project should have a defined testing program that will
evaluate at a minimum the Deconvolution, Noise Attenuation, Velocity picking density
requirements, the proper imaging technique (Migration, Pre-Stack Time or Depth Migration), and
the final scaling and archival of data.
o Enhanced processing steps shown in the figure are of two types. There are the
regularization or noise attenuation capabilities that go beyond normal processing
flows. These tend to be incremental steps when provided by processing contractors
and are meant to improve the data in the beginning of the processing flow. There
are also “interpretive” processing results that can drive the manner in which the
seismic data can enhance the interpretation results. These processes such as
extraction of AVO attributes or Anisotropic Velocity attributes typically lead to
better processed images, but also allow for output of analytical results that influence
exploration. Anisotropic velocity analysis can lead to better definition of fracture
orientation and density that is critical to drilling exploration or development wells
in fractured reservoirs or tight shale plays. The input requirement for this analysis
includes having recorded source – receiver azimuths over a wide distribution of
orientations. Wide Azimuth acquisition techniques are required. As a result this is
normally limited to 3D data.
o The Processing Flow shown here is indicative of the level effort for processing the
data but is not intended to be either all-inclusive of technologies available or to
replace expertise that a knowledgeable seismic processing specialist brings to a
project.
Target
oriented
PSTM
Marine Seismic Processing brings with it a different set of processing challenges. Generally
speaking marine seismic data is better quality than land data, partially owing to the more
consistent generation of source energy and consistent coupling and recording in the
streamers. The processing flow shown in the figure that follows depicts the typical set of
processing steps for marine seismic data.
o Signature Deconvolution is normally applied to marine seismic data. The process is
made possible due to the consistency of the seismic source and the ability to
effectively model or measure the source signature. In the processing flow, signature
deconvolution corrects the phase of the seismic data through the use of an inverse
filter to move the data to zero phase. This enhances the temporal resolution. This
enables the interpreter to more reliably interpret a peak or trough to represent an
increase or decrease in seismic impedance.
o Multiple Attenuation processes are very effective on marine data although they can
be present in land data too. There are a variety of algorithms that are currently under
development as well as in production that can remove water bottom multiples, free
surface multiples, and interbed multiples. Each contractor has their own approach
and depending on the severity of the problem the operators may elect to process the
data at a contractor with a specific algorithm.
o The Processing Flow shown here is indicative of the level effort for processing the
data but is not intended to be either all-inclusive of technologies available or to
replace expertise that a knowledgeable seismic processing specialist brings to a
project.
Target
oriented
PSTM
2D Seismic Processing - There are few issues in seismic processing that are unique to 2D
data. A significant difference between 2D and 3D processing in complex structural regimes
is the impact of the orientation of the lines with respect to the structure and whether the 2D
image is in the plane of the line. Out of plane structures will result in velocities that are not
geologically reasonable, so understanding the geology is important when processing the
data.
A minor complication in processing is the proper recording of the position of the trace.
Shotpoint and receiver positions are used to calculate the location of the CMP. There are
typically more CMP locations than shotpoints and this especially becomes an issue in
loading stacked seismic data into interpretation workstations. The original shotpoint
locations are not necessarily relevant after the data is processed, yet systems still enforce
shotpoint locations for the seismic traces. It is important to be aware that the CMP location
and numbering is what should be used when loading the traces into an interpretation
database.
3D seismic processing is unique in that it utilizes a binning system that may not have any
relationship to the original shotpoint or receiver locations. The binning system calculates a
grid over the survey area into which all of the data are collected. CMP positions are
calculated for each trace and the traces are gathered into the bin nearest to the calculated
CMP position. In Wide Azimuth surveys the orientation of the azimuth between the source
and receiver station for each trace is also retained. This information is subsequently used
when anisotropic velocity analysis is performed on the dataset.
Most seismic processing projects are undertaken by third party contractors although in some
large companies the ability to process the data internally is available. In all cases the need
for quality assurance of the processing is necessary. Quality Assurance is essentially a
technical audit of the approach being used to process the data.
The Quality Assurance effort is focused on two levels. The first is that the appropriate
application of technology is upheld. Experienced processing professionals review the
results during each phase of the processing project to ensure the technical solution fits the
underlying data. An example of this would be reviewing a refraction or reflection statics
solution. Do the refractions appear to have been properly picked? Is the cable geometry
appropriate for the Surface Consistent Statics solution? These are but a small sample of the
areas requiring technical audit. The following list is an example of some of the areas to be
evaluated during the QA process. It is not an exhaustive list nor does it address the degree
to which newer technologies may be properly or improperly applied.
o Amplitude Recovery – Test to validate the amplitude balancing of the raw shot
records at the beginning of the processing flow;
o Initial Filter – Does a frequency filter need to be applied early to clean up shot
records?
o Kill Bad Traces – Review random shot records to determine whether the processors
are eliminating bad data from the processing flow before it can have a detrimental
effect on the overall end product;
o Source Noise Attenuation – Are there source generated noises (ground roll, surface
waves, etc.) that should be removed before processing?
o Shot Domain Deconvolution – Tests are done on the shot records to compare
different deconvolution approaches. Deconvolution is an effort to balance the
frequency spectrum early in the processing flow and will have an impact on the
stability of the wavelet as velocity and statics solutions are applied;
o Multiple Attenuation – Are there shot domain or receiver domain multiple
attenuation approaches that might impact the ultimate quality of the final product.
Determine the appropriate methodology to be applied for attenuating the multiples.
This is an area of extensive research in the industry and there are a wide variety of
approaches. Different processing vendors will have either algorithms they have
developed or experience from processing similar data that will impact the approach
used. The experienced QA person will need to ensure there are tests and displays of
fundamental data that validate the approach used has eliminated noise without
impacting the underlying reflection data;
o Geometry Assignment – This is an area where the processor can have errors that
will significantly impact the final product quality.
o Statics Solution – Both the refraction and reflection statics model must be reviewed
to determine that they have been properly resolved;
o Velocity Analysis – Processors normally start the processing with a single velocity
for a line and then progressively increase the density of velocities from 1 km spacing
to 250 m as they progress through the processing sequence as the velocities will
determine how accurate the normal move-out correction will be and hence has an
impact on the wavelet stability and temporal resolution of the data. QA needs to
focus on the velocity picking effort.
o Stacked Sections – Reviewing stacks along each step of the processing is critical.
They help to illustrate issues with the geometry, velocity picks and all of the
individual processing steps.
o Migration – Either Pre-Stack (PSTM) or Post Stack Time Migration can be used for
both QA purposes to see how the overall section is developing or to finalize the
output.
o PSTM Velocity picking – there are several approaches to PSTM velocity picking.
Depending on the approach the critical element is to QA each line to validate the
velocity picks are optimizing the focusing of the final output image. Due to the fact
that there may be constructive interference that affects amplitudes, picking
maximum amplitudes for velocity imaging is not always the right solution, this
requires user input.
o PSDM Velocity Model – for Pre-Stack Depth Migration (PSDM) the process is
driven by the velocity model. An initial model normally taken from the PSTM
solution must be modified to fit the best geological interpretation. Iterations of the
velocity model are used through tomographic imaging and user input to optimize
the final output. PSDM may be a standard output for certain areas but will be limited
to areas where a reasonably accurate velocity model can be developed based on the
time sections. In areas where severe horizontal velocity variations and / or complex
geological structures are present PSDM is preferred but may be limited by the need
for a detailed velocity model as a starting point.
There are many steps to be audited during the processing of seismic data and these require
a trained eye of the processing specialist. The second level of quality assurance is that the
geological model must be represented by the final processed section. The interpreters must
be involved in validating that the processing approach being used is driving the solution
towards correctly imaging the subsurface.
All seismic processing projects including both new data and reprocessing of old data must
be thoroughly documented to reflect the objectives, processing steps, and issues
encountered during the processing of the data. Some of these observations are from the
processing contractor, but an analysis of the results from the PSC Operator are necessary to
ascertain whether the processed results achieved the intended results.
Archival of processed seismic data in several forms is needed to enhance how the data may
be used for future analysis or interpretation. The best practice is to archive the data in SEGY
format at several stages of the processing such as:
o After application of Deconvolution
o After application of noise attenuation processes
o Final CDP Gathers with statics applied – the input data to the final stack
o Final Stacked Sections
o Final Stacking Velocities
o Final Migrations (either Pre or Post Stack Migrations or both)
o For Pre-Stack Migrations the Migrated CMP gathers
o Final Filtered and Gained data
o Final Migration Velocities
The SEGY EBCDIC headers must include details regarding the processing sequence used
as well as co-ordinate reference system used and clarify the byte locations of key fields used
in the processing flow. The format for these headers should follow the content as listed in
the Yellow Book from the NPD in Norway unless there are other local requirements in
place. Byte location in the stack section should be as per standard SEGY format.
Processing seismic data is intended to provide a result that best addresses the geological
issues in an area. An appropriate processing flow should be developed based on the quality
of the input data as well as the geologic objectives.
Quality Assurance throughout the processing project is required to ensure the geologic
objectives as well as the appropriate technology is being used on the project. QA also
ensures the processing parameters are appropriately selected for each of the steps
throughout the flow.
All seismic processing projects must include a report that summarizes the objectives of the
project, the tests conducted to select the parameters used, examples of data quality issues
and how they were addressed, and examples of the final output data. A summary of the
seismic lines processed and the output data should be incorporated into the report.
1.3.3 References
1. Ikelle, L.T. and Amundsen, L, 2005, Introduction to Petroleum Seismology, SEG, Tulsa,
OK, 679 p.
2. Thomsen, L, 2007, Understanding Seismic Anisotropy / Explor. Exploitation, SEG, Tulsa,
OK.
3. Calvert, R., 2005, Insights and Methods for 4D Reservoir Monitoring and
Characterization,SEG, Tulsa, OK, 219 p.
4. Cordsen, A., Galbraith, M., Peirce, J., 2000, Planning Land 3-D Seismic Surveys, SEG,
Tulsa, OK, 204 p.
5. Wang, Z., Nur, A. 2000, Seismic and Acoustic Velocities in Reservoir Rocks Volume 3,
SEG, Tulsa, OK, 633 p.
o Operator should provide depth maps from the seismic interpretation at relevant
expected reservoirs with suitable estimates of the prospective resources for each
prospect in Low (P90), Best (P50) and High (P10) categories. The parameters
required for prospective resource estimation will be based on the petrophysical
interpretation of the wireline logs of the drilled wells in and around the block area
as available. Prospective resource estimates can be either deterministic or
probabilistic.
o Direct Hydrocarbon Indicators (DHI) and Amplitude Variation with Offset (AVO)
should be used to evaluate prospects where appropriate fluid substitution modeling
supports a noticeable hydrocarbon effect on seismic or a correlation with nearby
production can be established. A DHI that correlates to a closing contour of a
mapped prospect should be used as the P50 case.
o In areas/intervals of known over pressure or areas/intervals where there has not been
any drilling in the past, the Operator should carry out subsurface formation pressure
study – generate pore pressure profile indicating top of abnormal pressure, if any,
using well and seismic velocity data over each identified prospect. Operator should
generate the pore pressure gradient profile and fracture pressure gradient profile of
all the drillable prospects for well design.
o Fault seal analysis should be completed on prospects that require a fault seal either
through use of an Allen Diagram to illustrate juxtaposition of reservoirs and seals
across the fault or fault smear/gouge analysis for fault planes that are expected to
act as sealing surfaces.
for trapping. The Operator should identify and assess the volume (gross and
net), quality (porosity and permeability), and distribution of the major
reservoir intervals using any available analogues to evaluate potential
production rates. The Operator should identify and evaluate the principal
regional seals in terms of both presence and effectiveness. In areas of limited
data, the petroleum system analysis may rely on existing publications and
government geologic reports.
o Play Fairway Assessment
Define play types based upon principal reservoir intervals and their access
to regional source and seals. Review, collate and prioritize all potential
trapping mechanisms.
o Prospect Evaluation / Prioritization
Operator should review and summarize all data relating to each significant
prospect identified, including at least two key seismic lines that define the
trapping mechanism. To the extent practical, target depths will be considered
in the context of reservoir quality prediction and estimation of formation
volume (Bo) factors for oil and/or gas expansion (GEF) factors. The key
geological risk factors of trap (presence and effectiveness of trap and
including seal consideration), reservoir (presence and quality) and source
(presence, maturity and migration efficiency) will be combined to derive
overall geological risk.
Volumetric estimation of Stock Tank Oil Initially in Place (STOIIP) and/or
Gas Initially in Place (GIIP) will be made on all prospects by combining
gross reservoir volume (area multiplied by gross thickness) with averaged
estimates of net-to-gross ratio, porosity, hydrocarbon saturation, fluid data
(Bo/GEF) and volumetric conversion factors. Depending on data
availability, a range of input factors will be included, and as requested,
Operator should calculate Deterministic and/or Probabilistic resources on all
significant prospects (i.e. those surpassing minimum thresholds of size and
risk) to derive a distribution of volume versus probability. Commercially
recoverable volumes should also be estimated by including a range of
recovery factors.
Based on the Prospect evaluations described above, Operator should develop
a drilling prioritization schedule, together with recommended drilling
locations. Operator should make any recommendations they deem necessary
to reduce the risk of the prospects.
An industry standard seismic interpretation workflow has been provided for the analysis of
an exploration block. Operators should follow the workflow above for most exploration
blocks; however, certain geologic and economic considerations or data limitations may
require other approaches to meet their exploration needs. It is recommended that the above
workflow be made available to Operators as a reference for an acceptable workflow to
evaluate most Indian exploration blocks; however, certain details related to risk analysis,
resource calculation and certain company proprietary methods, although essential to the
exploration process and useful to clarify interpretation results, may be excluded or
generalized for meetings and reports outside the company.
1.4.3 References
1. Alistair R. Brown, Interpretation of Three-Dimensional Seismic Data, AAPG Memoir 42,
7th Edition.
2. Peter R. Rose, Risk Analysis and Management of Petroleum Exploration Ventures, AAPG
Methods in Exploration Series, No. 12.
3. Russel K. Davis and James W. Handschy, AAPG Bulletin Special Issue CD-Fault Seals,
Digital Version of AAPG Theme Issue on CD-ROM.
4. Leslie B. Magoon and Wallace G. Dow, The Petroleum System from Source to Trap, Digital
Reprint of AAPG Memoir 60.
5. Davis, R.K., An, D.A. Medwedeff, & D. Yarwood. 1999, Fault seal analysis, offshore
Myanmar: A case study. AAPG Hedberg Conference Special Volume, 1999.
Acceleration is the measure of gravity expressed as mass dependent term. At the Earth’s surface,
the gravitational acceleration ranges from about 9.83 meter per second squared (ms-2) at the poles
to 9.77 ms-2 at the Equator.
Units used in gravity survey are:
Micrometer per second squared (µms-2) = 10-6 ms-2 (the SI units)
Milligal (mgal) = 10-3 cm s-2 = 10-5 ms-2 = 10 µms-2 (the traditional CGS unit)
Gravity unit (gu) = 1 µms-2 (the old American measure = 1 meter scale division)
Microgal (µgal) = 10-8 ms-2 = 0.01 µms-2 (often used for absolute measurements)
Newton meter per kilogram (Nm.kg-1) = 1 ms-2 (an alternative form of units)
Gravity is a useful tool for investigating deep tectonic structures. It is used for outlining
sedimentary basins, rifts, faults, dikes, or sills, granitic plutons, regolith drainage patterns, or
kimberlite pipes. A surveyor should first decide what he is looking for, and then design the gravity
survey accordingly.
Gravity can help in mapping subsurface geologic structures where the rocks have significant
density contrasts. Gravity surveying is only useful if the subsurface geological structure involves
bodies of different density. The density contrast between the rock bodies must be high enough to
give gravity anomaly higher than the background noise recorded in the survey. Gravity will not be
the best tool for the job if the differences in magnetization or susceptibility are more characteristic
of the rock bodies than the density changes.
The geologic structures may vary in density in the direction of the measurements; flat lying strata
of constant thickness will not give any changes in the anomaly at the Earth’s surface. Also, a
complicated geological structure at depth may not give a signal at the surface that can be resolved
into separate anomalies. In these cases, a seismic survey will be more effective.
The optimum observation spacing for the gravity survey will be determined based on the size and
depth the bodies the surveyor is looking for. For shallow bodies, an observation spacing may equal
to the dimension (in the measurement direction) of the body or twice the dimension for deeper
bodies will detect the existence of the body but not define its shape. In order to get any reasonable
idea about the shape of the body, observations should exceed the dimensions of the body.
If the Operator is interested in structures of dimensions less than the spacing of the existing gravity
coverage in the area, then the Operator should see some evidence of these bodies in the existing
anomaly pattern. However, if the structures have no significant density contrast, the anomaly
pattern will be featureless. In performing a gravity survey, it is important to look at the existing
data and use that in the decision process and survey planning.
All of the following parameters are considered when planning a gravity survey. Careful pre-
planning can avoid significant issues when executing the survey in the field.
o Orientation
In case of existing subsurface structure (e.g., dike) with known strike
direction, designing gravity survey at 30/60 degrees to the strike direction of
the geology can often provide more information than one oriented at 90
degrees. However it should be decided on basis of available geological
information during planning stage.
o Density/Spacing
In regional surveys, observation density or station spacing is often calculated
from the area to be covered divided by the number of stations that can be
afforded within the budget. When planning the station spacing, the Operator
should consider the existing anomaly pattern in conjunction with the known
geology. Using this information and, if available, the aeromagnetic
anomalies a series of polygons can be constructed to delimit areas of higher
and lower desired station density. In areas of long linear features, the
operators may consider anisotropic spacing (e.g. 2 x 1km) with the closer
spacing aligned across the features. If no existing or indicative gravity data
is available an evenly spaced coverage should be surveyed first, followed by
targeted in-fill based on the results of this even coverage.
o Regular grid or opportunity (along roads)
In some parts of the country a regular grid of observations will necessitate
the use of a helicopter for transporting the equipment to enable timely
completion of the survey; this will increase the cost by 50 to 100% compared
with road vehicle gravity surveys. In urban areas and farming areas, regular
grids of 1, 2 or 4 km can be achieved by utilizing road transport.
o Effectiveness of detailed traverses
Detailed traverses give useful information for interpreting extensive linear
features but are of limited use in constructing a reliable gridded surface of
an area. For planning a regional gravity survey of an area, the coverage
should be as regularly spaced as possible in all directions.
o Station selection
The aim of choosing the position of the gravity station carefully is to avoid
the reading being influenced by physical effects that are difficult to quantify.
o In areas of significant local elevation changes
The standard formulae for the calculation of simple gravity anomalies
assume a flat earth surface at the observation point. Any deviation from a
Soft sand, loose rock or mud not providing a stable footing for the
meter
Access to the site not being granted or the site being dangerous
In pre-planning the survey these issues can be identified by the use of
satellite imagery such as Google Earth, or topographic maps that are readily
available.
o City Gravity surveys
There are a number of terrain effects that are not immediately obvious. These
terrain effects can be induced by construction in cities, towns, airports or
mines. Below are points that need to be considered:
locations. The apparatus is designed in such a way that nearly all the
extraneous forces will cancel out in the comparison of the two (or more)
observations and the output will be a gravity gradient tensor (gradient
vector). The gradients are useful, they are of high frequency response
sensors of the geology, but for quantitative modeling, a good ground gravity
survey of the area is required to provide the ground constraint.
Airborne gravity has advantages and disadvantages over other methods.
These advantages and disadvantages are shown below:
Advantages Disadvantages
o Ship - submarine
Seaborne gravity surveys have lesser stability problems than airborne
gravity surveys are. The movements of deep water is slower and more
predictable than air currents. Large ships will not be highly affected by chop
and swell on a calm day. Gravity surveying in rough weather will give poor
results.
o Vehicle - car, 4WD, quadbike, motorbike
Conducting conventional gravity surveys require a wheeled vehicle to
transport the Operator and equipment between the observation sites. The
gravity meter is lifted out of its box at the observation site and placed on the
ground or a base-plate and the meter is leveled and read (optically or
digitally). Standard vehicles are used in built up areas. But on rough tracks,
along fence lines or across paddocks, 4WD vehicles are used. Quadbikes are
useful in densely timbered or scrubby areas where turning ability and vehicle
weight are important. And two wheel motorbikes may be convenient along
traverse lines. Gravity meters must be protected from bumps and vibration
as much as possible.
o Helicopter - Heligrav
Helicopters are the most effective (but more expensive) method of transport
in remote areas. The Scintrex Heligrav system is a self-leveling digital
reading gravity meter. The attached tripod is suspended by cable from a
helicopter. After the system is carefully lowered onto the ground, the
helicopter hovers while the reading is made. The data flows between the
helicopter and the meter through an umbilical cord attached to the cable.
Equipment
o Gravity equipment
The three main classes of gravity measuring instruments:
o Positioning equipment
Positions and particularly heights had been key factors in calculating
accurate gravity anomalies. Modern survey instruments should be used for
positioning the more detailed gravity surveys.
o Pressure based height instruments
Atmospheric pressure decreases with altitude, so pressure measurements can
be used to calculate elevation. A rough estimate of the pressure decrease is
1 millibar for each 8.7 meter increase in altitude. Accurate height differences
can be measured in a local area (within the same pressure regime as the base)
if base pressure variations are recorded, the weather pattern is stable and
repeat readings are made at the base and selected field stations during the
loop. The height difference network can then be tied into the Height Datum
at one or more benchmarks. Pressure measuring apparatus that have been
used in gravity surveys are altimeters, precision micro-barometers and
digital barometers.
o Global positioning system receivers
The introduction of the Global Positioning System (GPS) in the late 1980s
enabled gravity to take its place as a precision tool in mapping the fine detail
of crustal structure. The GPS receiver monitors time encoded signals being
broadcast by a constellation of GPS satellites orbiting the Earth, from 3 or
more of these signals the position of the receiver can be calculated in
reference to the center of the Geoid. The position values are referred to as
the geocentric coordinates. Differential GPS (DGPS) is the standard method
deployed for surveying. In DGPS all of the GPS readings for each site are
tied back to known base stations established at the start of the survey. These
stations are normally tied to known benchmarks or new benchmarks are
created and tied into an existing network.
Positioning
o Early Gravity surveys use plane table and theodolite for positioning. Working with
these types of tools, the surveyors would exert tremendous amounts of effort to
cover small areas with less accuracy.
o GPS system is widely used in gravity surveying where it has greatly reduced the
cost of providing accurate positions and heights. Commercial GPS receivers can be
single frequency or dual frequency. The accuracy of a position obtained with a
single frequency receiver is about 7m horizontal and 12m vertical compared with
about 5m horizontal and 8m vertical accuracy for a dual frequency receiver.
Obviously this vertical accuracy is insufficient for gravity surveying but can be
improved by employing differential or relative techniques using two or more
receivers. Differential GPS can work in a simple way where one receiver is set up
over a known point, the base, while another receiver, the rover, occupies unknown
points. Corrections may need to be applied to the GPS positions. Accuracy of DGPS
is in millimeters.
o The level of accuracy required in the determination of gravity station positions is
dependent on the type of gravity survey and the size of the anomalies that are
expected to be detected. An error of 10 cm in the height of a station would result in
an error of about 0.3 µms-2. Errors of this magnitude are acceptable in regional
gravity surveys with station spacing one or more kilometers, but for more detailed
surveys the height of the gravity station needs to be determined more accurately.
dropped off at the second station. The transport then returns to the first
station and transports the first crew to the third station, then the second crew
to the fourth station and so on. This method of leapfrogging is particularly
efficient when each crew needs to spend a significant length of time at each
station.
o Designing a robust network
A gravity survey network is a series of interlocking closed loops of gravity
observations. The design of the gravity survey loop structure, the bases, the
repeat and tie stations is critical in enabling accurate station values to be
computed with confidence. An example of gravity loop network is shown in
the figure below.
(From:http://www.ultramag.com/Downloads/Gravity/AGSO_Gravity_Best
_Practice.pdf)
executing gravity surveys in the type of terrain that the proposed survey will be
conducted. Companies with only marine experience may not be a good choice to do
a gravity survey on an onshore block.
o Equipment must be calibrated and properly maintained. Current surveys will in
nearly all cases be conducted using GPS for positioning and altitude calibration.
When merging existing and new survey areas there must be an overlap that allows
for the datasets to be properly tied and any tidal effects or elevation differences due
to different surveying techniques must be addressed.
Advantages Disadvantages
Survey Type
Gradio-metry
Land Based
Ship-borne
Submarine
Helicopter
Borehole
Airborne
Airborne
Satellite
Gravity
Gravity
Gravity
Gravity
Limitations
Resolution
Reservoir
Formation
Geological Structures
Basin Scale
Estimated Depth of 1-10 10 - 5000 10 - 5000 m 500 - 10 - 5000 1000 - 1000 - 2000 -
investigation meters m* * 5000 m * m* 10000 m 10000 m 20000 m
Sensitive to
Well Casing
Survey Duration - Diurnal
variations
Height of instrument
Topographic variations in
survey area (requires terrain
corrections)
Drift (spring tension)
Primary Use
Reservoir Monitoring
Subsurface mapping
Prospect Scale
Regional Scale
Basin Scale
* Depth of investigation is dependent on the length of a profile or area covered by the survey
Potential field methods are most effective when the geologic bodies being investigated
demonstrate significant contrast in a property that the technology is able to detect. Gravity
data reacts to differences in formation density, Induced Polarization reacts to changes in
conductivity, and Magnetics reacts to differences in magnetic susceptibility of the rocks.
These examples are a subset of the range of potential field methods and the correct method
must be identified based on the expected or modeled differences in an area. Acquiring data
using one of these methods requires an understanding of the wavelength of the phenomena
and the sampling required to properly measure and model the response.
Gravity and Magnetic surveys are primarily used for basin scale interpretation. They can be
helpful in defining the presence or absence of geological features that have distinctive
density or magnetic potential when contrasted to the surrounding medium. The different
gravity survey types have their own set of challenges and selecting the correct method for
the identified project should consider the limitations of the method. Gravity surveys may
be useful for defining depth to basement in areas where other techniques have ambiguous
results or for defining general basin shapes. Gravity data is also useful for identification of
low density lenses such as salt to verify whether an anomalous zone may be due to a salt
lens versus a volcanic intrusion. Geological and Geophysical staff in the Production Sharing
Contractor’s staff must determine the incremental value of the potential field data and how
it will be integrated into their overall evaluation of the contract area. Recent advancements
in GPS positioning and gravity and gradiometer equipment have improved the resolution
and accuracy of airborne methods such as helicopter and fixed wing platforms to be nearly
comparable to land acquisition with some notable advantages in uniform coverage,
increased accessibility and data processing of more uniformly sampled data. It is
recommended that the Operator use the most appropriate and efficient method to satisfy
their objectives for the gravity surveys.
Production Sharing Contract Operators should use qualified contractors in the conduct of
gravity and magnetic surveys. These contractors will be knowledgeable of local issues and
can integrate new data into existing datasets. Likewise, constraints on the use of the
instruments, collection, processing and interpretation of the results enforced by
governmental institutions must be considered and a reliable contractor will be informed of
any limitations.
Where base networks are available and data is readily available from governmental agencies
these networks should be integrated into the gravity or magnetics surveys to ensure
consistency between all surveys. When integrating existing gravity data into new surveys,
the positioning accuracy must be considered. Older surveys collected using Plane Table
mapping techniques have a different level of accuracy for their positioning and elevations,
therefore those locations may need to be weighted differently than data acquired using a
DGPS method.
Quality Assurance of potential field surveys is important. Third party consultants or internal
company specialists with expertise in the potential field method should be involved in the
planning and execution of any survey. These experts will ensure appropriate technology
and equipment are used to meet the demands of the survey as designed. Consultants or
contractors who specialize in the field as a third party to ensure proper field methods are
used are an important part of any survey.
1.5.3 References
1. Forrsberg A. and Olesen A. Broad-band gravity field mapping by airborne gravity and
GOCE. DANISH NATIONAL SPACE CENTER.
2. Murrey, A.S. and Tracey R.M. 2000. Best practice in Gravity Surveying. Australian
Geological Survey Organization.
3. Nabifhian, M.N, Ander, M.E., Grauch, V.J.S., Hansen, R. O., LaFehr, T.R., Li, Y., Pearson,
W.C., Peirce, J.W., Philips, J.D., and M.E. The Historical Development of Gravity Methods
in Exploration.
Outcrop sampling
An offshore geochemical exploration program can be much more complex requiring program
design and consulting. Sampling can include vibro-coring and drilling programs, piston/gravity
core sample collection, bottom water sampling, and onboard sample processing. Onboard testing
and analysis can include sediment extract and headspace gas analysis, as well as “sniffer” methods
using a sonde a few meters above the bottom to survey seeps by traversing the bottom by selected
grid patterns. Marine programs are obviously more expensive and time intensive but provide data
from different environments.
Borehole geochemical sampling consists of openhole percussion sidewall sampling at
predetermined sample spacing (shots per foot) or full core retrieval. Sampling formation gases
during drilling at “shows” as well as utilizing special analytical methods such as special core
analysis (SCAL) provide valuable information allowing for analysis of source/source and
source/oil correlation data. Sampling gases to be used in “Rock Eval” analysis provides information
on gas versus oil prone kerogen and hydrocarbon maturity.
In gathering geochemical samples for head-space gas analysis the samples should be placed
in sealed containers as soon as possible and the container remains closed until the analysis
is to be performed.
Analytical procedures marked on the flowchart with an “IS” require the use of an internal
standard. Three NGS standard samples are available and are identified as:
o THE NORWEGIAN GEOCHEMICAL STANDARD SVALBARD ROCK 1 (NGS
SR-1)
o THE NORWEGIAN GEOCHEMICAL STANDARD JET ROCK 1 (NGS JR-1)
o THE NORWEGIAN GEOCHEMICAL STANDARD NORTH SEA OIL 1 (NGS
NSO-1)
It should be made clear at the beginning of the analytical flowchart that only “canned
cuttings” can be used for headspace gas analysis. All other types of “rock samples” are
washed to remove contaminants and then crushed to provide “picked cuttings” for Rock
Eval/Solvent Extraction analysis. Canned cuttings are also treated in the same way for Rock
Eval/Solvent Extraction analysis.
Standard sample documentation as well as reference values for the NGS samples is based
on analyses carried out according to the Norwegian Industry Guide to Organic Geochemical
Analyses, third edition(NIGOGA) (Patience et al. 1993).
o Analysis Guide
The analytical procedures above assume wells were drilled with water-based
mud. The use of oil or synthetic-based mud may require modified sample
treatment depending on client requirements. Norwegian Geochemical
Standard Samples (NGS) are available through the Norwegian Petroleum
Directorate to be used as internal standards for Geochemical analysis and
reporting “permissible ranges” and “most likely values.” A consistent format
was introduced for all analysis descriptions for ease of use and centralized
reporting. The Reporting Guide now contains only the general rules for
reporting as given below.
o Reporting Guide (Principal Rules and Remarks)
The aim of a standard geochemical report is to present and describe the data
obtained by the various analyses. The extent of detailed interpretation – in
the form of both text and figures – should be agreed upon by customer and
Service Company.
As a general principle, all results must be provided in digital form, in
addition to the written report. Unless specified otherwise, the requirements
stated below therefore apply to both the written report and the digital data
transfer.
If any analyses are not carried out in accordance with this Guide, this must
be noted.
If results cannot be obtained from an analysis, or if the obtained results are
unreliable or doubtful, this must be noted and the reason should be
mentioned.
Wherever the Guide requires control analyses, the results from these must
be reported, separately from the “normal” analyses. The tables must contain
all variables used as quality criteria (which may differ from those to be
reported for the “normal” analyses). They must also include the name(s) of
the control sample(s) and should contain the most likely values and
permissible ranges quoted in the NIGOGA.
The sample type must be given. It must be clear if bulk or picked cuttings
were used.
Both top and bottom depth must be reported for cutting, drill stem test and
production test samples. Measured depth relative to Rotary Kelly Bushing
(MD RKB) must always be reported, and it must be stated whether this is
driller’s or logger’s depth. The customer must make this information
available to the service company.
All tables and figures should be mentioned in the text.
Any nomenclature (for peaks, ratios, kerogen constituents etc.) and units of
measure stated in the NIGOGA must be followed, unless items (e.g.
compounds, ratios) are reported which are not mentioned in this Guide.
All terms (codes, abbreviations, compound names) and units of measure that
are necessary for the understanding of the report text, the figures or tables
and that are not defined or specified in this Guide must be explained. This
information can conveniently be collected in a separate table (list of terms)
which has to be included also in the electronic data transfer.
The unit of measure must be given for each reported variable. “Implicit” or
“self-explanatory” units of measure do not exist. Incomplete concentration
units such as “%”, “ppm”, “ppb” etc. are not acceptable, as they neither tell
which properties were determined (e.g. volume, weight, peak area, peak
height) nor to which variable the values were normalized (e.g. sum of
recorded peak areas, sample weight, sample volume). When concentrations
are determined from GC or GC-MS peak data, it must be clearly stated
whether these are based on peak areas or peak heights. When peak ratios are
reported, the formula must be given, and it must always be stated whether
the ratios are based on areas or heights or concentrations. If they are based
on concentration, it must be stated whether the concentrations ultimately are
based on peak heights or areas.
Geochemical analysis of data from both wells and surface sampling is an important step in
the exploration evaluation of any area. The procedures outlined above are provided as a
reference to the methodology documented by NIGOGA and is accepted worldwide. Use of
this methodology will ensure consistency in the comparison of source rock potential on a
global scale and is therefore appropriate for application in all areas. The recommendation
is to follow the Best Practices as outlined.
1.6.3 References
1. The Norwegian Petroleum Directorate 1995: Provisions relating to digital transmission of
geological and reservoir technical data in connection with the final report. (Drilling
regulations, Section 12). The Norwegian Petroleum Directorate, November 1995. YA-061.
ISBN 82-7257-476-4. [Therein: Appendix 6 - Specification of transfer format for
geochemical data (GC-NPD-95 version 1.0, Dictionary GC-DIC-V1); NB! regularly
updated].
2. Dahlgren, S., Hanesand, T., Mills, N., Patience, R., Brekke, T., Sinding-Larsen, R. 1998 a:
Norwegian Geochemical Standards Newsletter vol. 1, Norwegian Geochemical Standard
samples: Svalbard Rock – 1 (NGS SR-1). The Norwegian Petroleum Directorate,
Stavanger, Norway.
3. Dahlgren, S., Hanesand, T., Mills, N., Patience, R., Brekke, T., Sinding-Larsen, R. 1998 b:
Norwegian Geochemical Standards Newsletter vol. 2, Norwegian Geochemical Standard
samples: Jet Rock – 1 (NGS JR-1). The Norwegian Petroleum Directorate, Stavanger,
Norway.
4. Dahlgren, S., Hanesand, T., Mills, N., Patience, R., Brekke, T., Sinding-Larsen, R. 1998 c:
Norwegian Geochemical Standards Newsletter vol. 3, Norwegian Geochemical Standard
samples: North Sea Oil – 1 (NGS NSO-1). The Norwegian Petroleum Directorate,
Stavanger, Norway.
5. Patience, R. L. (Statoil), Pedersen, V.B. (Saga Petroleum), Hanesand, T. (Norsk Hydro),
Weiss, H. M. (SINTEF Petroleum Research, former IKU Petroleum Research), Feriday, I.
(Geolab Nor), and Nyland, B. (Norwegian Petroleum Directorate), The Norwegian Industry
Guide to Organic Geochemical Analyses, Third Edition (1993)
6. Weiss, H.M., Wilhelms, A., Mills, N., Scotchmer, J., Hall, P.B., Lind, K. and Brekke, T.
(2000): NIGOGA - The Norwegian Industry Guide to Organic Geochemical Analyses
[online]. Edition 4.0 Published by Norsk Hydro, Statoil, Geolab Nor, SINTEF Petroleum
Research and the Norwegian Petroleum Directorate. 102 pp. Available from World Wide
Web: http://www.npd.no/engelsk/nigoga/default.htm
Cutting samples can also be used for micropaleontology (tests of ancient plantonic and benthonic
organisms) and palynology (study of primarily spores and pollen and other organic microfossils).
The result of these studies is essential for understanding the biostratigraphy and age of the different
formations in the borehole, which will result in better correlation of age of deposition with offset
wells and environment of deposition (EOD) which can be valuable for predicting potential reservoir
distribution.
The primary collection point for well cuttings is the shale-shaker. Other collection points are the
possum belly and desander/desilter. Possum belly sample collection is thought to preserve larger
cutting such as sandstones or conglomerates. While the desander/desilter sample collection is good
for unconsolidated samples. The sampling requirements for the collection of cuttings varies in the
industry, and is generally determined at the discretion of the operator, also considering any
requirements by the government or local administrations.
Samples are collected and either bagged wet or dried for storage and later analysis. Samples are
analyzed at the drilling site to determine the formation being drilled and fluid content. Samples
should be collected by the mudlogging team to insure that it is done properly.
For sedimentological samples, the best method to supplement the cuttings are side wall cores and
cores. In most instances cuttings do not provide a sample of the consolidated rock, which is better
for sedimentological studies. Side wall cores are taken with a percussion or rotary drilling method
depending on the consolidation of the rock in the wellbore. Side wall cores are generally around
2.5 cm in diameter and 6.25 in length depending on the rock and method of acquiring these cores.
Sidewall cores provide a good snapshot of the lithology and thin sections can be used for
sedimentological study. Conventional cores are 11.43 cm in diameter and can be cut in drill pipe
lengths (about 10 m) for hundreds of meters. Conventional cores provide the best sample for
sedimentological study. Both of these core types can be used for other reservoir and rock properties
studies as well. Sidewall cores are generally taken by a wireline tool after all logging runs have
been made. Conventional cores are taken while drilling and require a swap out of the bottomhole
assembly and are more costly and time consuming.
For exploration wells, the following would be considered a standard good practice:
o For surface-hole sections, 10m cuttings samples are collected.
o For intermediate to target-hole sections, 5m cuttings samples are collected.
o Sampling rate can be increased to 1m samples through a zone of interest. If it is
necessary to collect samples at this rate, drill rates should be slowed to ensure
accurate sampling or stop drilling and a “bottoms up” sample can be collected.
o Paleontological and Palynology samples are commonly collected every 10m
interval.
For development wells, the following would be considered a standard good practice:
o For surface-hole sections, cuttings samples are collected at 10-15 m interval.
o For intermediate to production-hole sections, cuttings samples are collected at 10 m
interval.
o Depending on production zone, sampling rate can be increased to 5m.
o For paleontological and palynology study, samples are commonly collected at every
10m interval.
The geology of a particular well can often dictate when samples are collected. If a zone of
interest lies in between a 5m sample interval for example, the Well Site Geologist or
geology team can request the mudloggers “catch” a sample from a specific depth, also
known as a “spot sample.” Reasons for this could be due to:
o A drilling break, or unexpected change in rate-of-penetration (ROP).
o Abrupt or noteworthy MWD/LWD response that may indicate a zone of interest.
o An increase in gas shows or petroleum odor at the shale-shakers.
o If approaching an expected formation top, and a lithology confirmation is necessary.
If the Well Site Geologist identifies any change in drilling or gas parameters they deem to
be worthy of a spot sample, it is at their discretion to request one.
Once a sampling rate is agreed upon, the operator will specify the amount of cuttings to be
archived. In exploration wells, general practice calls for:
o At least three sets of washed, dried and bagged cuttings samples are to be labeled
and boxed by mudlogging personnel – one set for any government requirements,
and two for the operator’s research purposes.
o At least one set of unwashed, wet samples (still containing drilling mud and
potentially formation gas or oil) are bagged to potentially be used later to analyze
any formation fluids or gases.
Development wells may only require washed, dried samples, if it is decided that sufficient
subsurface data and/or cuttings already exist.
Accurate labeling of samples is extremely important. All samples must be depth corrected
by using a “lagging” method, i.e., using calcium carbide in the wellbore and the resulting
acetylene gas as a tracer or determining the bit to surface lag time of samples coming from
the drill bit or both. The Well Site Geologist will closely monitor the collection and labeling
of cuttings by the mudlogging personnel. All containment supplies will be provided by the
mudlogging contractor, who should only use supplies intended for the purpose of containing
drill-cuttings.
o For washed, dried cuttings, samples will be contained within a small paper envelope
or cloth bag – both of which must clearly state the depth-range for that particular
sample, the company/operator name, and the well-name.
o Wet samples are collected at the shale-shakers in a plastic bag previously labeled
with the well-name and depth interval. This plastic bag is then contained within a
cloth or paper bag that also notes the company/operator, well-name, and depth
interval for the sample.
All bagged samples are then neatly placed into their own respective sturdy cardboard boxes
that clearly label the depth-range of the samples within, all relevant company information,
the well-name, and any shipping instructions.
Micropaleontological cutting samples are dried and treated, sidewall cores and conventional
cores can also be used for analysis. Note that the techniques used for concentrating
micropaleontological samples are in general destructive, i.e. only the particular microfossils
are preserved.
These samples are used in a lab and treated depending on the composition and size of the
microfossils which are to be studied.
type). The best way to preserve sidewall cores from physical damage is to use rotary
sidewall cores rather than percussion, this should be consider if the rock is very
brittle or unconsolidated.
Typical handling operation for sidewall cores is to inspect the gun to see if all bullets were
fired. Next cores are extracted and described then wrapped in plastic wrap or aluminum foil
and then placed in glass jars or ProtecCore sleeves as soon as possible. Then the sample is
labeled with depth, well name, location and operator. Sample description is on a separate
paper but accompanies the sample to the lab. Sidewall cores can also be frozen, jacketed in
lead sheets or left in the bullets from the actual sidewall coring operations depending on the
condition of the rock.
Typical handling operation for conventional cores is to lay down the core barrel, cut into 1
meter sections, and inspect and describe as quickly and carefully as possible. Description
should be recorded in a core log in graphical format noting the thickness of a lithologic
zone, grain size changes, sedimentary structures, fossils, diagenetic features, lithology,
nature of contacts between different lithological zones, oil staining, fracturing, and visible
porosity as well as other attributes which are deemed important by the operator. After
description, the core is generally wrapped in plastic wrap or foil (ProtecCore) and coated
with wax for shipping. Other methods for sealing is to place in metal cans which will
preserve reservoir fluid, fractured, and unconsolidated sediments, sealing in tubes which
will preserve pressure and reservoir fluid, or freezing in dry ice which will preserve
unconsolidated sediments. Core preservation should take care to not cause dehydration and
salt precipitation, oxidation, redistribution of fluids, evaporation and condensation,
expansion of shales, and bacterial growth.
Core and sidewall coring samples should be sent to a lab for slabbing, thin section
preparation and staining for lithology. These processed samples can then be used for
sedimentological interpretations, such as overall description, lithologic content, contacts,
grain size, environment of deposition, porosity, and permeability. Geochemical analysis
(see Section1.6) can also be used for sedimentological interpretations.
Sidewall and conventional cores are recommended for exploratory wells. Sidewall cores
locations should be picked from the logs for the purpose of study of reservoir fluid,
lithology, or organic content. Sedimentological studies of side wall & conventional cores
will help determine reservoir properties and be useful in mapping reservoir facies .
Conventional or specialized cores are also recommended for development wells for
reservoir characterization.
1.7.3 References
1. Brasier, M.D. (1980), Microfossils. Chapman and Hall publishers. ISBN 0-412-44570-0
2. Feldmann, R., M., Chapman, R., E., Hannibal, J., T., eds., 1989, Paleotechniques:
Paleontological Society Special Publication 4, 358 p. p.
3. Jansonius, J; D.C. McGregor (1996). "Introduction, Palynology: Principles and
Applications". AASP Foundation 1: 1–10.
4. Keelan, D. K., and D. A. T. Donohue, 1985, Core analysis: Boston, MA, IHRDC Video
Library for Exploration and Production Specialists, n. PE405, 186 p.
5. Kummel, B., Raup, D., eds., 1965, Handbook of Paleontological Techniques: San
Francisco, W., H. Freeman, 851
6. Traverse, A. (1988), Paleopalynology. Unwin Hyman ISBN 0-04-561001-0
7. Traeger and Harding (1987). The Wellbore Sampling Workshop.
The electrical current flows from the tool into formation through
borehole. Electrode arrays on either side of the source electrode force
the measurement current into a horizontal disk-shaped pattern
around the borehole. Formation resistivity is determined by
monitoring the amount of current flowing from the tool. (Krygowski,
2003)
The lithology or the nature of formation can be determined by the following prior
to any petro-physical analysis:
Mud logging
Geology
Integrated well log analysis in the nearby wells
o Calculating Porosity
Sonic
Conventional sonic tools measure the reciprocal of the velocity of the
compressional wave (Bassiouni, 1994). A high frequency acoustic pulse
from a transmitter is detected at two or more receivers. The time of the first
detection of the transmitted pulse at each receiver is processed to produce an
interval transit time. Compensated tools are used to minimize the effects of
borehole sizes. (Krygowski, 2003)
Neutron
High energy neutrons (emitting source: Americium-Beryllium), slowed by
formation nuclei, are detected by 2 detectors that generates count rates. The
count rates are inversely proportional to hydrogen in the formation. By
assuming that all the hydrogen resides in the pore spaces of the formation,
the hydrogen index can be related to formation porosity (Krygowski, 2003).
Cased hole and production well logs: service companies offer wireline services in cased
hole section that generates the parameters discussed above. Particular production logging
is run to meet specific objectives as mentioned below:
o Fluid tracking in formation: temperature surveys, mechanical flowmeter surveys,
borehole fluid density or fluid capacitance
o Cement job quality: temperature log, unfocussed gamma ray log and regular bond
log
o Zonal isolation (cement channeling): cement bond logs, acoustic noise, temperature,
radioactive tracer, neutron-activation logs
o Monitoring fluid contacts and recompletion zones: neutron, pulsed neutron and
spectral logs
o Geological objectives
Lithologic information
Rock type
Depositional environment
Pore type
Mineralogy/geochemistry
Geologic maps
Fracture orientation
Permeability/porosity correlation
Relative permeability
Capillary pressure data
Steady state and unsteady state
Wettability determination
Archie Exponents – a, m, n
NMR Core Analysis
SEM (Scanning Electron Microscopy) and EDS (Energy-dispersive X-ray
spectroscopy)
Asphaltene precipitation
Data for refining log calculations
Electrical properties
Grain density
Reserves estimate:
- Porosity
- Fluid saturations
o Drilling and completions
Fluid/formation compatibility studies:
Resistivity/conductivity/Induction
Neutron
Bulk density
Photoelectric
Density correction
Sonic or Acoustic
Equivalent circulation density
Temperature
Interpreted logs: porosity, water resistivity and water saturation
Borehole Image logs
Nuclear Magnetic Resonance (data mainly includes quality control curves,
computed curves and T2 bin distributions)
Elemental spectroscopy
Cement Bond Logs (CBL) and Casing Colar Locator (CCL)
Production Logging Tool (PLT) data
Vertical Seismic Profiles (VSP)/ Check shot
o Acquisition and detailed analysis of sidewall cores, rotary sidewall and/or
conventional cores
o Geochemical analysis
o Preparation of Completion Log at end of well – includes Lithology Log data plus
Open Hole or LWD log curves, gas measurements, geological formation tops
o Preparation of End of Well Report(s): one prepared by Well Site Geologist and one
by Drilling Department
o Complete well details, analysis of well logs, testing recommendation and Final
Evaluation Report by Geologist/Petrophysicist
o Formation testing program that include any logging tool that collects pressure data
and/or fluid samples from the borehole. The data acquisition includes log images,
pressure gradient plots and preliminary sample analysis. It may also include the fluid
related analysis like PVT analysis.
Caliper
Lithology
Mineralogy
Q Gamma Ray Shale volume
u
Clay content
a
Spontaneous Water resistivity
li
t potential
Porosity
y Water saturation
c Resistivity/
h Porosity Permeability
Induction
e
c Sonic NTG/Reserve Capillary
k pressure
Neutron BVW
Output Validation
Well log analysis
o The first step is to check the log quality that is received from the service companies.
The practice is to check the Caliper (for open hole) or cement bond log (Cased hole)
or Neutron Density data for any sign for deterioration in data. After carefully
identifying the quality issues and applying environmental corrections, the steps
below are performed.
Shale volume
o Various empirical correlations are available to estimate shale volume using GR. The
shale volume is function of gamma ray index that is estimated using the following
correlations:
TOC
o The Total Organic Content (TOC), is the amount of organic carbon content
estimated either in laboratory or logs. The amount of organic carbon indicated by
the amount of Kerogen is an important indicator of hydrocarbon presence especially
in unconventional reservoirs. Kerogens are known to be good sources of
hydrocarbons. TOC is estimated using the following method:
Schmoker (Schmoker & Hester, 1983)
Modified Schmoker (Schmoker, 1994) (Gonzalez, et al., 2013)
DeltaLogR (Passey, Creaney, Kulla, Moretti, & Stroud, 1990)
Uranium (Gonzalez, et al., 2013)
NMR (Gonzalez, et al., 2013)
o Apart from the above techniques, laboratory core measurements are also performed
to estimate total organic content.
Lithology
o The first step of identifying lithology is to determine shale and non-shale intervals
(clean). Then, the following algorithm can be followed:
Dipmeter
o The dip angle and direction of planar surface (such as bedding, fracture, strata, etc.)
required elevation and geographical position of at least 3 points. The tool measures
formation parameters such as resistivity and travel time by means of 3 or more
sensors mounted on caliper arms so as to scan different sides of the borehole wall.
The anomalies/changes in the sensor measurements recorded with relative
displacement, radial and azimuthal positions are used to compute dip relative to the
tool. (Goetz, 1993)
o The parameters are used to determine lamination thickness, contrast, continuity and
frequency in thin shale sand sections, fracture geometry, density and intensity,
mapping, correlation intervals and other structural and stratigraphic applications.
o The dipmeter is presented by arrow or tadpole plot along with the well logs.
Porosity
o Porosity is determined by following the workflow mentioned below. Based on
availability of data, the right set of log curves is used.
In case lithology is known, the work flow can be followed to determine effective porosity (Krygowski, 2003)
o Using two porosity measurements in X-Y crossplot tends to minimize some of the
environmental and lithologic effects that produces better estimates of porosity (and
lithology, in case unknown) than using single porosity as mentioned above. Most of
the cross-plots have similar algorithms as mentioned below (Krygowski, 2003):
o There are numerous ways to estimate formation water resistivity. One of the
techniques is to calculate an apparent water resistivity from the porosity and
uninvaded zone resistivity measurements. The lowest value of the apparent water
resistivity in the porous and permeable zone among all other zones does indicate
actual water resistivity. (Krygowski, 2003) However, there are some assumptions:
The zones have same water resistivity
The lowest value of apparent water resistivity in all zones is the true water
resistivity. The higher values of apparent water resistivity are indicative of
hydrocarbons.
o The other methods are:
Minimum recommended logging details that should be acquired in an exploration well are
as follows:
o Acquisition of Open Hole/Cased Hole wireline Logs and/or LWD and/or MWD
Logs that shall be used to correlate and shall at least enable an interpretation of
lithology and estimation of porosity and water saturation.
o Logging suite in hole sizes of 17 ½” or greater should be at the discretion of the
operator as per requirement and to include Gamma ray, Caliper, Resistivity, Sonic,
Neutron and Density in hole sizes of less than 17 ½”. Sonic and Density may also
be required at in the shallow hole at Operator’s discretion if synthetic seismograms
are needed to tie well markers to the seismic data.
o Collection, bagging and description of drill cutting samples of all rock types from
all geological formations shall commence at a maximum of 10 meter intervals as
soon as return of drilling fluid has been established.
o Preparation of a Lithology Log based on drill cutting sample description by Well
Site Geologist
o Preparation of End of Well Reports by Well Site Geologist and Drilling Department
o Well head information such as name, spud date, mud properties, temperature,
deviation survey of the well (if deviated), start and stop depth, run and bit details,
personnel and data acquisition details.
o Analysis of well logs, testing recommendation and Final Evaluation Report by
designated Geologist/Petrophysicist.
o Formation test logging should be carried out in exploration wells to evaluate
pressure gradient and type of fluids in potential or known formation.
o Fluid samples shall be taken associated with formation testing and logging.
Lithology, porosity, permeability and water saturation are some of the crucial data provided
for geo-modeling. Such parameters can be validated or generated from Core NMR analysis.
Core based NMR provides T2 relaxation cutoffs and permeability relationships for
downhole logging calibration. Apart from that, it helps to determine pore structure and
wettability. NMR analysis on core sample (of any lithology) provides: effective porosity,
BVI and FFI, pore size geometry, pore size distribution, fluid saturation, diffusion
coefficient, permeability models, wetting characteristics and oil viscosity. The above
measurement also helps in evaluating NMR logs if acquired. Due to the cost and time
consuming nature of the analysis, Core NMR analysis is not recommended in all situations.
The method discussed in best practices is generally valid for all clastic reservoirs. For
carbonate and thin shale sand reservoirs, correct matrix parameters should be used along
with the methodology discussed. Also, due to complexity of the reservoirs, low high
resolution and advanced tools are more effective.
Wireline tools in oil based mud drilling fluid are Gamma Ray, Caliper, Sonic, Litho-density
and, instead of Laterolog, Induction tools are preferred.
Cased hole is recommended only when open hole cannot be acquired due to hole / wellbore
instability. However, due to quality and noise issues in case hole logging, open-hole
wireline is recommended to be used wherever possible.
1.8.3 References
1. American Petroleum Institute. (1998). Recommended practices for core analysis.
Washington: API Publishing Services.
2. Archie, G. E. (1942, December). The Electrical Resistivity Log as an Aid in Determining
Some Reservoir Characteristics. Transactions of the AIME, 146(1).
doi:http://dx.doi.org/10.2118/942054-G
3. Arps, J. J. (1953). The Effect of Temperature on the Density and Electrical Resistivity of
Sodium Chloride Solutions. AIME, 198, 327-328.
4. Bassiouni, Z. (1994). Theory, Measurement and Interpretation of well logs. Richardson:
Society of Petroleum Engineers.
5. Clavier, C., Coates, G., & Dumanoir, J. (1984, April). Theoretical and Experimental Bases
for the Dual-Water Model for Interpretation of Shaly Sands. Society of Petroleum
Engineers Journal, 24(2), 153-168. doi:http://dx.doi.org/10.2118/6859-PA
6. Clavier, C., Hoyle, W. R., & Meunier, D. (1971). Quantitative Interpretation of Thermal
Neutron Decay Time Logs: Part I - Fundamentals and Techniques. JPT (June 1971), 743-
755.
7. Gondouin, M., Tixier, M. P., & Simard, G. L. (1957, January). An experimental study on
the Influence of the Chemical Composition of Electrolytes on the SP Curves. AIME.
8. Goetz, J. F. (1993). Dipmeters: Part 4. Wireline Methods: Dipmeter. In D. M. Thompson,
& A. M. Woods, Development Geology Reference Manual (pp. 158-162). American
Association of Petroleum Geologists.
9. Gonzalez, J., Lewis, R., Hemmingway, J., Grau, J., Rylander, E., & Schmitt, R. (2013).
Determination of Formation Organic Carbon Content using a new Neutron_Induced
Gamma Ray Spectroscopy Service That Directly Measures Carbon. 54th Annual Logging
Symposium. New Orleans, Louisiana: SPWLA.
10. Halliburton. (2012). eChartBook. Retrieved from Halliburton eChartBook:
http://echartbook.halliburton.com/eChartBook.aspx
11. Krygowski, D. A. (2003). Guide to Petrophysical Interpretation. Austin: AAPG.
12. Larionov, V. V. (1969). Borehole Radiometry. Nedra, Moskwa.
13. LeCompte, B., & Hursan, G. (2010). Quantifying source rock maturity from Logs: How to
get more than TOC from Delta Log R. SPE Annual Technical Conference and Exhibition.
Florence: Society of Petroleum Engineers.
14. Passey, Q. R., Creaney, S., Kulla, J. B., Moretti, F. J., & Stroud, J. D. (1990). A Practical
Model for Organic Richness from Porosity and Resistivity Logs. AAPG Bulletin, 64(12),
1777-1794.
15. Pickett, G. R. (1966, Nov). A Review of Current Technologies for Determination of Water
saturation from Logs. JPT, 1425-1433.
16. Pickett, G. R. (1973). Pattern Recognition as a Means of Formation Evaluation. 14th Annual
Logging Symposium. Lafayette: SPWLA.
17. Poupon, A., & Leveaux, J. (1971). Evaluation of Water Saturations in Shaly Formations.
12th Annual Logging Symposium. Dallas: SPWLA.
18. Raymer, L. L., Hunt, E. R., & Gardner, J. S. (1980). An Improved Sonic Transit Time-to-
Porosity Transform. 21st Annual Logging Symposium (pp. 1-12). Lafayette: SPWLA.
19. Schlumberger Well Surveying Corporation. (2013). Log Interpretation Chart Book.
Houston: Schlumberger.
20. Schmoker, J. W., & Hester, T. C. (1983). Organic Carbon in Bakken Formation, United
States Portion of Williston Basin. AAPG Bulletin, 67(12), 2165-2174.
21. Simandoux, P. (1963). Measures dielectrique en milieux poreux, application a measure de
saturation en eau, etude des massifs argileaux. Revue de l’institut Francais du
Petrole(Suppliment issue), 193-215.
22. Stieber, S. (1970). Pulsed Neutron Capture Log Evaluation in the Lousiana Gulf coast. 1970
SPE Annual Meeting. Houston: SPE 2961.
23. Waxman, M. H., & Smits, L. M. (1968). Electrical Conductivities in Oil-Bearing Shaly
Sands. Society of Petroleum Engineers Journal, 8 (2), 107-122.
doi:http://dx.doi.org/10.2118/1863-A.
24. Waxman, M. H., & Thomas, E. C. (1974). Electrical Conductivities in Shaly Sands-I. The
Relation between Hydrocarbon Saturation and Resistivity Index; II. The Temperature
Coefficient of Electrical Conductivity. Journal of Petroleum Technology, 26(2), 213-225.
doi:http://dx.doi.org/10.2118/4094-PA.
41. Timur, A., 1982, Open hole well logging, SPE-10037, in International petroleum
conference [Beijing] proceedings: Society of Petroleum Engineers, p. 639-674. Later
published 1982 in condensed form as, Advances in well logging: Journal of Petroleum
Technology.
o Fluid samples shall be taken associated with formation testing and logging.
The minimum well evaluation practices outlined in Best Practices above constitute the basic
level of effort required to fully ascertain the hydrocarbon bearing potential of an exploration
well and should be completed for each well. These data should be encapsulated with the
Final Well Report that is submitted to DGH.
The Well Completion Report (WCR) should include following details also:-
If Bull dozing has been carried out in the well then details of bull dozing i.e. pressure,
quantity, bull dozing depth with previous shoe depth.
1.9.3 References:
1. NTL No. Feb 2010, Notice to lessees and operators of federal oil and gas leases in the outer
continental shelf, Gulf of Mexico OCS region, United States Department of the Interior
Minerals Management Service Gulf of Mexico OCS region.
2. International Business Publications, 2013. USA Norway Oil and Gas Exploration Laws and
Regulations Handbook, Washington D.C.
Construction of geological maps is necessary to define the structure in the subsurface, and
to show the areal extent and variation of reservoir parameters in a hydrocarbon discovery.
These maps can be used in a geological ‘static’ model of any hydrocarbon discovery, and
so maps should be constructed in a way that they can be input into common modeling
software.
Radiometric dating techniques should be used on distinct high gamma ray beds; shales or
tuffaceous beds from volcanic events. The absolute ages should provide time constraints
when correlating.
Biostratigraphy has constraints and should only be used when a sufficient data set is
acquired throughout the entire well. Palynology and paleontological data is typically
restricted to shales and carbonate formations, while sandstones typically have a low
abundance of specimens. Fossil and faunal floras are nonexistent past certain ages so a
variety of biostratigraphic data must be used to obtain a full record. The biostratigraphic
record may be used as a relative age constraint when a sufficient record is collected.
Once an absolute or relative age sequence has been established the interpreter may begin
correlation of the well log suite by recognizing beds of similar well log values, responses,
thicknesses, etc. Correlated formations must have similar fossil and faunal flora or must lie
between similar absolute marker beds.
1.10.3 References
1. Industry experience
Thickness Maps - Two types of thickness maps may be created; an isopach or isochore. It’s
important to distinguish the two from each other. Typically if dip data is available, an
isopach map is created. If dip data is not available, then an isochore map is created. Both
maps should be created when possible, isopach maps will show the true thickness while
isochore maps show vertical thickness.
Porosity Maps - Porosity maps show the porosity distribution for a particular reservoir for
a specific interval. The horizontal and vertical resolution is determined by the interpreter
based upon their needs.
Saturation Maps - Saturation maps show the distribution of fluid saturation for a particular
reservoir at a specific interval. The horizontal and vertical resolution is determined by the
interpreter based upon their needs.
o Net to gross sand percentage map can be constructed by using the entire reservoir
interval as a gross value and the net sand from the cutoff values. This map can also
be useful in field development and environment of deposition interpretations.
Seismic attribute maps can contribute to the contouring and extending the map if
the attribute is shown to have a correlation to sand percentage.
o Another useful map is the product of the porosity*thickness (PhiH map), which
gives the pore volume of the reservoir and can show possible trends to exploit during
development. Seismic attribute maps can contribute to the contouring of this map if
the attribute is shown to have a correlation to porous feet of a reservoir.
o A useful addition is to multiply this pore volume map times saturation, this will give
a map of hydrocarbon pore volume of the reservoir (SoPhiH map). This map can
also indicate areas which can be exploited during primary, secondary or tertiary field
development. Seismic attribute maps can contribute to the contouring and extending
the map if the attribute is shown to have a correlation to hydrocarbon pore volume.
o If there is sufficient data to show a good correlation between porosity and
permeability then permeability maps (k map) can be constructed by multiplying the
porosity map by that correlation algorithm. Sufficient core permeability data is
needed to make the algorithm accurate.
o The product of the permeability and hydrocarbon pore volume maps (kSoPhiH map)
are very useful in planning field development.
Fluid Contacts - There are several types of contacts which need to be determined and
mapped: oil-water, gas-water, oil-gas, oil-down-to, gas-down-to. These contacts are
displayed on a structure map and are indicated by a contour line that is distinguishable from
the other contour lines.
Faults and Other Geological Boundaries - Faults are denoted on structure maps by polygons.
Faults are projected on the structure map where they intersect at that particular depth. The
contours lines must honor the fault by following the basic contouring laws mentioned in the
contouring section below. Wavy lines represent the location where formations or reservoirs
sub crop due to unconformities.
Structure Maps
o Structure maps should be constructed on zones of interest prior to drilling and
should be updated after a well is drilled. The map will show the depth of the
formation top in the mapped area of interest. Map contouring should honor and be
consistent with the formation top picked in well logs.
Thickness Maps
o Thickness maps should not be constructed until after structure maps have been
created and quality checked with formation tops from well logs.
Porosity Maps
o The decision to prepare a separate map on the top of porosity, where the upper
portion of a unit is not productive or is a correlative marker above the actual
reservoir, needs to be made on a reservoir-by-reservoir basis. Depending upon the
geometry of the reservoir and thickness of the zone, the difference in volume
between a map on the top of a correlative marker and a map on the top of porosity
may be too insignificant to warrant additional mapping.
o Top porosity maps are created based off of marker data for the reservoir of interest.
Top porosity maps differ from structure maps in regard to showing the actual
reservoir configuration instead of the overall structure. A marker at the top of the
reservoir is picked off of e-logs. Top porosity maps should only use well data when
sufficient well data is present. If there is poor well control, top porosity maps may
trend structure maps and honor top reservoir markers in existing wells.
Saturation Maps
o Generally, saturation maps use a Sw-height function as best practice. Sw-height
modeling allows spatial distribution of Sw, aerially and vertically. Typically it is
impractical to map Archie inputs and parameters because they may introduce
inadvertent consequences. Sw-height models can be applied to dynamic simulation,
thus maintaining equilibrium with rock properties. Saturation maps may then be
displayed on each of the pay horizon surfaces.
Reservoir Maps
o To be constructed after sufficient wells data is available, i.e., after field discovery
during appraisal and development.
o Net pay maps are essentially thickness maps of the hydrocarbon bearing zones being
produced. A cutoff of resistivity and porosity of the minimum productive zone is
used to as a lower bound for generating thickness values from logs then the values
are contoured. This map is useful for infield development.
o Net sand maps are essentially thickness maps of the potential reservoir and usually
would use all well data available even outside of the known field boundaries. A
cutoff value of gamma ray and porosity can generate the thickness data which would
then be contoured. This map is useful for environment of deposition and can provide
ideas about the more permeable trends in the reservoir.
o Net to gross maps can be constructed for sand or pay. The data is from the log and
uses a predetermined cutoff using gamma ray, porosity or resistivity or a
combination of two or three depending on the net value to be generated. See above
net pay and net sand discussions. The net value is divided by the gross interval of
sand or pay in the logs to give the ratio.
o The Phi-H or reservoir pore volume map is constructed using well log data and an
average porosity value over the reservoir interval. Another way to model these
values is with a geostatistical approach to create the map.
o Once the PhiH and hydrocarbon saturation maps are created then it is only necessary
to multiply the two maps to get the hydrocarbon pore volume (SoPhiH) map.
o A permeability (k) map is created by multiplying the reservoir pore volume map by
an algorithm based on core permeability to core porosity correlation.
o Multiplying the permeability map times the hydrocarbon pore volume map will get
the kSoPhiH map to show the potentially most productive areas of the field.
Fluid Contacts
o Fluid contacts in a discovered hydrocarbon deposit can be mapped in different ways.
Good Industry Practice requires using a combination of methods to determine fluid
contacts, and then to map them on a structure map.
o The methods for determining the contacts are:
Oil and gas down-to depths using electric logs.
Oil and gas down-to depths using electric logs, in particular the resistivity
curves to define the hydrocarbon and water zones. The water zones will
typically have lower resistivity than hydrocarbon zones.
Dynamic Formation Tester pressure measurements can be used to define
zones with oil or gas pressure gradients, which are distinct from pressure
gradients in a water zone.
o Once a contact is determined, it should be represented by a contour on the structure
map.
1.11.3 References
1. Evenick, J.C., 2008, Introduction to Well Logs & Subsurface Maps: Tulsa, PennWell
Corporation, 236 p.
A number of oil industry consulting companies provide volumetric estimation and reserve audits,
and each has an established methodology. The following reviews the methods employed by some
of these companies, from a survey of industry reports.
D&M classifies resources in accordance with the PRMS approved in March 2007 by the Society
of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum
Geologists, and the Society of Petroleum Evaluation Engineers.
RPS
o RPS volumes and risk factors are calculated in accordance with the 2007
SPE/WPC/AAPG/SPEE Petroleum Resource Management System (PRMS).
Estimating the range is undertaken in a probabilistic way (i.e. employing Monte
Carlo simulation), by using a range for each input parameter to derive a range for
the output volumes. Key contributing factors to the overall uncertainty are data
uncertainty (both quantity and quality), interpretation uncertainty and model
uncertainty. Volumetric input parameters, Gross Rock Volume (GRV),
porosity (Ø), net-to-gross ratio (N/G), water saturation (Sw), fluid / gas expansion
factor (Bo or Bg) and recovery factor, are considered separately.
o Volumetric estimates are prepared probabilistically using Logicom’s REP™ Monte
Carlo program.
Gross rock volumes (GRV) are derived using Area / Depth contours defined
by top reservoir surfaces.
The P50 gross reservoir thickness of each target formation is based upon the
penetrated thickness in the well with +/- 10% variability applied to account
for possible thickness variability across the structure.
The maximum mapped closing contour is taken as the P10 input allowing
for mapping uncertainty and possible deeper contacts, but with the
distribution upside clipped at 110% of the P10 value to ensure unrealistic
spill points are excluded. The P90 input is adjusted so that the derived
minimum value on the distribution equaled the smallest justifiable area of
the structure which is often the 4-way dip (i.e. non-fault seal dependent)
closure.
A petrophysical assessment provides the basis for the range of inputs for the
reservoir parameters used in the program REP. For fractured reservoirs dual
porosity (matrix and fracture) systems are predicted. Net to gross ratio (N/G)
ranges for the matrix are based on the RPS petrophysical sensitivities;
whereas for the fracture element N/G was set at 100% as it was assumed that
fracturing could affect the whole of the gross reservoir interval.
Matrix porosity ranges are established petrophysically. Fracture porosity is
assumed to range between 0 and 1% Sw ranges, guided by regional
information, are used for the matrix porosity across all target horizons. More
optimistic (lower) Sw values are applied to the fracture porosity.
Formation volume factors (Bo) are varied according to the hydrocarbon
indications and published details of oils encountered in nearby fields and
discoveries. Bo is assumed to increase with depth as the oil API increases.
o Recovery factors (RF) are applied deterministically. A range of recovery factors for
the matrix pore volume are applied, whereas for open fracture pore volume higher
recovery factors are predicted. Volume weighted recovery factors, for matrix and
fractures, are used to derive the technically recoverable volumes.
o Volumes categorized by RPS as Prospective Resources have an associated
Geological Probability of Success (GPoS).RPS assesses risk by considering both a
Play Risk and a Prospect Risk. When assessing undrilled prospects RPS assigns a
geological Chance of Success (CoS) which represents the likelihood of source rock,
charge, reservoir, trap and seal conspiring to result in a present-day hydrocarbon
accumulation. RPS considers three factors when assessing Play Risk: source,
reservoir, seal and consider four factors when assessing Prospect Risk: trap, seal,
reservoir and charge. The CoS for the Play and Prospect are multiplied together to
give a Geological Probability of Success (GPoS). The result is the chance or
probability of discovering hydrocarbons in sufficient quantity for them to be tested
to surface.
o RPS aggregates Prospective Resources by a statistical consolidation including the
geological probability of success.
o For reserves, a range of reserves are determined deterministically according to
whether a zone was tested, its structure fill-point (LKO vs. spill) and distance from
the discovery well. The terminology used is 1P (Proved; P90), 2P (Probable; 1P+2P;
P50) and 3P (Possible; 1P+2P+3P; P10). The 1P, 2P, and 3P areas are based on
proximity to the discovery well and an assumed structural fill.
Schlumberger
o Each prospect is assessed using the GeoX software, an application that creates a
Monte Carlo simulation of all possible outcomes. The simulation calculates the
prospect’s chance of success (chance that at least one zone will contain enough oil
to be called a “discovery”) and the prospect’s resource uncertainty.
o Volumetric calculations are made using GeoX. For each prospect, the following
assessment workflow is utilized:
Define the appropriate reservoir parameters for each zone.
Estimate resource uncertainty for each individual zone.
Estimate the chance of success for each individual zone.
Aggregate the zones to define the prospect’s resource uncertainty and
chance of success.
Aggregate prospects to define the resource uncertainty and chance of
success for the block or area of interest.
o A prospect’s resource is the recoverable hydrocarbon within the prospect.
Uncertainty refers to the range of possible resource volumes, and their associated
probabilities, that may be contained within a prospect. Risk is the chance of failure:
the probability that a prospect will contain an insignificant resource volume. The
chance of success (COS) is 1 – Risk. A prospect’s chance of success is roughly the
probability that the prospect will contain enough hydrocarbons to be called a
discovery, though not necessarily enough to be economic.
o For an individual reservoir or formation within a prospect (referred to as a zone),
resource uncertainty is a function of parameters such as thickness, column height,
net-to-gross, porosity, recovery factor, and the uncertainty around those individual
parameters. The chance of success for each individual zone is estimated by the
assessment team. For a multiple-zone prospect, both the resource uncertainty and
the chance of success are a result of aggregating the potential zones within the
prospect. The prospect aggregation accounts for the chance that a given zone will
contain oil, the potential oil volumes within each zone, and the number of zones that
may succeed.
o When aggregating the zones within a prospect, the Trap and Charge elements are
assumed to be dependent. In any given realization, a closure (trap) is assumed to be
either present for all zones, or absent for all zones. Likewise, in a given realization,
the source-migration system either charges all zones or fails to charge all zones.
o In order to create a proper aggregation of a multiple-zone prospect, the chance of
success (COS) is estimated for each individual zone. COS is estimated by examining
four geologic elements (trap, seal, reservoir, and charge) and estimating the
probability that each element is present and is adequate to support a volume large
enough to be deemed a discovery (though not necessarily a commercial discovery).
In Schlumberger’s terminology the chance for each element is known as the Chance
of Adequacy. Multiplying the chances of adequacy yields the zone’s chance of
success.
Reserve Estimation
o After a successful exploration well, reserves may be estimated. The reserve
estimation will take into account results from an appraisal work program, and from
a development plan.
o Reserves must satisfy four criteria: they must be discovered, recoverable,
commercial, and remaining based on the development project(s) applied.
o Reserves are further subdivided in accordance with the level of certainty associated
with the estimates and may be sub-classified based on project maturity and/or
characterized by their development and production status.
o To be included in the Reserves class, a project must be sufficiently defined to
establish its commercial viability. There must be a reasonable expectation that all
required internal and external approvals will be forthcoming, and there is evidence
of firm intention to proceed with development within a reasonable timeframe.
o For reserves the range of uncertainty is captured by 1P, 2P, and 3P volumes. The
terminology used is 1P (Proved; P90), 2P (Probable; 1P+2P; P50) and 3P (Possible;
1P+2P+3P; P10).
o The range of reserves can be determined deterministically by using a range of
estimates of structure fill-point or by using polygon areas that vary by the distance
from the discovery well.
o The SPE guidelines as defined in the 2007 Petroleum Resources Management
System and the 2011 Guidelines for Application of the Petroleum Resources
Management System are very succinct in their definition of the resource and reserve
calculation and allocation process and should be followed for consistency with all
parties.
1.12.3 References
1. Oil industry reports on resource estimation.
2. Guidelines for Application of the Petroleum Resources Management System. November
2011. http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf
3. Petroleum Resources Management System. 2007.
http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf
well logs
well completion data
casings and liners
well tops / markers
o Fault data
Fault polygon
Fault surface
Fault sticks
Seismic Interpretation
o 3D grids
o Core data
Displaying data
Well tops
Well correlations
Editing well tops
Creating new well tops
Making surfaces from well tops
Fault Modeling
o Corner Point Gridding
o Fault Sticks
o Fault Polygons
o Digitize the fault polygons on the surface
o Creating the key pillars
o Adjusting the key pillars
o Connecting the faults
o QC the faults and the truncation at the faults
o Creating a segment grid boundary
o Inserting Trends and Directions to the fault
o Building Pillar grid
o QC the skeleton of the Pillar Grid
o Insert Surfaces into the skeleton
o Make horizons
o Tying Horizons to well tops
o Fault settings to the horizon
o QC of the resultant horizons using an intersection plane
o Make zones
o QC the zones by building intersection windows
o Layering the zones
3 D Grid Construction
o Construct the structural grid
o Define the 3D grid domain
o Corner point gridding
o Create the skeleton
o Insert surfaces into the skeleton
Facies Modeling
o Fluvial modeling
o Geometry
o Drift
o Sequential Indicator Simulation
o Interactive facies modeling
Petrophysical Modeling
o Deterministic modeling
o Stochastic modeling
Volume Calculations
o Calculating bulk volume
o Calculating STOIIP with Phi, Sw
Individual runs
Monte Carlo simulations
o Construct report
Well Correlations
o Review markers for top and base of reservoir targets
o Construct stratigraphic cross-sections, adjusting markers if necessary
Structure
o Review the input surfaces
o Import surfaces and create 2D grid
o Create structure maps on Top of reservoir horizons and seals
o Create isopach map of reservoir sands
Fluid Contacts
o Analyze well tests, create stick plots of oil, gas, water in wells
o Determine free water level and fluid contacts (oil-water, gas-oil)
Fault modeling
o Import fault data as fault planes, fault sticks or fault polygons
o Create fault surfaces from the input data by creating 2D grid for the surfaces
o Edit the faults if necessary using key pillars
o Connect the faults wherever necessary
3D Grid Construction
o Create a 3D grid skeleton
o Create a grid boundary and quality check the 3D grid
o If creating a faulted grid, QC the skeleton grid and create segment grid boundary
o Insert the surfaces into the 3D skeleton grid
o Tie the surfaces in the grid to the markers
o Create zones
o Review the zones using intersection planes for quality control
o Layer the zones accordingly and review the layering using the resolution of upscaled
well logs
Petrophysics
o Cross-plot well data and core data
o Generate calculated curves for Vshale, porosity and permeability
o Analyze capillary pressure data; plot J curves, plot Sw as a function of J (phi, k, Pc)
o Calculate oil and gas saturation as a function of height above free water level
Lithofacies
o Cross-plot well data and core data; identify data clusters
o Relate measured values to lithofacies types (core data)
o Create a LITH log for each well, assigning a number to each lithofacies
o Map lithofacies distribution
o Relate maps to environments of deposition
o Investigate seismic attributes that may correlate spatially to lithofacies
1.13.3 References
1. Industry experience
4D Seismic surveys have been utilized over the last two decades in the monitoring of the
results of producing oil and gas fields to determine where bypassed pay or reservoir that is
not in communication with the producing horizons.
By definition, a 4D seismic survey is a repeat 3D survey over the same field at a later point
in time—time being the fourth dimension. Repeatability of the survey data is an underlying
requirement and includes both considerations of the geometry of the survey and the
geological nature of the problem being addressed. The second, third, and subsequent
surveys must be calibrated such that the relative amplitude differences observed in the
follow-on surveys are verified to be due to changes in rock and fluid properties resulting
from production of hydrocarbons or injection of water into the reservoir.
4D surveys can be used simply on an empirical basis to visually inspect the areas within an
interpreted seismic sequence that have undergone change in the period of time that has
elapsed since the previous survey, then to draw conclusions based on those observations.
Obtaining the greatest value in 4D seismic surveys requires detailed planning and analysis
in advance and then calibration of the results to ascertain the changes in rock and fluid
properties that have occurred over the intervening period. The technology has evolved to
Permanent Reservoir Monitoring (PRM) installations to improve quality and frequency of
4D surveys.
The figure below shows the North Sea area 4D installed base of PRM installations. The
impact of these installations has been that PRM systems originally designed for reservoir
management and placing infill wells are now used for well optimization, frac monitoring,
EOR, monitoring water injection, and well surveillance for HSE monitoring.
North Sea 4D PRM installations Keynote Address (Second EAGE Workshop on Permanent Reservoir Monitoring
2013)
4D seismic is frequently attempted using existing 3D datasets as the baseline. The issue
with this approach is primarily that there are significant differences in the noise
environment between the surveys. Success in using this approach is dependent on how well
the processing contractor can address the noise and balance the amplitudes between the
original and follow-on surveys.
In an ideal setting, 4D seismic data from multiple surveys would all be acquired using an
identical geometry. In some cases the use of existing 3D surveys and calibrating subsequent
3D surveys to match in background amplitude response is done to address changes that
occurred in fluid content from the original survey to future repeat surveys. Different
geometry makes calibration more difficult but does not preclude using surveys not recorded
with identical parameters. Reliability of results from dissimilar surveys is diminished but it
may be the only means of obtaining a baseline measurement.
4D surveys over heterogeneous reservoirs will enable the geologists and engineers to plan
development wells by identifying reservoir areas that are not being effectively drained by
the current wells. Although this is a case where 4D seismic is of significant value, there are
other instances where the 4D seismic may be useful including evaluation of structural
changes throughout the history of the field due to hydrocarbon extraction, passive seismic
monitoring for fracture propagation during frac operation as well as during production; and
for Carbon Sequestration projects it is a way to monitor changes in the rock properties
related to the injection of CO2 for storage.
4D seismic technology is recommended for large scale developments both onshore and
offshore. Through integrating production data, rock properties, petrophysical log results
and seismic data into a holistic interpretation, greater recovery of the oil or gas from fields
is possible. The EAGE conference on PRM has demonstrated that the technology is being
employed broadly and is being used successfully. Norway has been a strong supporter of
the technology. It has aided in moving recovery factors into the 60% range.
Other considerations for the use of 4D seismic surveys are the economics of the data’s
impact on field development. Seismic data that demonstrates changes in rock properties
related produced hydrocarbons is very impactful. Scale of the project will dictate how large
of an investment is justifiable. The both the figure above and the table below are included
to provide some insight into the scope and timing for many of these projects. The
technology has demonstrable value and for many of the Host Governments they are finding
value in the use of 4D seismic technology to improve recovery factors from fields that have
been in decline for many years.
Permanent Reservoir Monitoring employed in the North Sea and Offshore Brazil (first break volume 32, May
2014)
due to pressure relief in the reservoir may be valid reasons for follow-on
surveys.
o Designing the 4D survey
Parameters for acquiring the follow-on survey or surveys over a producing
field is normally based on the results of the previous studies. The rock
properties study may indicate that the 4D survey will be needed to evaluate
changes due to reservoir collapse. The Modeling study may indicate that the
4D survey requires shear wave data to enable the detection of the parameters
that are of most interest during development and production. The
calibration study may provide indications that there are missing elements in
the original survey (a lack of azimuthal distributions, insufficient aperture
angles for the reflections, etc.) that dictate a different design for subsequent
surveys.
Original 4D surveys were undertaken as repeat 3D surveys in marine
environment primarily. These surveys were able to demonstrate changes in
rock properties or fluid contents but were prone to issues related to the signal
to noise ratio (s/n) of the surveys. Current best practice is to utilize buried
geophone arrays that are permanently emplaced. The buried cables are much
quieter therefore much better s/n. They also lead to more consistent
measurements for follow-up surveys, many of the fields being monitored
today conduct multiple surveys during the life of the field. The other benefit
of a permanent buried array is that passive seismic measurements may also
be made during the life of the survey. The passive seismic can be used for
monitoring frac jobs or natural fracturing that is a result of pressure depletion
or pressure build-up in the case of an EOR project with water or gas
injection.
o Processing the 4D survey
The key to processing the 4D surveys is in the ability to consistently bin and
then calibrate the amplitudes in the surveys. For follow-on surveys that use
a different geometry than the original survey this results in re-binning them
to a consistent grid. For surveys that were acquired in noisier environments
it is critical to normalize the amplitudes carefully. Operators that are doing
multiple follow-on surveys develop a consistent processing flow that enables
rapid turnaround of the new data.
The final step in the processing is creating the delta set where the differences
between the first and second survey are calculated. If the data are not
properly calibrated and amplitudes balanced the difference data is difficult
to get value from. The interpreting geophysicist will normally start by using
the horizons picked in an original interpretation and use them to validate the
new and old surveys are similar. An amplitude extraction over the zone(s)
of interest is then used to investigate the differences and begin to assign
significance to the observed differences.
The steps outlined above are all part of a PRM project or a 4D seismic project using repeat
3D seismic surveys without a permanently installed recording system. PRM has the distinct
advantage of being able to be used as a passive as well as an active seismic acquisition
system. PRM normally yields more consistent results between surveys and has lower
overall noise than repeat surveys using surface or streamer surveys. With the permanent
installation it can be used to monitor frac jobs and for HSE purposes to correlate production
events observed throughout the life of the field.
All 4D projects require sufficient modeling to demonstrate the rock property alterations due
to fluid content changes are detectable in seismic data. Once that effort has been completed
the design of an acquisition program to accurately capture the amplitude variations can be
completed and a PRM system deployed.
1.14.3 References
1. MacBeth, C., Huang, Y., Ralahat, R., 2013, 4D Seismic Interpretation with Frequently
Acquired, Multiple Time-lapsed Surveys, Proceedings of the Second EAGE Workshop on
Permanent Reservoir Monitoring 2013 – Current and Future Trends Stavanger, Norway, 2-
5 July 2013
2. Bjerrum, L. W., Matveeva, T., Lindgard, J.E., Rutedal, H.I., Yde, A.C. S., 2014,
Comparison of Noise on an Un-Trenched and Trenched Cable Deployed in the North Sea
for a PRM System, Characteristics , Proceedings of the 76th EAGE Conference and
Exhibition 2014, Amsterdam RAI, The Netherlands, 16-19 June 2014
3. Bertrand, A., Jeanjeot, G., Folstad, P.G., Grandi, A., Buizard, S., Hoeber, H., Al-Khatib, H.
Nakstad, H., 2013, Ekofisk PRM Seismic Operations, , Proceedings of the Second EAGE
Workshop on Permanent Reservoir Monitoring 2013 – Current and Future Trends
Stavanger, Norway, 2-5 July 2013
4. Takanashi, M., Kato, A., Kasahara, J., Luth, S., Juhlin, C., 2014, Elastic Full Waveform
Inversion with a Permanent Seismic Source ACROSS: Towards Hydrocarbon Reservoir
Monitoring, International Petroleum Technology Conference 2014
5. Johann, P. R. S., Thedy, E. A., Ramos Filho, W. L., Silva, J.G.R, 2013, , Proceedings of the
Second EAGE Workshop on Permanent Reservoir Monitoring 2013 – Current and Future
Trends Stavanger, Norway, 2-5 July 2013
6. Watts, G. F. T, 2013, Keynote Presentation – Evolution in the PRM Marketplace,
Proceedings of the Second EAGE Workshop on Permanent Reservoir Monitoring 2013 –
Current and Future Trends Stavanger, Norway, 2-5 July 2013
7. Irving, D. H. B, McConnell, J., 2013, Operationalization of Workflows for Reservoir
Monitoring and Decision Support: Implications for Data Management, , Proceedings of the
Second EAGE Workshop on Permanent Reservoir Monitoring 2013 – Current and Future
Trends Stavanger, Norway, 2-5 July 2013
8. Thompson, M., Houbiers, M., McConnell, J., Irving, D. H. B, 2014, Quantitative 4D
Analysis Using Business Analytics Techniques, Proceedings of the 76th EAGE Conference
and Exhibition 2014, Amsterdam RAI, The Netherlands, 16-19 June 2014
9. Selwood, C. S., Shah, H. M., Mika, J. E., Baptiste, D., 2013, The Evolution of Imaging over
Azeri, from TTI Tomography to Anisotropic FWI, Proceedings of the 75th EAGE
Conference and Exhibition 2013, London, UK, 10-13 June 2013
10. Falahat, R., Obidegwu, D., Shams, A., MacBeth, C. 2014, The interpretation of Amplitude
Changes in 4-D Seismic data arising from Gas Exsolution and Dissolution, Petroleum
Geoscience, Vol 20, 2014, pp. 303-320
11. Norberg, D. N., 2013, The Rock Strewn Road to Getting Sanction for Investment in PRM,
Proceedings of the Second EAGE Workshop on Permanent Reservoir Monitoring 2013 –
Current and Future Trends Stavanger, Norway, 2-5 July 2013
12. Drottning, A. H., Zuhlsdorff, L., Bergfjord, E., Rasmussen, T.A., 2013, Use of Modelling
to Optimize the PRM Geometry for Active and Passive Seismic Analyses, Proceedings of
the Second EAGE Workshop on Permanent Reservoir Monitoring 2013 – Current and
Future Trends Stavanger, Norway, 2-5 July 2013
In case of unfinished minimum work program in a block, the same can be substituted
by equivalent work program, in another block of Contractor or in new acreage as
approved by Regulator. This can be achieved in terms of equivalent work units.
1.15.3 References
1. Production sharing contracts for Brazil, Indonesia, Oman, Pakistan, Myanmar & Australia.
In some cases the PSC dictates that a non-revocable Performance Bond will be issued in the amount
of the Minimum Exploration Obligation. The expenditures made in each year of the exploration
phase as they are approved are deducted from the outstanding balance on the Performance Bond.
Some model PSC agreements do not address a compensation process for failure to meet the
Minimum Work Obligation. There are some PSC agreements that stipulate a minimum work
program but do not clearly indicate a value assigned to completing that program.
In general, the methodologies employed in determining the Liquidated Damages if there is a clause
that addresses this issue are either based on:
A fixed amount for the program and reduced by the actual amount expended
The means of providing security for the Host Government for those Liquidated Damages is not
stipulated in all agreements, but where noted it is most frequently a Performance Bond. If there is
such a Performance Bond, the value of the bond may be reduced periodically depending on the
actual expenditures towards the work program with Host Government approval. The periodicity of
this adjustment is not stated in all cases and is inconsistent when it is stated.
In the event a commitment has been partially completed but the full intent has not been
achieved, the Management Committee should address the issue and subsequently refer to
the Government for approval.
o Credit should be given for wells drilled which have achieved the exploration
objective (see broadened definition of Basement and Achievement of Exploration
Objective in Section 1.20)
o Secondly, for calculation of amount payable for unfinished MWP, it is proposed
that Period Wise Fixed Rates should be calculated and uniformly applied to ensure
transparency and reasonableness.
In cases where the Work Program has not been fulfilled based on a special case, the issue
should be raised to the Management Committee and with agreement of the Management
Committee, the issue would be elevated to the appropriate governmental agency / ministry
for approval.
1.16.3 References
1. Production sharing contracts for India, Angola, Kenya, Timor Leste, Kurdistan
Please refer to the Norwegian Petroleum Directorate “Blue Book” for well data and
“Yellow Book” for geophysical data for guidelines which serve as an industry standard
NDR adopted by a number of Host Governments (links are given in References below)
The advantage to a NDR is that there is a common form that manages all of the data and it
is easy for the Host Government to place the requirement for archival on the operators.
The cost for maintaining the NDR is in many cases shared by the Contractors/Operators
through an annual assessment as part of their operating budget.
India has already begun the implementation of a National Data Repository (NDR). The
NDR is responsible for determining the requirements for submitting the data for archival.
The Blue Book and Yellow Book references from Norway are included as examples of the
level of detail the NDR should provide to the operators in order to capture all of the data in
a systematic fashion so that it can be retrieved efficiently for future operators.
The Norwegian Data Bank utilizes a website to collect the details regarding data to be
submitted for addition to their archives. Procedures for online submission are found here:
http://www.npd.no/Global/Norsk/5%20-
%20Regelverk/Skjema/Borerapportering/HowtotransferCDRSXMLdatafilestoPSA1.pdf
The processes for submission of data are all included at the following website:
http://www.npd.no/en/Reporting/Submission-of-material-and-information-required-by-
the-rules-and-regulations/
1.17.3 References
1. Guidelines for reporting well data to authorities after completion, “Blue Book”, Version 6,
http://www.npd.no/globalassets/Global/Norsk/5-Regelverk/Tematiske-
veiledninger/B_og_b_digital_rapportering_e.pdf
2. Guidelines for reporting of Geophysical Data to Authorities, Yellow Book, Ver 1.4, 2013,
Norwegian Petroleum Directorate (http://www.npd.no/Global/Norsk/5-
Regelverk/Tematiske-veiledninger/Geophysical_guidelines_e.pdf)
Costs
o Pre-license costs - Cost that is incurred in the period prior to the acquisition of a
legal right to explore for oil and gas in a particular location.
o License acquisition costs - Costs that are incurred to purchase, lease or otherwise
acquire a property.
o Exploration and appraisal costs - Costs incurred after obtaining a license or
concession but before a decision is taken to develop a field or reservoir.
o Development costs - Costs incurred after a decision has been taken to develop a
reservoir
o Operating costs - Costs of producing oil and gas including costs of personnel
engaged in the operation, repairs and maintenance and materials, supplies and fuel
consumed and services utilized in such operations.
Decommissioning
o The process of plugging and abandoning wells, dismantlement of wellhead,
production and transport facilities and restoration of producing areas in accordance
with license requirements and/or relevant legislation.
Impairment
o Capitalized development costs - a change in circumstances leading to a conclusion
that the recoverable amount from reserves associated with capitalized development
costs is likely to be less than the amount at which those costs are carried in the
books.
o Costs capitalized whilst a field is still being appraised - a change in circumstances
leading to a conclusion that there is no longer a reasonable prospect that commercial
reserves will result and will be developed.
High risk
High cost of investment
Time lag between exploration and production
No necessary correlation between the capital expenditure for exploration and
development and the value of the oil and gas reserves discovered as a result
of the activities
o These and other factors make the accounting for oil and gas operations complex and
specialized and thus have led to development of a wide range of accounting
practices in the industry. The two most commonly used and recommended historical
cost methods in accounting for oil and gas industry is:
Successful Efforts Method
Full Cost Method
o Oil and Gas accounting can be related to three basic activities carried out by oil and
gas exploration and production companies.
Pre-production and development activities
Production activities
Decommissioning activities
o These three basic types of activities must be accounted for using one of the two
above named generally accepted historical cost methods. These methods of
accounting have been described in the sections below.
Accounting Systems
o Successful Efforts Method
The chart below describes the functioning of the Successful Efforts Method
o The primary difference between successful efforts and the full cost is in whether a
cost is capitalized or expensed when incurred. Thus the difference is in the timing
of expense or loss charge against the revenue.
o The second difference between the two methods is the size of the cost center over
which the costs are accumulated. For the successful efforts method the cost center
is the lease, field or reservoir whereas for the full costs method the cost center is the
country.
o Under the successful efforts method, only exploratory drilling costs that are
successful are considered to be a part of the cost of finding oil and gas and thus
capitalized. Unsuccessful exploratory drilling costs do not result in any economic
benefit and thus are expensed. In contrast full cost method considers both
unsuccessful and successful costs incurred in search for reserves as a necessary part
of finding oil and gas. Thus, both successful and unsuccessful costs are capitalized
even though the unsuccessful costs have not future economic benefit.
o A comparison of the accounting treatment between the various costs under both
successful efforts method and full costs method is shown in the table below:
If any commercial reserves are found after the appraisal, then the net
capitalized costs which were incurred in the process of discovering
the field should be transferred into a single field cost center. Any
subsequent development costs, should be capitalized in this cost
center.
The accounting policy of the firm should provide the basis under
which cost pools are established, for example geographic area,
region or country.
The aggregate net book value of full cost pools should be disclosed,
together with the aggregate of costs held outside cost pools.
o Production activities
All the expenses under the production activities are expensed under both
Successful Efforts and Full Cost methods of accounting.
Inventory Valuation
1.18.3 References
1. Wright, Charlotte J., and Rebecca A. Gallun. Fundamentals of Oil & Gas Accounting.
Tulsa, OK: PennWell, 2008.
2. "SORP Statements of Recommended Practice." Accounting for Oil and Gas Exploration,
Development, Production and Decommissioning Activities, Oil Industry Accounting
Committee, UK: Updated 7th June 2001.
3. Jennings, Dennis R., Horace R. Brock, Joseph B. Feiten, John P. Klingstedt, and Donald
M. Jones. Petroleum Accounting: Principles, Procedures, & Issues. Denton, TX:
Professional Development Institute, 2000. Print.
4. "Financial Reporting in the Oil and Gas Industry: International Financial Reporting
Standards." PwC. PricewaterhouseCoopers International Limited, Sept. 2011. Web. Feb.
2015. <http://www.pwc.com/gx/en/oil-gas-energy/reporting-regulatory-
compliance/publications-financial-reporting-oil-gas-industry.jhtml>.
5. Adere, Endale M. "Accounting for Oil and Gas: The Effect of the Gap between US GAAP
and IFRS on Norwegian Companies." Umea School of Business, May 2011. Web. Feb.
2015. <http%3A%2F%2Fwww.diva-
portal.org%2Fsmash%2Fget%2Fdiva2%3A478518%2FFULLTEXT03>.
6. Cortese, C. L., H. J. Irvine, and M. Kaidonis. "Extractive Industries Accounting and
Economic Consequences: Past, Present and Future." N.p., 2009. Web. Feb. 2015.
<http%3A%2F%2Fro.uow.edu.au%2Fcgi%2Fviewcontent.cgi%3Farticle%3D1533%26co
ntext%3Dcommpapers>.
7. Malmquest, David H. "EFFICIENT CONTRACTING AND THE CHOICE OF
ACCOUNTING METHOD IN THE OIL AND GAS INDUSTRY." Journal of Accounting
and Economics 12 (1990): 173-205. Securities and Exchange Commission, Washington
DC. Web. Feb. 2015.
8. Schugart, Gary. "Workbook on Oil and Gas Accounting." (2002): n. pag. Institute for
Energy, Law & Enterprise, 2002. Web. 2015.
<http://www.beg.utexas.edu/energyecon/Uganda/Oil-&-Gas-Accounting-1.pdf>.
that may not be available locally to work with the data, thus adding a higher level of expertise in
the analysis. This benefits both the Government and Contractor/Operator in that the quality of the
analysis or processing will most likely be better as a result.
It is not unusual for Host Governments to allow the export of data or materials for analysis and
processing. Countries that clearly allow for this activity are Brazil, Angola, Kurdistan, Ghana,
Mozambique and Timor Leste which all have provisions allowing for the export of data. The critical
element appears to be that for nearly all cases where the issue is addressed, the original data, a
portion of the samples, or copies of must be retained in country unless expressly approved by the
Host Government or National Oil Company.
The Contractor is required to provide all data and materials to the Government.
Where exportation is allowed for analysis or processing the original data, a sub-sample, or
a copy of the original data must be retained in country.
In most cases the Government must be notified of the planned exportation and give
approval.
Approval to perform the work out of the country is based on an understanding that
equivalent capabilities do not exist in-country.
For cases where the expertise available in country may not address the level of expertise
required for specific analysis or processing, during the tender evaluation the local
contractors would be excluded for technical reasons and therefore the cost differential is
not an issue.
The export of data for analysis and processing in other countries is a very common practice
and should be endorsed where needed. As outlined in the Best Practices, an approval by the
Government is needed. The process will in many circumstances be initiated through a tender
for analysis or processing services such that the local services companies may demonstrate
whether the capability to do the work exists locally. Technical evaluation of the tenders
results in the qualification of the bidders. Rationale for the technical evaluation may
include:
o Specific algorithms that the Operator considers to provide incremental value beyond
routine processing algorithms that may be used by local contractors;
o Technical work that may require use of data that exists in a unique database that is
not local to the operation; or
o Specific personnel with unique experience / knowledge that add value to the analysis
and processing due to their expertise in the field of study.
The cost of the project can also be a reason for exporting the data to a contractor that is out
of the country. Lower cost for performing the work outside the country may be due to:
o The commercial tender shows the work can be performed at the same technical level
outside the country for a lower cost;
o The incremental cost for the quality assurance personnel in the case where these
individuals are not local. An individual may be required travel frequently to a
contractor’s location during the processing effort therefore these total costs should
be incorporated in the commercial evaluation; or
o Computing facilities or laboratory facilities that are not present or available in the
country would be prohibitively expensive to access or import to complete a project.
The mechanism for assessing the reasons for exporting the data are frequently addressed
during the tender evaluation process. Consideration to allow for the application of the right
technology for a project should outweigh the insistence that the data be maintained in the
country.
Normal processes for exporting data stipulate that the original raw data or sample must
remain in country. To allow for completing the work outside of the country in the case
where a sample must be sent only part of the sample may be exported. For digital data, the
original copy is retained and a secondary copy is shipped or transmitted. Digital
transmission is the preferred method if possible. An issue is that the volume of data from
some large 3D seismic field datasets may be too great to transmit.
1.19.3 References
1. Brazil Concession Agreement; Clause 17
2. Angola Model Production Sharing Agreement; Article 24
3. Kurdistan Model PSC, Article 18
4. Ghana Model PSC, Article 7
5. Mozambique Model PSC
6. PSC Model Timor-Leste; Article 15.4
Basement is encountered.
The ability to obtain relief from the Minimum Work Obligation for a well
drilled that does not reach the intended horizon is still left to the discretion
of the Management Committee but the cases outlined above are the most
frequently cited as exceptions where the operator is allowed to dispatch the
obligation.
MWD is a type of well logging that incorporates the measurement tools into
the drill-string and provides real-time information such as azimuth,
inclination, etc., to help with steering the bit.
In very high inclination wells, use of LWD/MWD may be the best option.
LWD and MWD acquire evaluation and drilling optimization data during
drilling operations to guide well placement and to provide data for survey
management and development planning.
o Drilling Rig Selection
Most drilling contractors use IADC (International Association of Drilling
Contractors) recommended practices for rig operating and design practices
including preventive maintenance recommendations.
Proper rig selection involves preparing detailed maximum load well designs
and evaluating the rig capability and limitations to ensure the rig is suitable
for the job. In some cases the well design and drilling procedures may have
to be altered to match rig limitations.
Soil evaluation for rig foundation must be conducted for rig stability except
for drill ships and floaters.
Other environmental factors that will impact the rig stability are wind, wave
and current. These factors must be considered in rig selection.
o Rig Personnel
All relevant personnel of Company and Contractor must be trained in Well
Control. Several certifications are globally recognized, e.g. IWCF
(International Well Control Forum), Wellcap by IADC, Randy Smith Well
Control, etc.
Other commonly used training programs are:
H2S Handling
Each operator should develop a similar document for each well. The
following information is generally presented:
Type and volumes of fluid expected: oil, gas, H2S, CO2, etc.
For sub-sea wellheads and BOP, the current and other marine
conditions.
Wellheads and BOP must be selected to meet the latest API recommended
practices, IADC guidelines and ISO QA/QC
Material selection must comply with NACE standards
Design must meet ASTM and other manufacturers’ procedures
Installation must be in accordance with manufacturers’ procedures
All maintenance and repairs must comply with manufacturers’ procedures
and use OEM parts only
After any repairs, wellheads and BOP must be re-certified as per API
requirements
o Sustained Annular/Casing Pressure
Sustained annular pressure is defined as pressure in an annulus of non-
structural casing strings that is:
Annulus pressure in all wells and in multipurpose and gas lifted wells
shall be monitored through continuous recording
80 percent of the MIYP of the pipe body of the next outer casing or
production riser string; or
For the last outer casing or production riser string in the well, the MAWOP
is the lesser of the following:
30 percent of the MIYP of the pipe body for the casing or production
riser string being evaluated; or
1.20.3 References
1. As practiced by Major Oil Companies
2. API RP 10B – Testing Well Cement
3. API D10 – Selecting Rotary Drilling Equipment
4. API RP O4G – Inspection, Maintenance and Repair of Drilling and Servicing structures
5. API RP 13B – Field testing of Drilling Fluids
6. API RP 54 – Occupational Safety Oil and Gas Drilling Operations
7. API Spec 16D – Well Control Equipment Systems
8. ISO 9001
9. ISO 29001 – Quality management requirements for the design, development, production,
installation and service of products for the petroleum, petrochemical and natural gas
industries
10. NACE TM0175 – Testing of materials for SSC in H2S environment
11. NACE TM0187 – Evaluating elastomeric material in H2S environment
12. PSCs from Kurdistan, Ghana, Kenya, Republic of Cyprus, Tanzania
13. “Remember Basement in your Oil and Exploration: Examples of Producing Basement
Reservoirs in Indonesia, Venezuela and USA”
(http://cseg.ca/assets/files/resources/abstracts/2007/038S0126.pdf)
14. International Association of Drilling Contractors- IADC-Manual
15. National Association of Corrosion Engrs-NACE- document MRO175
16. International Well Control Certification- IWCF
17. Helicopter Under-water Egress Training)-HUET
18. American Petroleum Institute-API- RP53- BOP
19. American Petroleum Institute-API- RP90- Casing Annular Pressure
20. ONGC – BOP Installation/testing procedures
to re-negotiate the terms of the contract after signature. The approach taken by the DGH referenced
above appears to be a reasonable one.
The questions that remain to be answered are with respect to what portions of a work program
should come into consideration for such waivers, and the justifiable rationale for such an alteration
to the work program schedule. International practices for this tend to be limited to cases where
there is an excessive financial burden due to limited availability of contractors to undertake a
program; limited contractor resources (such as drill rigs); delays in contractor timing due to work
load in other countries or contract areas; and in general due to limited resources (such as specialized
drill pipe, or drilling materials).
Another source of delays relates to Host Government approvals and permits required for carrying
out the work program. Many governments allow for extensions for delays in obtaining approval,
permits, clearances, etc. The Government of India included policy which permits extensions to
Contractors on account of securing Government approvals/permits/clearances, deeming these
“excusable delays.”
In the event delays are directly the result of delays in obtaining Government approvals,
permits, clearances, etc., extensions of equal duration of the delay should be provided to
Contractors.
Policies for “stopping the clock” are difficult to administer. These situations should be
considered only when there are multiple Operators that are impacted by a commercial or
physical constraint that is global or regional in scale. In the case of the Indian PSC
agreements the ability to stop the clock is not a provision within the agreement and will
necessitate action by the government. An extension policy regarding excusable delays could
be added to future production sharing contracts.
If an Operator believes the situation to fall under the category of Force Majeure, then they
can petition for consideration by the Government.
1.21.3 References
1. Federative Republic of Brazil Ministry of Mines and Energy, Production Sharing Contracts
for Exploration and Production of Oil and Natural Gas.
2. Letter dated July 19, 2010, from Government of India Ministry of Petroleum and Natural
Gas to Director General of Hydrocarbons, Subject: Grant of Rig Holiday in Deepwater
Blocks and implementation issues under Production Sharing Contract (PSC) regime reg.
3. Policy Framework for Relaxations, Extensions and Clarifications at the Development and
Production Stage under the PSC Regime for Early Monetization of Hydrocarbon
Discoveries. Letter dated November 10, 2014. From Government of India Ministry of
Petroleum and Natural Gas to Director General of Hydrocarbons.
Often Governments will acquire speculative 2D seismic data over unlicensed Blocks to
generate interest by potential Operators in these open Blocks. This data is usually available
for purchase by interested Operators.
Governments maintain copies of all data acquired on all Blocks throughout the life of each
Block. This data is also often available for purchase from the Government by interested
parties.
Upon award of a Block, the Operator will often be provided with more detailed data,
especially seismic data, than that which was included in the original data package provided
to interested companies.
Award of a Block will require that the Operator must carry out a work program that will
likely include reprocessing of existing seismic data, acquisition of 2D seismic and/or 3D
seismic, potential field data, geological studies, geochemical sampling and the drilling of
one or more exploration wells.
Acquisition of new data by the Operator may include programs that extend beyond the
contract area. In these cases, the normal operating procedure is to get approval from the
government and from Operators in the adjoining Block(s) (if the acreage is held) to acquire
data over the areas under their control. The typical practice is that this “mineral trespass” is
granted to the Operator in exchange for the current license holder being provided copies of
the new data. The Operator will negotiate a Data Trade agreement that encapsulates the data
to be provided and receive governmental approval for the trade.
Certain seismic or other data acquisition projects might cross out of the Operators
concession area into an adjoining area. In most cases the surveys must continue to allow for
the full imaging of the area within the concession. This type of trespass also requires
approval by the adjoining concession holder. A typical agreement between the two
operators will grant the holder of the trespassed area an amount of data in the Operator’s
concession area equal to the amount of data acquired within the trespassed block.
Data trade agreements must stipulate the type of data being traded and will normally include
specific reference to the level of processing applied to the traded data. Access to the raw
data is negotiable.
Once the Operator has obtained reprocessed or new data they will be in a position to trade
with Operators of adjacent blocks. Normal practice in countries where Production Sharing
Contracts exist is to negotiate a trade wherein a quid pro quo trade is made after receiving
Government approval.
The acquisition of data in adjoining areas is an important part of assessing the viability of
the exploration targets within the contract area. The ability to conduct this work is important
but must consider the rights of the holders of adjacent acreage.
For open acreage – the Government will be the grantor of permission to extend the survey
over the acreage not currently under license. Since the Government is technically the
“owner” of all data collected these data will ultimately reside in the National Data
Repository. While the Operator still holds the Exploration License for the block under
which the data was originally acquired, a normal practice would retain proprietary rights to
use this data with that Operator. Other companies that wish to gain access to that data will
need to petition the Operator and the Government for the data and depending on the trade
agreement reached between the two companies the Government normally approves the
trade agreement.
For held acreage – the Operator must petition the Operator of the block to “trespass” during
their acquisition efforts. Normally there is no reason for the contract holder to deny the
trespass agreement. Such Agreement must be completed in a time bound manner. A
common practice for a data trespass is to provide 1 for 1 data from the Operator’s block as
compensation for allowing the trespass. These principles hold for well and seismic data.
Operators frequently trade well data to improve the understanding of their blocks by either
pre-trading wells they are committed to drill or wells already drilled in their acreage. It is
the ability of each Operator to properly place their block in a regional context that adds
value to the Government, therefore support for these transactions is not reasonably
withheld.
1.22.3 References
1. Production sharing contracts for Ghana, Kurdistan, Indonesia, Oman, India and Nigeria.
2. 2013 Global Oil & Gas Tax Guide - includes discussion of terms for Columbia, Equatorial
Guinea and Ecuador.
Countries which require mining permits for the development of the discovery typically
allow for further exploration activities undertaken under the mining permit.
In the United States, continuous exploration throughout the life of a producing field is
allowed and encouraged which leads to additional discoveries in the area.
The specific issue in this case is the fact that once a contract area is converted to a mining
license the question is raised regarding cost recovery of exploration related costs. All the
exploration cost should be allowed for cost recovery otherwise there will be no incentive
for incremental high risk exploration effort. The “Ring Fencing” of production areas to limit
cost recovery creates a disincentive to continue looking for additional resources. Extension
exploration has one of the highest success rates of any type of exploration drilling activity
and should be encouraged.
Exploration in ML areas is permitted and not ring fenced and the terms and conditions of
PSC are applicable in to any new discovery in the ML Area.
1.23.3 References
1. Model PSC for the Republic of Kenya, Angola, Kurdistan, Brazil, Oman and Indonesia
2. Minerals Program regulations in New Zealand
3. Gulf of Mexico for Continued Exploration in Mining Area
“Work Program” means a work program formulated for the purpose of carrying out
Petroleum Operations
Most countries require submission of AFEs for each actionable item along with a proposed
Work Program and Budget for MC approval.
The MC is usually charged with making sure that all petroleum operations move forward
in a safe and expeditious time frame and adhere to the contractual obligations of the
Minimum Work Program and Minimum Expenditure Commitment.
Contractor/Operator shall reach an agreement prior to the start of the Financial year on the
work program and budget.
Each reviewed/approved Annual Work Program and Budget may include an agreed upon
contingency that will apply to the total of such reviewed/approved Annual Work Program
and Budget.
Details of the Annual Work Program may change through the course of the Financial Year
and the Contractor/Operator should not be limited from making these changes as long as
the objectives of the Annual Work Program and approved expenditures in the Budget and
Operating Costs remain the same. Material changes to objectives and/or budgeted
expenditures of the Annual Work Program during implementation shall require approval of
the MC.
In the exploration phase of a concession the work program is primarily the responsibility of
and is paid for by the contract holder. Costs incurred go into a cost recovery pool and are
recovered in the event of a discovery leading to commercial production. Decisions
regarding these expenditures should remain in line with the risk / reward of the prospects
in the block and comply with the MWP/MEC. During the Exploration Phase, the
Management Committee holds an advisory capacity. For exploration activities during this
phase, the Management Committee hold an advisory capacity.
In the Development Phase of the granted mining lease, the Management Committee holds
an approval capacity. This control is in place to ensure the operator is efficiently and
effectively developing the asset. As mentioned in Section 1.23, continued exploration
within the mining lease should be allowed as this could lead to an increase in production
from the asset to the benefit of both the Contractor and the Government.
1.24.3 References
1. Production sharing contracts for Tanzania, China, Ghana, Angola, Oman, Indonesia, India.
Discovery
2.1 Standards for Area Demarcation for Development, Discovery and
Mining Lease
2.1.1 Definitions and Discussion
In the India Model PSC, an operator may announce a Discovery, and must submit a Discovery
report after completion of well tests. Operator must then submit an Appraisal Program with a Work
Program and Budget specifying the boundaries of a potential development area. Operator may then
submit a Declaration of Commerciality (DoC) with a full report. Operator must then submit a Field
Development Plan (FDP) with the boundaries of the proposed Development Area. Subsequent to
approval of the FDP, a Mining Lease (ML) is granted for commercial production of oil and gas
from the ML area, as approved in the FDP.
A Discovery may be of conventional or unconventional resources. Conventional resources exist in
discrete petroleum accumulations related to a localized geological structural feature and/or
stratigraphic condition, typically with each accumulation bounded by a downdip contact with an
aquifer, that may be established subsequent to appraisal drilling and which is significantly affected
by hydrodynamic influences such as buoyancy of petroleum in water. The petroleum recovered
typically requires minimal processing prior to sale. A Discovery is actual evidence (testing,
sampling, and/or logging) from at least one well penetration in one of the accumulation to have
demonstrated presence of potentially moveable hydrocarbons.
Unconventional resources exist in petroleum accumulations that are pervasive throughout a large
area and that are not significantly affected by hydrodynamic influences. Examples include coalbed
methane (CBM), basin-centered gas, shale gas, gas hydrates, natural bitumen, and oil shale
deposits. Typically, such accumulations require specialized extraction technology (e.g., dewatering
of CBM, fracturing programs for shale gas or oil, steam and/or solvents to mobilize bitumen for in-
situ recovery).
In the Oman PSC, an operator must submit an Appraisal Plan after a Discovery. The Appraisal Plan
defines an area where appraisal activities will be conducted. After the appraisal work is conducted,
an Appraisal Report must be submitted followed by a FDP. DoC is made upon approval of the
FDP. The Development Area is defined in the FDP.
In the Kurdistan PSC, an operator may announce a Discovery, and then must submit a Discovery
report. Operator must submit an Appraisal Work Program after the Discovery report, and the
appraisal area may not be greater than two times the size of the mapped geologic structure. After
the appraisal work is completed, operator must submit an Appraisal Report. With the Appraisal
Report, operator may submit a Declaration of Commerciality. Operator must then submit a FDP
after declaring the Discovery as commercial. FDP should define the production area, taking into
account the results of the appraisal work program.
Good Industry Practices must be defined for the demarcation of Development versus Exploration
areas, and for how a Discovery may be appraised and progressed to a Declaration of
Commerciality.
Appraisal Area
o After the discovery of a conventional resource, the appraisal area should be basis of
judged prospectivities, delineated from G&G data set, prior to drilling. This will
involve defining the hydrocarbon entrapment by updating existing maps with the
new well data. An appraisal program should be defined to upgrade the resources
within this area.
o For an unconventional play such as shale oil, condensate, or gas, the appraisal area
should include the area on the lease where the shale is sufficiently thick, sufficiently
high in TOC and mature for hydrocarbon generation such that hydrocarbons should
be present in the shale. An appraisal drilling program should be defined to prove up
the unconventional resources within this area, to produce at commercial rate.
o For tight gas or basin-centered gas, the appraisal area should include the area on the
lease where the reservoir is sufficiently thick. An appraisal program should be
defined to prove up the resources within this area, to produce at commercial rate.
o The Appraisal Area may not include the whole block. To retain an area outside of
the Appraisal Area when entering the next exploration phase, additional exploration
as per the PSC agreement will be required.
Development Area
o After a successful appraisal of a conventional resource, the Development Area
should be defined in the DoC and FDP reports, based on G&G data generated till
completion of appraisal program. The Development Area is equivalent to (FDP
approved area and represents the area where the areal extension of oil/gas pool limits
of reservoirs/geobodies have been defined/mapped with a reasonable confidence.
The FDP will define a plan to develop the resources within the Development Area.
o For an unconventional play such as shale oil or shale gas, the Development Area
should include the area on the lease where the shale is sufficiently thick to produce
at commercial rates, sufficiently high in TOC and mature for hydrocarbon
generation such that hydrocarbons should be present in the shale, and is an area
confirmed by appraisal drilling. The FDP will define the program to develop the
unconventional resources within this area.
o For tight gas or basin-centered gas, the Development Area should include the area
on the lease where the reservoir is sufficiently thick to produce at commercial rates.
This area will be confirmed by an appraisal drilling program showing the extent of
the reservoir.
o Mining Lease approval should be granted by the government in a timely manner.
2.1.3 References
1. Oman, Kurdistan, and India Model PSC agreements.
Once a discovery is made, the Contractor should notify the same. A notice of
discovery may be based on production testing results. As a practice, the production
testing must be witnessed by DGH representative as guided by respective PSC.
o After completion of well testing, Contractor should submit a Discovery Report,
reviewing the relevant well data which proves the discovery of hydrocarbons in the
well. Such report should include geological maps, OOIP / GIIP, well test results and
possible fluid contacts.
2.2.3 References
1. Oman, Kurdistan, and India Model PSC agreements.
2.3 International Norms for Well Flow Tests such as DST and any other
Test Procedures in Open Hole, Cased Hole, Gravel Pack, Frac Pack
Required for Evaluating or Approving the “Discovery”.
2.3.1 Definitions and Discussion
The Directorate General of Hydrocarbons (DGH) has been entrusted with the
responsibility for monitoring of PSCs awarded under Pre-NELP and NELP and field
bidding rounds on behalf of Government of India. These PSCs require monitoring of
exploration work commitments during the exploration phase, and further monitoring of
appraisal work and approval of development work. In the case of a hydrocarbon
discovery, an issue is what constitutes a discovery, and what data must be collected to
demonstrate a discovery has been made. Relevant data includes mud logs, electric logs,
Dynamic Formation Tester /RDT/RCI sample collection, and DST results.
There are different types of tests conducted for discovery wells are:
o Dynamic Formation Tester, RDT, or RCI or a similar test tool depending on the
service company
o DST
from the Dynamic Formation Tester results and supported by well logs but
one test at a time.
In the past, as the name applies, a DST tool with packers and tester valve
used to be attached at the end of the drill string and run into the well to test
the perforated interval of interest. However, the current day DST tool
consists of a bottom-hole testing assembly which is normally attached at the
end of suitable tubing string rather than the drill string.
These tools have multiple valves and a bundle of four or more high accuracy
pressure and temperature gauges. They also have capability of shutting-in
the well very close to downhole; however, their functional ability needs to
be evaluated and confirmed.
Testing times and flow rates for each test need to be pre-determined
depending on the type of fluid (oil or gas), quality of the formation (high or
low permeability), wellbore effects and other factors such as reservoir
pressure and temperature etc. The use of a commercial or in-house software
(if available) is recommended for this purpose.
Test sequence for each test interval consists of the following four major
steps:
STEP 1: Short time (e.g. 10 to 15 minutes) flow and one to two hours
of shut-in period to determine initial reservoir pressure.
Pressure and temperature data can be recorded even every few seconds and
transmitted to surface or any remote location via internet. However, it is
important that appropriate gauges have been selected depending upon the
range of anticipated pressures and temperatures and have been properly
calibrated and tested.
It is important to record flow rates very accurately.
The above discussed testing procedure can also be used for gravel pack and
frac-pack wells in case they fall into the category of discovery wells. In this
case one or two pressure gauges can be set to read annulus pressures and
remaining gauges are set to read tubing pressures. The pressure difference
between the tubing and annulus should indicate the pressure loss due to
gravel pack or sand production.
The pressure difference between the two tubing gauges at two different
vertical locations can help to determine the wellbore fluid gradient. This
information can be also used to extrapolate measured pressures to the mid-
point perforation interval (MPP) in case the pressure gauges are vertically
away from the MPP.
Such tests can be run in open-hole but are not usually recommended because
of the possibility of encountering formation integrity problems including the
risk of losing the well.
The use of the Dynamic Formation Tester tool should not be considered a substitute for
the DST type tool and vice versa especially for the first discovery wells until enough
confidence has been gained regarding discovery or non-discovery of a given oil and gas
play.
The use of both Dynamic Formation Tester and DST are recommended for discovery
or exploration type offshore wells in deep water and ultra-deep water environment as
well as deep wells in the onshore environment where the cost of drilling and completing
wells is very high.
In certain cases, where a good correlation has been established between the well logs
and the Dynamic Formation Tester and DST results, the use of only Dynamic Formation
Tester tool may be sufficient. However, the flow and shut-in test periods in such cases
need to be much longer than the usual short test periods utilized during Dynamic
Formation Tester type open-hole tests. Moreover, it should be also confirmed that the
formation is competent enough to withstand longer testing periods unless the Dynamic
Formation Tester tool is run in a cased-hole environment.
In other cases, cost benefit analysis should be performed to evaluate whether both the
Dynamic Formation Tester and DST type tools should be run or the use of only the DST
type tool will be sufficient. This condition should be applicable in case of shallow
offshore wells and/or less expensive onshore wells.
In case of DST of oil wells, where the reservoir pressure is lower than the hydrostatic
pressure, the well may or may not flow to the surface. In this case, to determine well’s
flow potential, tools like coiled tubing may need to be used to assist the fluid flow to
the surface. After CTU job, influx study may be carried out to determine the liquid
influx rate followed by pressure gradient survey to know the fluid content in the tubing
column. Such wells also require specialized well testing methods such as slug and
impulse testing to derive the reservoir parameters.
Another challenging situation may occur in case of the DST of a heavy oil reservoir,
where API oil gravity is low and oil viscosity is very high. The result may be that oil
can barely flow into the well. To bring the oil flow to the surface, the use of tools like
jet pump may be required. Testing methods such as slug tests and/or impulse tests may
be used to derive reservoir parameters. In this case, to confirm or deny the discovery,
screening criteria required for the thermal exploitation of heavy oil reservoirs need to
be checked prior to the submission of the DoC.
The third challenging situation may occur in case of the DST of unconventional oil and
gas reservoirs, where the formation permeability will be in micro-Darcy. Based on the
experience of the exploitation of such reservoirs in USA, it is obvious that wells in such
type of reservoirs will have to be hydraulically fractured and wells will require to be
drilled on a small and closer spacing. Such information should be pertinent in DoC. In
testing of such wells using DST, flow rates will be low during the flow period and
wellbore storage effects will be high requiring down-hole shut-in during the pressure
buildup testing. Testing of such wells will require careful planning and execution.
In this write-up, three challenging cases related to DST have been discussed as above.
It should be pointed out that there could be other special cases which would require
special testing and analysis considerations.
A schematic of a DST type test procedure for each test interval is shown in the figure
below. It should be pointed out that axis values depicting pressures, rates, and test times
in this figure are arbitrary.
Based upon our experience in USA and certain European locations such as United
Kingdom and Norway, it is not a requirement that a representative of the Regulatory
Agency should attend the well-site during the Dynamic Formation Tester and DST type
testing of discovery wells or pressure transient testing of other wells. However, in India,
a government representative, if available, can be assigned to be at the well-site during
testing of discovery wells or other wells, if considered important or deemed appropriate
as per the PSC rules.
2.3.3 References
1. Fundamentals of Formation Testing, published by Schlumberger, Sugarland, Texas (2006)
2. Vella, M., Veneruso, T., Lefoll, P., McEvey, T. and Reiss, A.,:”The Nuts and Bolts of Well
Testing”, Oilfield Review (April, 1992)
3. Types of Formation Testing Tools described at the websites of Service Companies such as
Schlumberger, Baker Hughes, Halliburton and Weatherford, (Dec 2014).
4. Three SPE Monographs on Well Testing namely a) Vol. 1 by Matthews & Russell (1967),
b) Vol. 5 by Earlougher, Jr. (1977), and c) Vol. 23 edited by Med Kamal (2009).
5. SPE Textbook Series on Well Testing vol. 1 by John Lee (1982)
6. Ramey, Henry J., Jr., Agarwal, Ram G., and Martin, Ian:”Analysis of ‘Slug Test” or DST Flow
Period Data, J. Cdn. Pet. Tech. (July-Sept 1975) 37-42.
2.4.3 References
1. Oman, Kurdistan, and India Model PSC agreements.
Operator could accelerate the Front-End Engineering and Design (FEED) studies and plan
a staged development, with an early production system that expedites first production.
Operator could develop a contracting and procurement strategy that prioritizes activities
such as ordering long lead items well in advance of production.
Both the Operator and Government should adhere to the PSC specified timelines.
Government should expedite the review and approval process and the issuance of permits
and approvals.
2.5.3 References
1. Kurdistan, Indonesia and India Model PSC agreements.
2.6.3 References
1. Production sharing agreements for Kurdistan, Mozambique, Indonesia, India, Oman.
Appraisal
3.1 Best Practices Regarding Various Methods of Appraisal
Considering the Extent of Reservoir, Hydrodynamic Systems and
Connectivity, and Different Fault Blocks
3.1.1 Definitions and Discussion
“Appraisal” is the assessment of exploration prospects after a discovery of Petroleum with
the aim to better define the parameters of the Petroleum and the reservoir to which the
discovery relates. The appraisal phase takes place following discovery of oil or gas, upon
which the Operator requires further information about the extent of the deposit or its
production characteristics to determine whether it can be commercially exploited.
Prospecting, exploration and appraisal operations are conducted so as to ensure that good
quality data is acquired, within reasonable economic and technical constraints. Sufficient
data needs to be gathered to test the understanding of the reservoir and to minimize
uncertainties that affect the success of petroleum recovery.
During appraisal, more wells are generally drilled to collect information and samples from
the reservoir. Additional seismic surveys might also be acquired in order to better image
the reservoir. These activities can take several years and cost tens to hundreds of millions
of dollars. More seismic surveys and wells help petroleum geologists, geophysicists and
reservoir engineers to better understand the reservoir. For example, they try to find out
whether rock or fluid properties change away from the discovery well, how much oil or gas
might be in the reservoir, and how fast oil or gas will move through the reservoir. The
prospective development can successfully move past the appraisal stage if a company
decides that the oil or gas fields can be develop economically. One risk that companies face
is that, even after investing time and money in the appraisal stage, they may not find a way
to develop the field profitably and responsibly.
In addition to drilling appraisal wells and furthering geological and geophysical testing, the
appraisal and evaluation phase typically includes conducting detailed engineering studies
to determine the nature and extent of the reserves potential and the formulation of a plan
for developing and producing the potential reserves in order to obtain maximum economic
recovery. Marketing studies may also be necessary, especially in the case of gas discoveries,
in order to evaluate transportation costs and market price potential.
In operations in the United States, especially in areas with a history of production, when an
exploratory well discovers hydrocarbons, the company may briefly evaluate the results of
drilling and then move directly into development. This is particularly likely in onshore
operations in locations where an transportation and marketing infrastructure exists. In U.S.
domestic offshore operations, the market and transportation infrastructure may also be in
place; however, drilling of additional wells may be necessary in order to determine whether
the potential reserves are sufficient to warrant construction of a production platform,
additional pipelines, and/or onshore facilities to handle the production. If additional wells
are drilled in order to determine whether potential reserves are sufficient to justify installing
the necessary infrastructure, they are often treated as a part of the exploration phase.
In operations outside the United States, the appraisal and evaluation phase is more likely to
be necessary and is much better defined. Production sharing contracts and risk service
agreements often specify certain appraisal activities that must be carried out by the
contractor in the event that an exploratory well results in a discovery.
The Appraisal Report shall include all available technical and economic data relevant to the
determination of commerciality. An appraisal report shall include but not be limited to the
following information:
o Geological and petrophysical characteristics of the discovery;
o Estimated geographical extent of the discovery;
o Thickness and extent of productive layers; depth of pay zones;
o Pressure, volume and temperature data (PVT);
o Productivity index of wells tested; anticipated production performance;
o Recovery drive characteristics;
o Characteristics and quality of petroleum discovered;
o Preliminary estimates of Hydrocarbons in place and reserves;
o Enumeration of other important characteristics and properties of the deposits and
fluids discovered;
o Preliminary economic study with regard to the exploitation of the discovery;
o Technical and economic feasibility studies relating to processing and transport of
petroleum from the location; and
o Additional information and assessments as required.
The purpose of Appraisal is to establish the size and commerciality of the discovery. This
can involve several activities including additional seismic work, longer-term flow tests, or
the drilling of further wells. Sufficient data needs to be gathered to test the understanding
of the reservoir and to resolve uncertainties that may affect the success of development of
the discovery.
During the Appraisal phase, good practice will normally require that all the information
needed to determine the most appropriate development has been gathered and analyzed
properly. This will allow for consideration of all realistic options for field development,
including the application of new or innovative technology.
Good industry practice may include activities designed and conducted to maximize data
gathering for maximum economic petroleum recovery and minimum wastage within
reasonable technical and economic constraints. Such activities may include:
o Drilling of additional wells
o Long term flow test and Pressure Transient Analysis (PTA)
o Additional 2D/3D seismic acquisition
o Reprocessing, reinterpretation and remapping of proposed development area
o Rock and fluid sampling and analysis
o Interference test between two wells to determine pressure communication across a
fault
o Drilling a well at the flanks to predict aquifer behavior or to test injectivity in the
water leg
The purpose of appraisal is to better establish the size and commerciality of the discovery.
Different methods and techniques, including the use of new innovative technologies, should
be acceptable if they can accomplish the goal of the appraisal phase. As discussed above,
different tests and data may be required to determine the size of the discovery and its
commerciality. The international practice is geared toward achieving the ultimate objective
rather than to follow any particular approach.
3.1.3 References
1. Hydrocarbon Exploration and Production by Frank Jahn, Mark Cook and Mark Gaham.
2. Planning and practice guidance for oil and gas. Published by the Government of UK.
3. Guidelines published by the Government of UK for onshore and offshore oil and gas field
development plans.
4. Upstream Petroleum Operations by Wright.
“Exploration operations” are defined in the Indian model PSC as operations conducted in
the Contract Area in search of Petroleum and in the course of an Appraisal Program and
shall include but not be limited to aerial, geological, geophysical, geochemical,
palaeontological, palynological, topographical and seismic surveys, analysis, studies and
their interpretation, investigations relating to the subsurface geology including structural
test drilling, stratigraphic test drilling, drilling of Exploration Wells and Appraisal Wells
and other related activities such as surveying, drill site preparation and all work necessarily
connected therewith that is conducted in connection with Petroleum exploration.
“Exploratory Well” means a well drilled in the course of Exploration Operations and whose
purpose at the commencement of drilling is to explore for an accumulation of petroleum
whose existence was at the time unproven by drilling.
“Appraisal Area” means an area within the Contract Area encompassing the geographical
extent of a Discovery that is subject to an Appraisal work program and corresponding
budget in accordance with the terms of the PSC.
The contract holder or operator may also elect when submitting the program to:
o Continue with the exploration work program over the remainder of the Contract
Area, or
o Relinquish the areas not required for the appraisal of the discovery
In certain situations, it may be difficult to be precise about the actual limits of a field before
the appraisal work is completed. In such scenarios, Operator or permit holder may be
allowed a reasonably adequate area to enable it to appraise the discovery.
The general practice is to allow the permit holder to continue with exploration activities in
conjunction with the appraisal of a Discovery during contract period.
3.2.3 References
1. Production sharing contracts/concession agreements for Kenya, Angola, Kurdistan, Oman,
Tanzania, Liberia, Ghana, Indonesia, Brazil
2. Minerals Program regulations in New Zealand
3. Activities and Guidelines on upstream oil and gas activities in China
4. Petroleum Regulations of the Republic of Equatorial Guinea
“Appraisal Program” means an approved work program and budget prepared for the
purpose of Appraisal.
The objective of the Appraisal phase is to reduce uncertainty related to the discovery by
confirming and evaluating the presence extent and how potential of hydrocarbons that have
been indicated by previous exploratory drilling, well testing and other G&G studies. The
appraisal phase can involve several activities including additional seismic work, long-term
flow tests or the drilling of further wells. Appraisal activities should be based upon the
information required to reduce uncertainty.
“Exploration operations” are defined in the Indian model PSC as operations conducted in
the Contract Area in search of Petroleum and in the course of an Appraisal Program that
shall include but not be limited to aerial, geological, geophysical, geochemical,
palaeontological, palynological, topographical and seismic surveys, analysis, studies and
their interpretation, investigations relating to the subsurface geology including structural
test drilling, stratigraphic test drilling, drilling of Exploration Wells and Appraisal Wells
and other related activities such as surveying, drill site preparation and all work necessarily
connected therewith that is conducted in connection with Petroleum exploration.
“Unconventional hydrocarbons” refers to oil and gas having an unconventional source and
entrapped in unconventional reservoir rocks.
o Well tests may be carried out in the appraisal or exploratory wells to gain a better
understanding of the reservoir.
o Extended Well Tests (EWT) may also be authorized if it can be demonstrated that
this will result in better technical understanding or confidence in the performance
of the field needed to assess commercial potential. EWTs should have realistic and
definable appraisal objectives essential to the success of a development.
o The revenue from the produced oil called “Test Oil” may be shared between the
parties. The sharing of revenue is as per PSC guidelines.
In certain situations, an interference test between two wells may be used to determine
pressure communication across a fault.
Conducting supplementary studies and acquisition of geophysical and other data, as well as
the processing of same data.
In addition to drilling appraisal wells and further geological and geophysical testing, the
appraisal phase typically includes conducting detailed engineering studies to determine the
nature and extent of the reserves and the formulation of a plan for developing and producing
the reserves in order to obtain maximum economic recovery.
Marketing studies may also be necessary, especially in the case of gas discoveries, in order
to evaluate transportation costs and market price potential.
The pre-development field activities such as drilling of new wells, testing of existing wells,
geological/geophysical surveys, etc., that are needed for improved understanding of
reservoir parameters should be allowed if they assist in achieving the goal of the appraisal
phase.
The international practice with regard to “Test oil” is that if DoC has been approved, then
the revenue can be shared between the parties as per PSC guidelines. The same may be
followed here.
3.3.3 References
1. Hydrocarbon Exploration and Production by Frank Jahn, Mark Cook and Mark Gaham
2. Planning and practice guidance for oil and gas. Published by the Government of UK
3. Guidelines published by the Government of UK for onshore and offshore oil and gas field
development plans
4. Production sharing contracts/concession agreements for Kenya, Angola, Kurdistan, Oman,
Tanzania, Liberia, Ghana, Indonesia, Brazil
Pay summary table with Gross thickness, Net Pay thickness in MD,
TVD/TVDSS, average effective porosity, average water saturation,
HCPT, cut-off values for Vcl, PHIE and Sw, and fluid contacts
P/Z inputs and gas deviation factor (Z) for gas reservoirs
Forecasted production profiles (oil/gas/water production/injection rates,
watercut, GOR/CGR, cumulative production/injection, reservoir pressure
and decline rate considered along with basis/assumptions)
Map of well locations with 1P/1C/P90, 2P/2C/P50 and 3P/3C/P10 polygons
In addition to the recommended data for submission with the DoC Report, the following
additional data is recommended for submission with subsequent FDP Report
o Geology and Geophysics data
All details of additional data/information/analyses generated since DoC
report submission
Any revisions to defined development area
o Petrophysical data
All details of additional data/information/analyses generated since DoC
report submission
o Reservoir data
All details of additional data/information/analyses generated since DoC
report submission
4.1.3 Recommendations
The data requirements at the time of submission of DoC and FDP reports have been outlined
as best practices and are recommended for India.
4.1.4 References
1. Production sharing contracts from Oman, Indonesia, Kurdistan, Iraq, and India
2. Directorate General of Hydrocarbons “Guidelines for evaluation of Declaration of
Commerciality (DoC), Field Development Plan (FDP) & Well locations.
DGH/FDP/Checklist/14, November 11, 2014.
Many fiscal regimes include a cost recovery mechanism to allow the contractor to recover costs
associated with exploration, appraisal, development and production. In the case of marginal fields
with large sunk costs (such as an extensive exploration program), the resulting percentage of gross
production obtained by the government after cost recovery can be greatly reduced. This is more of
an issue with progressive regimes where government take is based more on profitability than gross
revenues (Johnston, 1994). Progressive and regressive fiscal policies are summarized in the figure
below from Johnston’s book.
In order to receive a minimum desired percentage of gross production, many countries have
adjusted the terms of their fiscal agreements accordingly. An example is the addition of a royalty
payment (or First Tranche Petroleum in Indonesia) to assign a fixed percentage of gross production
to the government before cost recovery deductions. Another example is limiting cost recovery to a
certain percentage of gross production (such as 60% in Oman), ensuring a portion of production
carries through to the production split between government and contractor.
However, in cases where the volume of hydrocarbons discovered is small or in mature fields where
profitable production is no longer achievable under the terms of the PSC, certain strategies must be
employed in order for profitable development to occur. Either the terms of the PSC could be relaxed
to provide additional economic incentive, or the discovery or field could lay idle until a time where
increases in oil or gas prices or enhancements in engineering technologies improve project
economics.
For oil/gas importing countries, it may be best to incentivize development of marginal fields
through relaxed/amended PSC terms, resulting in the direct benefits of additional government
revenues and reduced reliance on imports as well as the indirect benefits of jobs and income into
local communities.
Some countries include a clause in their agreements allowing for the terms of the contract to be
revisited in the case of marginal fields. In this scenario, the Contractor/Operator is to give notice
and consult with the Government concerning any alterations to the terms of the PSC which would
permit commercial development of the marginal field.
This has been practiced in Nigeria where an aggressive campaign targeting marginal fields began
in 2010. 116 oil and gas fields have been classified as marginal fields and have been targeted for
incentivized development by qualified companies. As an additional stimulus to development of
these marginal fields, the government has granted a number of fiscal incentives such as lower
sliding scale royalties and substantially reduced petroleum profit taxes.
Another way to incentivize development of marginal fields is to manage the existing inventory of
processing and transportation facilities and infrastructure to arrange access for marginal fields to
reduce the costs of bringing these fields to production. The US and UK-Norwegian Code of Practice
are examples of regional/national infrastructure sharing systems. Sharing of infrastructure is
discussed in Section 10.2 of this report.
Apply these principles to include stranded discoveries, especially in DW, UDW, HPHT,
Difficult areas
4.2.3 References
1. Johnston, Daniel. 1994. International Petroleum Fiscal Systems and Production Sharing
Contracts. Tulsa, OK. PennWell Publishing Company.
2. Production sharing contracts for Indonesia and Oman.
3. www.spe.org
4. Nigeria Oil and Gas: Marginal Fields. March 2014.Ashurst London.
5. Manaf et al. 2014. Effect of Taxation and Fiscal Arrangement on Marginal Oil Field
Investment Climate: A Theoretical Framework.
6. Mart Resources: http://www.martresources.com/operations/introduction-to-nigeria/
PRMS definitions
“Prospective Resources” are those quantities of petroleum that are estimated, as of a given
date, to be potentially recoverable from undiscovered accumulations.
Range of Uncertainty
o In PRMS, the range of uncertainty is characterized by three specific scenarios
reflecting low, best, and high case outcomes from the project. The terminology is
different depending on which class is appropriate for the project, but the underlying
principle is the same regardless of the level of maturity. In summary, if the project
satisfies all the criteria for Reserves, the low, best, and high estimates are designated
as Proved (1P), Proved plus Probable (2P), and Proved plus Probable plus Possible
(3P), respectively. The equivalent terms for Contingent Resources are 1C, 2C, and
3C, while the terms “low estimate,” “best estimate,” and “high estimate” are used
for Prospective Resources. The three estimates may be based on deterministic
methods or on probabilistic methods.
o While estimates may be made using deterministic or probabilistic methods, the
underlying principles must be the same if comparable results are to be achieved. It
project, even though the 2C level is commercially viable. It is not uncommon, for
example, for a company to first test that the 2C estimate satisfies all their corporate
hurdles and then, as a project robustness test, to require that the low (1C) outcome
is at least break-even. If the project fails this latter test and development remains
contingent on satisfying this break-even test, further data acquisition (probably
appraisal drilling) would be required to reduce the range of uncertainty first. In such
a case, the chance of commerciality is the probability that the appraisal efforts will
increase the low (1C) estimate above the break-even level, which is not the same as
the probability (assessed before the additional appraisal) that the actual recovery
will exceed the break-even level. In this situation, because the project will not go
ahead unless the 1C estimate is increased.
o As mentioned above, there is no industry standard for the reporting of Contingent
Resource estimates. However, the commercial risk associated with such projects can
vary widely. If Contingent Resources are reported externally, the commercial risk
can be communicated to users (e.g., investors, Governments, etc.) by various means,
including: (1) describing the specific contingencies associated with individual
projects; (2) reporting a quantitative chance of commerciality for each project;
and/or (3) assigning each project to one of the Project Maturity Subclasses.
The PRMS guidelines have been sponsored by SPE, AAPG, WPC, SPEE and SEG and are
viewed internationally as the recommended best practice for classification and evaluation
of resources and reserves. It is therefore recommended that India adopt the PRMS
guidelines.
It is recommended that reporting and auditing of oil and gas reserves should be performed
by reputable National or International agencies.
o For publicly traded companies, auditing should be performed annually or as per the
requirements of the Government.
o For private companies, auditing should be performed on an as-needed basis.
Changes in Reserves estimate may be acceptable based on new data and fulfillment of
PRMS guidelines
4.3.3 References
1. Guidelines for Application of the Petroleum Resources Management System. November
2011. http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf
economically producible—from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations—prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable time.
The reliable technology concept permits companies to prepare their reserve estimates using
new types of technology that companies were not permitted to use under the previous rules;
The new definition of reliable technology permits the use of technology (including
computational methods) that has been field tested and has demonstrated consistency and
repeatability in the formation being evaluated or in an analogous formation;
An example (the only example in the SEC commentary) of reliable technology is a
combination of seismic data and interpretation, wireline formation tests, geophysical logs,
and core data to estimate reserves;
Use of reliable technology is a necessary condition for classification of resources as
reserves;
Reliable technologies can be used to establish the reasonable certainty of proved reserves;
Reliable technologies can be used to establish lowest known oil and highest known oil and
can be added to well penetrations as acceptable ways to establish these levels;
Reliable technology can be used to establish reasonable certainty of “undeveloped oil and
gas reserves” in improved recovery projects as an alternative to requiring evidence from
projects in the same reservoir or an analogous reservoir;
Required disclosures of reliable technology will be limited to a concise summary of the
technology or technologies used to create the estimate; and
A company will not be required to disclose proprietary technologies, or a proprietary mix
of technologies, at a level of specificity that would cause competitive harm.
4.4.3 References
1. SEC regulations
2. Lee, J. The “Reliable Technologies” Rule: What Did the SEC Intend? Presented at Offshore
Technology Conference, Houston, Texas, USA, 3-6 May 2010. OTC 20379.
Field Development
5.1 International Norms for Monetization of Reserves in
Probable & Possible Categories
Descriptions
A Field Development Plan means a plan submitted by the contractor for the development
of a commercial discovery, which has been approved by the competent authority pursuant
to the relevant provisions of the contract. All Reserves and Resources definitions are to be
governed by prevailing SPE Petroleum Resource Management System (PRMS).
All FDPs should contain an agreed plan for the commissioning and production phases of
the development. The plan should set out the principles and objectives on which continuing
technical analysis and data gathering shall be conducted, based on which field management
decisions will be taken.
During field development, the Contractor/Operator may gain additional knowledge which
may justify development of reserves earlier classified under probable and possible
categories. In this scenario, a revised & commercially viable Field Development Plan is to
be prepared which identifies deviations from the agreed plan and proposes revised
approaches to field development and management.
However, under certain conditions, further phases of development may be required with
substantial alterations to the original development strategy, or major changes may be
required to existing or new facilities. In these conditions, a more formal revision to the
relevant sections of the Field Development Plan may be required and agreed upon by the
Contractor/Operator and the government agency.
The FDP should include sensitivities to show alternate development scenarios in case of
additional reserves are to be developed at a later stage.
In case of a high degree of confidence on the part of the Operator, the Operator may provide
a plan for facilities to accommodate 3P reserves. Such a plan should be staged in a way to
minimize economic risk. The regulatory body may decide to approve the cost of only the
facilities associated with the 2P reserves in the beginning and provide further approvals as
the 3P reserves move to 2P and 1P categories.
5.1.3 References
Petroleum Resource Management System, 2007, Richardson, Texas,
http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf
Secondary recovery involves the injection of an injectant (typically water or gas) to re-
pressurize the reservoir and displace the oil. Waterflooding is the most common secondary
recovery method but gas re-injection for pressure maintenance is also considered a
secondary method.
Enhanced oil recovery (EOR) comprises of reservoir processes that recover oil left behind
by secondary recovery. EOR processes focus on rock/oil/injectant system and the interplay
of viscous and capillary forces.
Improved oil recovery (IOR) is defined as any practice that is used to increase oil recovery.
This can include secondary and tertiary recovery processes (EOR) as well as practices to
increase sweep such as infill drilling, horizontal wells and polymers to increase
conformance.
The implementation of EOR is intimately tied to the price of oil and overall economics.
EOR is both capital and human resource intensive, primarily due to high injecting costs and
the additional levels of analysis and operations required. The timing of EOR is also
important: a case is made that advanced secondary recovery (e.g. IOR) technologies are a
better first option before full-field deployment of EOR. Realization of EOR potential can
only be achieved through long-term commitments, both in capital and human resources, a
vision to strive towards ultimate oil recovery instead of immediate oil recovery, research
and development, and a willingness to take risks. While EOR technologies have grown over
the years, significant challenges remain.
One of the emerging EOR techniques is Smart Water Flooding. Here, the idea is to inject
water with an optimized composition (in terms of salinity and ionic composition) into the
reservoir instead of any available water that may currently be injected or planned to be
injected. Recent research has shown that salinity and/or ionic composition can play a
significant role in oil recovery during water flooding and may yield up to 10 per cent or
higher additional oil recovery when compared to un-optimized water injection. This option
has several advantages compared to conventional EORs:
o It can achieve higher ultimate oil recovery with minimal investment in current
operations (this assumes that a water flooding infrastructure is already in place). The
advantage lies in avoiding extensive capital investment associated with
conventional EOR methods, such as expenditure on new infrastructure and plants
needed for injectants, new injection facilities, production and monitoring wells,
changes in tubing and casing, etc.
o It can be applied during the early life cycle of the reservoir.
o The payback is faster, even with small incremental oil recovery.
Another aspect of water flooding that can be improved is the monitoring and surveillance
(M&S) of projects. In many cases, adequate monitoring is not done because of the cost
involved. This may be detrimental to the overall recovery during water flooding. While an
optimum M&S plan cannot be predetermined for a given reservoir, some of its components
include: the time-tested open/cased hole logging, coring, flood-front monitoring, single and
inter-well tracer tests, and emerging technologies, such as: borehole gravimetry, cross-well
and borehole to surface electromagnetic (EM), and geophysical methods (cross-well
seismic, 4D seismic and 4D vertical seismic profiler (VSP)). A good M&S plan is essential
in optimizing oil recovery at the secondary recovery stage, and even more important during
the EOR phase.
Choice, timing, and strategy of secondary or tertiary recovery should be based on reservoir
characteristics and project economics;
Any plans to accelerate production should not cause a decrease in ultimate recovery. For
example, producing a reservoir at very high rates without increased injection support will
cause a surge in oil production rate, but ultimate recovery will be sacrificed as the reservoir
pressure decreases. So optimal bean size as is worked out during Initial Production Testing
be used during production in order to conserve reservoir energy.
As the easy and conventional light oil gets depleted, the focus should move towards more
difficult hydrocarbon resources, like heavy and extra heavy crudes, oil sands, bitumen and
shale oil.
Investment in R&D may be essential to generate the right options for field development in
certain cases.
EOR implementation may be aided by a company’s or country’s need for energy security
concerns.
Environmental concerns are important factors that have boosted EOR in recent years. For
example, CO2-EOR projects are implemented to sequester CO2, a greenhouse gas.
The objective of any FDP should be to maximize the ultimate oil recovery from the field
within an economic threshold.
For oil fields, FDPs should include a techno-economic evaluation of a secondary recovery
project. Example of secondary recovery projects that could be included are water flooding,
gas injection project, etc. that provide improved sweep and/or pressure maintenance.
Reservoir health being the primary issue during exploitation, pressure maintenance
measures to be taken up before the setting in of Bubble Point Pressure to maximize the
recovery based on economic viability
IOR/EOR processes should be encouraged and may be evaluated during the FDP stage to
avoid causing long term damage to the reservoir and at the same time maximizing recovery.
The process of pressure support should be considered and implemented in the field as early
as possible.
5.2.3 References
1. Stosur, G.J., Hite J.R., Carnahan N.F., Miller K., The Alphabet Soup of IOR, EOR
and AOR: Effective Communication Requires Definitions of Terms, SPE-84908,
presented at SPE International Improved Oil Recovery Conference in Asia Pacific
held in Kuala Lumpur, Malaysia, 20-21 October 2003.
2. Enhanced Oil Recovery Program Guidelines,
http://www.energy.alberta.ca/Oil/docs/EORP_Guidelines_2014.pdf
3. Kokal, Sunil, and Abdulaziz Al-Kaabi. "Enhanced oil recovery: challenges &
opportunities." World Petroleum Council: Official Publication (2010): 64-68.
The authorities want to emphasize that the resource base and the technical solutions, as
well as the economic estimates, must be sufficiently well-prepared. Estimates should be
made that highlight the uncertainties that are critical for the project. The plan(s) should
also contain an overview of future business opportunities that can provide a basis for
changes in the scope of investments.
Production strategy
o Describe the selected production strategy for the field
Within the PSC specified timeframe, the Contractor/Operator should provide a detailed
field development plan to the authorities for approval in a timely manner.
The Operator should plan properly for equipment, logistics, etc. and not delay
implementation of the approved FDP as per the agreed timeline. Substantial deviation
from the approved plan should require approval from authorities.
5.3.3 References
1. Plan for development and operation of a petroleum deposit (PDO) and plan for
installation and operation of facilities for transport and utilization of petroleum (PIO).
4 February 2010.
2. Guidance notes for onshore oil and gas field development plans, https://www.gov.uk/oil-
and-gas-fields-and-field-development.
It avoids the economic waste of unnecessary well drilling and construction of related
facilities that would otherwise occur under the competitive rule of capture.
It maximizes the ultimate recovery of petroleum from a field according to the best
technical or engineering information, whether during primary production operations
or enhanced recovery operations.
It gives all owners of rights in the common reservoir a fair share of the production.
It minimizes surface use of the land and surface damages by avoiding unnecessary
wells and infrastructure.
Definitions:
5.4.3 References
1. Unitizing Oil and Gas Fields around the World: A Comparative Analysis of
National Laws and Private Contracts.
Production
6.1 International Practices for Submitting Long Term Production
Profile and Medium Term Production Forecast and Mid-
Course Changes
6.1.1 Definitions and Discussion
The assumptions underlying the long-term and short term forecasts should be explained.
Short-term injection and production profiles should be updated yearly. Any changes,
whether increases or decreases, in the profiles should be explained.
Proposed changes in the Field Development Plan should be clearly documented and
justified based on technical studies and analysis. Where appropriate, a discussion of
additional longer-term development opportunities should be provided.
6.1.3 References
The UK Department of Energy and Climate Change (DECC) lists requirements for
onshore oil and conventional gas field development plans in their document “Guidance
Notes for Onshore Oil and Gas Field Development Plans (October 2009)”.
Differences between the actual and forecasted production volumes should be explained.
Likewise the reasons for overproduction may also be provided; to evaluate that the
overproduction is not at the cost of reservoir health.
Any recommendation for remedial action should include an estimate of the incremental
/ sustained volume of hydrocarbon that will be produced due to the remedial action.
6.2.3 References
1 The UK Department of Energy and Climate Change (DECC) lists requirements for
onshore oil and conventional gas field development plans in their document “Guidance
Notes for Onshore Oil and Gas Field Development Plans (October 2009)”. The section
on “Annual Field Reports” addresses issues related to deviations from the agreed FDP.
2 Natalya Morozova, “Chapter 20: Subsoil Law”, in ‘Doing Business in Russia’, Vinson
& Elkins LLP, 2009.
3 “Draft Model Revenue Sharing Contract (MRSC)”, Directorate General of
Hydrocarbons, Ministry of Petroleum and Natural Gas, Government of India.
4 Marcia Ashong, “Cost Recovery In Production Sharing Contracts: Opportunity For
Striking It Rich Or Just Another Risk Not Worth Bearing”. Dundee, CEPLMP, 2009.
Many aspects of well completion design are the same for onshore, offshore, deepwater, and
ultra-deepwater wells, although additional requirements may apply depending as per well
requirements.
No industry standard depth specification exists for deepwater and ultra-deepwater, although
the following depths are generally accepted. Governments sometimes specify the depth
requirements when these wells/developments receive favorable treatment in the PSC.
o Deepwater – distance from sea level to seafloor greater than 400 m (~ 1200 ft)
o Ultra-deepwater - distance from sea level to seafloor greater than 1500 m (~5000 ft)
Well completion design and execution is based on the reservoir context, technical
feasibility, safety, economic viability, operability and all relevant risk, reliability and
assurance analysis. The requirements are field and / or well-specific.
The well completion generally allows access for rig / rigless intervention methods such as
slickline, wireline, and coiled tubing operations etc. This requirement may be reviewed and
waived depending on the economics. However while doing so; safety aspects should be
kept in mind.
o Well casing and tubing strings must meet technical requirements for the environment
and life of the well.
Artificial lift
o The need for artificial lift should be determined according to the field development plan,
production rate forecasts, and the feasibility of artificial lift methods such as sucker rod
pumps, electric submersible pumps, progressive cavity pumps, gas lift, plunger lift, and
jet pumps, ESP, PCP, etc.
o When artificial lift methods are used, the equipment should comply with industry
standards (API, ISO etc).
o The type of artificial lift should be chosen according to well rates, fluid types, power/lift
fluids available, and field development economic analysis etc
Well completion materials selection should follow the relevant standards (NACE, API,
ISO, etc) based upon services / production environment.
6.3.3 References
1 NORSOK Standard D-010, “Well Integrity in Drilling and Well Operations”, August,
2004.
2 List of ISO standards related to well completions:
ISO 10405:2000 Petroleum and natural gas industries -- Care and use of
casing and tubing
ISO 10428:1993 Sucker rods (pony rods, polished rods, couplings and sub-
couplings) – Specification
ISO 11960:2014 Steel pipes for use as casing or tubing for wells
ISO 13678:2010 Evaluation and testing of thread compounds for use with
casing, tubing, line pipe and drill stem elements
ISO 15136-1:2009 Progressing cavity pump systems for artificial lift -- Part
1: Pumps
ISO 15136-2:2006 Progressing cavity pump systems for artificial lift -- Part
2: Surface-drive systems
ISO 15463:2003 Field inspection of new casing, tubing and plain-end drill
pipe
ISO/TS 16530-2:2014 Well integrity -- Part 2: Well integrity for the operational
phase
Proppant is used to keep the fracture open after the fracture is created, providing a high
conductivity conduit to the wellbore. Proppant can be natural sand or synthetic ceramic
proppant. The proppant type and size is selected to achieve the desired fracture
conductivity.
Acid fracturing is fracturing with acid as the injected fluid—proppant is not used.
Fracture conductivity is created by acid etching of the fracture face.
Well stimulations
The need for well stimulation should be determined in accordance with the field
development plan and required well rates.
o Hydraulic fracturing
Hydraulic fracture design computer models should be used to design and
execute the stimulation job. Injection pressures, rates, and fluid properties
should be monitored and recorded during the job.
o Acid stimulation
Matrix acid stimulations may be performed to remove mud damage and/or provide
near wellbore permeability enhancement. The acid pumping pressure is below
fracture pressure.
Rock mineralogy should be considered in acid treatment designs. Iron control agents
and other chemicals may be required.
Acid fracture fluids with proppant are not recommended. Acid treatment releases
fine particles that plug the proppant, reducing conductivity.
Acid treatment in sandstone formations releases fine particles or insoluble
precipitates that may plug the pore throats and reduce near wellbore conductivity.
In some cases, live or spent acids may generate emulsions and/or sludge with the
crude oil present in the reservoir. Therefore, the acid formulation should be
compatible to the reservoir rock as well as reservoir fluids. Special additives such
as clay stabilizer, anti-sludge agent may be required to carry out effective treatment.
Acid fracturing is used in carbonate formations and normally not effective in
sandstone formations. Acid fracturing treatments involves a high viscous fluid for
creating fracture in the reservoir followed by pumping of suitable acid formulations
at high rate and pressure.
Adequate precaution to be taken in handling of acid and other hazardous chemicals
used for acid treatments.
All the surface pumping lines should be pressure tested and provide adequate
bonding and grounding of manifold, high pressure pumping lines etc.
Allow only the authorized and experienced personnel in the well site.
Wear proper PPE including fall protection and respiratory protection where
appropriate.
Planning of workovers, well interventions, and stimulations should consider the reservoir
context, technical feasibility, economic viability, safety, operability, and all relevant risk,
reliability, and assurance analysis.
The techniques used should follow the best practices described above and continue to
evolve as new technology is developed.
6.4.3 References
1. “Hydraulic Fracturing”, Petroleum Engineering Handbook, SPE
2. “Effects of Water Depth on Offshore Equipment and OperationsTopic #3: Well Drilling
& Completion Design and Barriers”, Proceedings of Effects of Water Depths
Workshop, U.S. Bureau of Safety and Environmental Enforcement, Galveston, Texas,
November 2-3, 2011.
3. Drilling and well-servicing equipment, ISO 14693:2003.
4. Design and operation of subsea production systems -- Part 4: Subsea wellhead and tree
equipment, ISO 13628-4:2010.
5. Design and operation of subsea production systems -- Part 7: Completion/workover
riser systems, ISO 13628-7:2005.
6. “IRF Performance Measurement Project”, International Regulator’s Forum
(www.irfoffshoresafety.com)
Basic sediment and water (BS&W) is the percent by volume of water and solid
impurities in the oil.
Safety systems
o All facilities require safety systems based on field requirements, location,
environment, and as per the relevant safety standards such as DGMS, OISD, API,
NACE, ASME, BIS, ISO etc.
Oil processing
o Oil facilities separate the oil, gas, water, and solids; measure and sample the
oil to determine its value; and deliver it to the transportation system (i.e.,
pipeline, truck, ship, or railroad car); treat the oil to meet sales specifications.
o The contract between the oil seller (normally the producer) and the purchaser
(a pipeline company or refinery) specifies the allowable water content, and
may specify the maximum salt content in the crude oil.
o The liquid stream is generally stabilized, by removing light hydrocarbons,
to meet vapor pressure limits for storage in tanks for shipping at atmospheric
pressure by truck, train, barge, or ship without excessive vapor venting.
Gas processing
o Gas is treated for sales, internal consumption, gas lift, or reinjection. This
may involve only separation from the liquids or may include additional
processes such as compression, dehydration, removing H2S and CO2 etc.
o The amount of water vapor in the sales gas is usually limited by pipeline
specifications, in order to avoid corrosion and hydrate-formation problems.
A standard pipeline specification is 7 lbm of water per million standard cubic
feet of gas (lbm/MMscf). This corresponds to a water dew point of
approximately 32°F at 1,000 psi.
Water processing
o Water treatment facilities depend upon the inlet effluent characteristics and
the local statutory requirements to disposal, as a minimum, to be adopted.
Offshore facilities
o Types of offshore platforms:
o Differences between the process equipment (oil and gas separators, free-
water knockouts, gas scrubbers, pumps, compressors, etc.) installed on a
platform and those installed on land are minor. Consideration is given to
using vessels and machinery that are compact and lightweight (e.g., electric
motors are commonly used instead of gas engines for driving pumps and
compressors). Vertical clearance between decks may impose height
limitations and dictate equipment choices such as the use of horizontal
instead of vertical separators.
o Offshore process equipment is often packaged in modules for ease of
installation. This also reduces space and weight requirements.
Subsea/Deepwater facilities
o Conceptual subsea processing facility:
o Produced fluids flow to a host facility for processing and export. They may
flow unassisted or with the assistance of multiphase pumps. Alternatively,
subsea separation allows single-phase pumping of liquids.
o Utilities, control lines, and chemicals are supplied from the host facility via
umbilicals.
o The need for subsea processing is driven by economic evaluation of factors
such as lower wellhead pressure, water depth, tieback distance, and
processing capacity of topside facilities.
Safety and environmental protection should be incorporated into the design of every
facility and process.
6.5.3 References
1 “Oil and Gas Processing”, Petroleum Engineering Handbook, SPE.
2 RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic
Surface Safety Systems for Offshore Production Platforms, API.
3 “Safety Systems”, Petroleum Engineering Handbook, SPE.
ISO 21457:2010 Materials selection and corrosion control for oil and gas
production systems
ISO 12736 Wet thermal insulation coatings for pipelines, flow lines,
equipment and subsea structures
ISO 15761:2002 Steel gate, globe and check valves for sizes DN 100 and
smaller, for the petroleum and natural gas industries
ISO/AWI 18796 Internal coating and lining of carbon steel process vessels
ISO 25457:2008 Flare details for general refinery and petrochemical service
prior to custody transfer (or consumption). Also called Point of Sale or Custody Transfer
Point.
Gas metering: The metering of hydrocarbon gas should be dealt in accordance with
relevant AGA gas measurement standards or equivalent standards.
The main international standards for these meters are:
o Orifice meters: ISO Standard 5167 and AGA Standard 3.
o Turbine meters: ISO Standard 9951, Measurement of Gas Flow in Closed
Conduits: Turbine Meters and OIML R32, Rotary Piston Gas and Turbine Gas
Meters.
o Ultrasonic meters: ISO Standard TC30/SC5/WG1 and AGA Report 9 &10,
Measurement of Gas by Multipath Ultrasonic Meters.
o Coriolis meters: ISO Standard TC30/SC12 and AGA Report, Coriolis Flow
Measurement for Natural Gas Applications.
The meter measurements should be within the specified operating range
for the quoted accuracy of the meter.
Measured gas volume should be converted to volume at standard
conditions.
Multiphase meters
o Typically used for replacement of a well test separator rather than for custody
transfer. In some instances of commingled production, they may be used for
production allocation.
o Continually being developed and improved.
o Accuracy is less than single phase meters.
o V-cone meters may be used for wet gas metering in non-custody transfer
applications.
General practice for reconciliation between petroleum produced and stored and
petroleum sold.
o Sales quantities are equal to raw production less non-sales quantities (quantities
that are produced at the wellhead but not available for sales at the Reference
Point).
o Non-sales quantities include petroleum consumed as fuel, flared, lost in
processing, etc. plus non-hydrocarbons that must be removed prior to sale. Each
of these non-sales quantities may be allocated using separate Reference Points
but when combined with sales, should sum to raw production.
o All volumes should be reconciled to account for variations in temperature,
pressure, and fluid composition to the Standard Conditions/ Contract conditions.
Meters should meet the appropriate accuracy and specified performance criteria for
custody transfer or field operations management.
Records of metered volumes should be maintained and provided to co-owners and the
appropriate government agency, as required in the field rules.
6.6.3 References
1. Petroleum Engineering Handbook, SPE. Manual of Petroleum Measurement Standards
(MPMS), American Petroleum Institute (API), an ongoing publication in which
chapters are periodically revised and then released.
2. Petroleum Resource Management System. Society of Petroleum Engineers (SPE),
American Association of Petroleum Geologists (AAPG), World Petroleum Council
(WPC), Society of Petroleum Evaluation Engineers (SPEE), 2007.
3. List of related ISO specifications:
Standard Description
number
“Production battery” refers to the collection point where commingled production volumes
are measured.
As per best practices globally, the minimum frequency of production testing is once
every 3 months. However testing frequency may be decided by operators at their own
discretion.
o The resulting well-level oil, water, and gas rates should be checked for GOR
and WOR consistency with the well-test data. Significant deviations between
well-test WOR or GOR and the allocated values will require additional tuning
of the allocation procedure.
When an allocation factor is found to exceed the specified limits, the cause should be
investigated, documented and corrected.
For wells which are completed and commingled in multiple zones, the best-practices
method for back-allocation of production to individual zones is through the use of
production logs. Other acceptable practices for zonal allocation include permeability-
thickness weighting, simulated results, and tracer monitoring.
6.7.3 References
1. “Directive 017: Measurement Requirements for Oil and
Gas Operations”,Alberta Energy Regulator
(www.aer.ca), May 15, 2013.
2. “HM 96: Guidelines for the allocation of fluid streams
in oil and gas production”,UK Energy Institute.
3. “Allocation Measurement”, API MPMS Chapter 20.1
(R2011).
Tanker transportation
o Tanks can be truck-mounted, rail-mounted or ship-mounted, depending on
onshore or offshore location of facilities and transportation routes.
o Tankers must comply with all local road and maritime transportation laws for
hazardous and/or flammable materials. These regulations specify design,
construction, and certification of the tanks. In addition, they specify inspection
and testing requirements for re-certification. Inspections are normally required
at intervals ranging from 2 to 5 years.
o International maritime shipping is governed by the MARPOL convention
(International Maritime Organization) and SOLAS requirements.
o Outlets of road tankers shall be properly sealed after completion of loading and
measurement at Loading Point and the same shall be checked as unbroken prior
to unloading to prevent pilferage. In case the seal is found broken, the transporter
shall be penalized for the shortfall quantity.
o Fluid weight/volume should be measured and recorded when tanker is loaded
and at delivery site before unloading. Any discrepancies should be investigated
immediately.
o Leaks/spill volumes when loading/unloading tankers should be recorded and
reported.
Pipeline transportation
o Operation
Records should be kept of fluid volumes entering and exiting the pipeline and any
discrepancies investigated immediately.
6.8.3 References
1. “Pipeline Design Consideration and Standards”, Petroleum Engineering
Handbook, SPE.
2. Pipeline Pigging, Petroleum Engineering Handbook, SPE.
3. List of related ISO specifications:
ISO/FDIS 1823 Rubber hose and hose assemblies for oil suction and discharge
service – Specification
ISO 12490:2011 Mechanical integrity and sizing of actuators and mounting kits
for pipeline valves
Monthly well-level and zone-level injection and production volumes for oil, water, and
gas should be reported including:
o Unique Well Identifier / Well name
o Field name
o Zone name
o Well type (oil producer, gas producer, water injector, gas injector, etc.)
o Production mechanisms (flowing, gas-lift, ESP, etc.)
o Days on production
o Monthly oil, water, and gas production; monthly water and gas injection
o Average flowing tubing pressure
o Tubing-head injection pressure
o Choke Size
o Any other relevant parameter
Reservoir pressure measurements should also be reported including but not limited to;
o Well name and zone
o Date Tested
o Perforated / completed Intervals
o Shut-In / Flow-In time
o The survey type (SGS, PBU, RFT, DST, PFO, Multi-Rate, etc.)
o The tool depth (TVDSS)
o The datum depth (TVDSS)
o Pressure gradient
o Pressure at tool depth
o Pressure at datum depth.
Fields with continuous down-hole measurements of pressure and well head measurements
should report the relevant data on a monthly basis.
It is preferred that SBHP should be measured at least annually, but not limited to, in key
wells, aerially spread in major pay zones, based on reservoir conditions.
It is good practice to adopt a system for uniquely identifying wells. For example, a system
for assigning unique well identifiers has been implemented for wells within the United
States per API Bulletin D12A. The PPDM (Professional Petroleum Data Management
Association) has published a framework for assigning unique global well IDs.
6.9.3 References
1. The Norwegian Petroleum Directorate (NPD) has published “Guidelines for
Production Reporting” which abide by the PRODML standard.
2. The State of Alaska has published this format for reporting reservoir pressure.
3. “Well Identification Global”, Booklet from the PPDM Association (Sept, 2014).
4. American Petroleum Institute, 1979, The API well number and standard state and
county numeric codes including offshore waters, Dallas, TX, American Petroleum
Institute, API Bulletin D12A.
Nodal analysis is normally used to couple the reservoir inflow with the tubing outflow.
This model would also include any artificial lift methods in the wellbore outflow
calculation.
When possible, the results of nodal analysis modeling should be compared to field
measurements in order to validate the inflow and outflow calculations.
If artificial lift is planned, then nodal analysis and influx studies should be implemented to
help design and optimize the system.
6.10.3 References
1. Bertuzzi et al, “Wellbore Hydraulics”, Chapter 34 in the Petroleum
Engineering Handbook, SPE.
6.11.3 References
“Sampling Petroleum Reservoir Fluids”, API Recommended Practice 44, Second Edition,
April 2003.
“Fluid Properties” for gas refers to the dew-point pressure, solution oil-gas ratio,
formation volume factor, viscosity, specific gravity etc.
“Fluid Properties” for water refer to the formation volume factor, viscosity, density,
isothermal compressibility etc.
PVT studies must include basic quality-control checks including the following, but
not limited to:
o The gas sample should have minimum air content and minimum difference
between gas-bottle opening pressure and the separator pressure for the
recombined PVT sample.
o The oil sample bubble point pressure and bottle opening pressure should be
compared with separator pressure for the recombined PVT sample.
o PVT studies should include a general information sheet with (1) separator
gas/oil ratio (GOR) in standard cubic feet/separator barrel, (2) separator
conditions at sampling, (3) field shrinkage factor used ( = 1/Bo at separator
pressure), (4) flowing bottom-hole pressure (FBHP) at sampling, (5) static
reservoir pressure, (6) minimum FBHP before and during sampling, (7) time
and date of sampling, (8) production rates during sampling, (9) dimensions of
sample container, (10) total number and types of samples collected during the
drill stem test, and (11) perforation intervals and sampling depth (if it is a
bottom-hole sample).
o All laboratory measurements should follow the guidelines in the API “Manual
of Petroleum Measurement Standards (MPMS).”
6.12.3 References
1. API Manual of Petroleum Measurements Standards (MPMS) Chapters 8.1 and 8.2.
2. Whitson, C. H. and Brule, M. R., "Phase Behavior", SPE Monograph Volume 20
SPE (2000).
3. The Properties of Petroleum Fluids by William D McCain Jr
RMP should be part of FDP and shall be updated from time to time as deemed
necessary.
6.13.3 References
1. “Good Engineering Practice Area Application Guideline” from the British
Columbia Oil and Gas Board.
2. “Maximizing Economic Recovery of the UK’s Oil and Gas Reserves” from the UK
PILOT report.
3. “Production Efficiency Guidance Notes”, from the UK Department of Energy and
Climate Change (DECC), January 2010.
6.14.3 References
1. “Subsea and Downhole Processing”, Petroleum Engineering Handbook, SPE.
2. “Well Test- Extended”, Oil and Gas UK, Environmental Legislation Website.
http://www.ukooaenvironmentallegislation.co.uk/contents/topic_files/offshore/ext
ended_welltest.htm
3. "Guidance on the Content of Offshore Oil and Gas Field Development Plans",
United Kingdom Department of Energy and Climate Change (DECC), December
2013.
4. Leeson, T.J., Barr, J. and Selboe, J.O., "Appraisal of Exploration Prospects using
Extended Well Testing", Offshore Magazine, Volume 57, Issue 8, 1997.
5. Si, W., "A Brief Description of Extended Well Testing (EWT) System", SPE 29998,
1995.
6. AXIS Energy Projects, Web-reference: http://www.axis-ep.com/extended-well-
test-export-systems.html.
7. Leeson, T.J., "Extended Well Testing Boosts Prospects For Development of
Marginal Fields", Oil and Gas Journal, Volume 95, Issue 34, August 1997.
8. Earlougher, Robert C., Jr.: Advances in Well Test Analysis, Monograph Series,
Society of Petroleum Engineers of AIME, Dallas (1976) vol. 5.
9. Agarwal, Ram G.: “Direct Method of Estimating Average Pressure for Flowing Oil
and Gas Wells,” paper 135804 presented at the 2010 SPE Annual Technical
Conference and Exhibition, Florence, Italy, Sept. 19-22.
o Records of flaring events and measured / estimated volumes should be kept by the
operator. The regulatory agency may request these records as and when required.
o Design of flare system should be as per DGMS / API / OISD / relevant standards
and as per field requirements
6.15.3 References
o API Recommended Practice RP51R, Environmental Protection for Onshore
Oil and Gas Production Operations and Leases, 2009.
o Flare details for general refinery and petrochemical service, ISO
25457:2008.
o Industry Recommended Practice (IRP) Volume 4: Well Testing and Fluid
Handling from the Canadian Petroleum Safety Council, 2014.
o Flaring and Venting in the Oil and Gas Exploration and Production Industry:
An Overview of Purpose, Quantities, Issues, Practices, and Trends,
International Association of Oil and Gas Producers (IOGP), Report No.
2.79/288, January 2000.
o API Recommended Practice 55, "Recommended Practices for Oil and Gas
Producing and Gas Processing Plant Operations Involving Hydrogen
Sulfide", 2nd Edition, February 1995.
o “Zero Routine Flaring by 2030”, The World Bank (www.worldbank.org).
o Water used for fracturing usually comes from surface water sources such as lakes,
rivers, aquifers, and municipal sources. Relatively fresh water is required because
contaminants and salts reduce the effectiveness of fluid additives. These additives
are needed to achieve the required fluid properties for fracturing.
o The source of fracturing water should be determined and approved by the
appropriate local authorities before it is used.
o Slickwater fracturing fluids are less sensitive to salinity and impurities than
crosslinked fluids, but usually require more water volume.
o Water is normally transported in tanks to the well location.
o Newly developed methods for recycling produced and fracture flowback water
should be considered wherever techno-economically feasible.
Water sourcing, treatment, and disposal methods should comply with all relevant laws and
the best practices listed above.
6.16.3 References
a. “Water for Hydraulic Fracturing”, Petroleum Engineering Handbook, SPE.
b. Boschee, P. 2012. Handling Produced Water from Hydraulic Fracturing. Oil and
Gas Facilities1 (1): 23—26.
c. “Water Treating Facilities in Oil and Gas Operations, Petroleum Engineering
Handbook, SPE.
d. “Oil Facility”, Petroleum Engineering Handbook, SPE.
e. Surface water treatment for Injection”, Petroleum Engineering Handbook, SPE.
f. “Water (Prevention and Control of Pollution) Act, 1974 (amended 1988)”, Ministry
of Environment, Forest, and Climate Change, Government of India (enfor.nic.in).
g. “Environmental Protection Agency: Subchapter N - Effluent Guidelines and
Standards. Part 435—Oil and Gas Extraction Point Source Category”, United States
Code of Federal Regulations, Title 40.
In limited land areas, environmental footprint should be minimized by reducing pad size
and limiting construction of new infrastructure when possible.
6.17.3 References
o Finer M, Jenkins CN, Powers B (2013) Potential of Best Practice to Reduce
Impacts from Oil and Gas Projects in the Amazon. PLoS ONE 8(5): e63022.
doi:10.1371/journal.pone.0063022
o EPA Office of Compliance Sector Notebook Project, Profile of the Oil and
Gas Extraction Industry, October, 2000.
o Regulatory considerations
o Documentation of test objectives, test procedure etc.
Objectives of a well test – These have been classified in three major categories and are
discussed below
o Well test for reservoir evaluation
This normally applies to exploration wells and includes tests for the reservoir
fluid sampling, the reservoir flow capacity, and the initial reservoir pressure
and temperature.
It may include a single zone or multiple zones in a well.
o Well test for reservoir description
This may apply to most appraisal wells and a few development wells. Tests are
run to gain knowledge about reservoir permeability, reservoir heterogeneity,
drainage shape and boundary, and the existence of no flow boundaries such as
faults and reservoir pinch-outs. It is also desirable to know about the type of
reservoir boundary such as constant pressure or no flow closed system
boundary. However, it may not be possible to determine all of the above listed
parameters during the practical testing times.
o Well test for reservoir management (monitoring)
This usually applies to development wells and requires the periodic
collection of rate and pressure data from single or multiple wells.
Both drawdown (flowing) pressures and buildup pressures can be
collected on an as needed basis on all wells or selected wells to identify
any well problems such as formation plugging or water production to
name a few.
Periodic Pressure buildup (PBU) tests helps to diagnose and address well
problems. It also provides valuable information about reservoir pressure
and its changes as a function of time. To obtain an estimate of field-wide
average reservoir pressure, candidate wells for pressure buildup tests
should be selected in such a way that they offer a good areal coverage of
the field for each of the pay zone wherever feasible and valuable.
In general, the pressure buildup data need to be collected on a regular
basis, preferably on annual basis wherever required, to maintain a
reasonable pressure history of the field based on the reservoir conditions.
If applicable, plant and/or offshore platform facility maintenance or
shutdowns times can offer an excellent opportunity to collect such
pressure data with minimum loss to production.
Multi-rate Tests
Isochronal tests
Injection test
Multi-rate Tests
Interference Test
Pule Test
List of well and reservoir information desired from well tests is provided below:
Desired well information
7.1.3 References
1. Zheng, S., Corbett, P., “ Well Testing Best Practice”, Paper SPE 93984 presented at the
SPE Europec /EAGE Annual Conference held in Madrid, Spain, 13-18 June 2005.
2. Matthews, C. S. and Russell, D. G.: Pressure Buildup and Flow Tests in Wells, Monograph
Series, Society of Petroleum Engineers of AIME, Dallas (1967) 1.
3. Earlougher, Robert C., Jr.: Advances in Well Test Analysis, Monograph Series, Society of
Petroleum Engineers of AIME, Dallas (1976) vol. 5.
4. Bourdet, Dominique, “Well Test Analysis: The use of Advanced Interpretation Models”,
Handbook of Petroleum Exploration & Production, Elsevier Publications, 2002, Vol. 3, 1-
45.
5. Lee, John: Well Testing, Text Book Series, Society of Petroleum Engineers of AIME, Dallas
(1982) vol. 1, 1-71.
6. Lee, J., Rollins, J. S., and Spivey, J. P.: Pressure Transient Testing, Text Book Series,
Society of Petroleum Engineers of AIME, Dallas (2003) Vol. 9.
7. Spivey, J. P. and Lee, John: Applied Well Test Interpretation, Text Book Series, Society of
Petroleum Engineers of AIME, Dallas (2013) Vol. 13.
8. Stewart, George: Well Test Design and Analysis, Penn well Corporation, Tulsa, Oklahoma
(2011).
9. British Colombia Well Testing and Reporting Requirements, BC Oil and Gas Commission,
March 2013.
Calibration of Gauges – Regardless of the gauge system that is used, the quality of the data
will depend on how accurately the gauges have been calibrated. The ever increasing
sophistication of gauges requires high accuracy calibration systems and particular attention
to detail in terms of calibration procedures.
Mechanical gauges should only be used as a back-up to electronic gauges, unless used for
HP/HT tests. Electronic gauges are, however, common today and should be used because
of their superior precision and resolution.
It is also recommended that the recorder section of the gauge is checked before running the
gauge to make sure that the stylus moves freely when the recorder is not connected to the
clock or to the pressure element.
When running a self-contained gauge, it is important to choose the clock so that most of the
length of the chart is used during the test. It is also advisable to choose the clock so that the
gauge needs to be run only once during the test, if possible.
If there is a doubt that a clock is running throughout a test, small pressure events may be
put on the chart at known times simply by raising the gauge several feet and then lowering
it back to its original position. The hours per inch calculated between each event should be
the same.
If the chart obtained from a gauge shows a stair-stepping pattern, a recorder malfunction is
indicated. That pattern indicates that the pressure must change by a certain amount before
the stylus moves. This difficulty must be corrected for good pressure results by freeing the
recorder so it does not get stuck.
In reservoirs with temperature above 150oC, run at least four gauges, preferably using
different gauge technologies.
In situations in which packers are being set and/or tubulars are perforated, pressures above
reservoir pressures can be anticipated for short durations. Select the proper gauge rating to
accommodate these conditions.
It is advisable to choose the gauge pressure range so that the maximum observed pressure
(current and future anticipated) falls between 60 and 80 percent of the upper limit of the
gauge. If a gauge with too high pressure range is chosen, the accuracy and sensitivity
obtained may not be adequate.
For long-term installation, gauge drift characteristics should be considered before the
choice is made.
It should be ensured that the gauge battery life is sufficient for the test duration at the
expected bottom-hole temperature with contingency built in.
For best results, pressure should be measured near the sand-face. If that is impossible, useful
data are usually obtained by correcting wellhead-pressure or fluid-level measurements to
bottom-hole conditions. Run the gauges as close to the perforations as possible.
Use surface pressure and temperature data along with bottom-hole data to resolve
ambiguous wellbore effects.
Run static and flowing gradient surveys before and/or after a test is complete, wherever
possible.
Prior to permanent abandonment of a well, sufficient pressure data shall be available to take
an informed decision.
Have all equipment certified for sour-gas service for testing reservoirs containing H2S.
7.2.3 References
1. Kamal, M., "Transient Well Testing", SPE Monograph Series Vol. 23, 2009. Under this
monograph, a chapter "Well Testing Measurements" by Jitendra Kikani is being referred.
2. Lee, J. et al, "Pressure Transient Testing", SPE Textbook Series Vol. 9, 2003.
3. Earlougher, R. C. Jr., "Advances in Well Test Analysis", SPE Monograph Series Vol. 5,
1977.
4. Vella, M. et al. "The Nuts and Bolts of Well Testing", Oilfield Review 4 (2), pg 22, 1992.
5. Mattar, L., "Critical Evaluation and Processing of Data Before Pressure Transient
Analysis", SPEFE 24729-PA, 1996.
6. McAleese, S., "Operational Aspects of Oil and Gas Well Testing, Handbook of Petroleum
Exploration and Production, Vol. 1, Elsevier Science, 2000.
For the traditional test comprising two flow periods and two buildups. Generally transient
analysis focuses on the second buildup.
The first step is to identify the various flow regimes on the log-log plot of ∆p and derivative
vs. time. The second step is to choose the most likely model for each.
Estimation of model parameters is then made using specialized plots that allow a focused
analysis of each flow regime.
In this forward modeling process, the interpreter interprets parameters, either manually or
automatically using a nonlinear regression scheme, and perhaps alters the choice of model
for one of the regimes to obtain the best possible fit.
The final interpretation step, called history matching or verification, uses the model
established in the relevant buildup to predict pressure response throughout all flow and shut-
in periods of the test and confirms that the model satisfactorily accounts for all data.
This may result in more parameter adjustment because every period must now be matched
simultaneously; even though the second flow period is planned intentionally long to
minimize the influence of previous periods.
Well testing analysis involves a multitude of input parameters with high degrees of
uncertainty associated with them. Hence it is recommended that each analysis needs to be
accompanied by a parametric sensitivity study.
The analysis platform should involve a minimum of one commercial software and/or in-
house computations. This ensures the validity and credibility of the analysis results.
7.3.3 References
1. Bourdet, Dominique, “Well Test Analysis: The use of Advanced Interpretation Models”,
Handbook of Petroleum Exploration & Production, Elsevier Publications, 2002, Vol. 3, 1-
45.
2. Lee, J., Rollins, J. S., and Spivey, J. P.: Pressure Transient Testing, Text Book Series,
Society of Petroleum Engineers of AIME, Dallas (2003) Vol. 9.
3. Spivey, J. P. and Lee, John: Applied Well Test Interpretation, Text Book Series, Society of
Petroleum Engineers of AIME, Dallas (2013) Vol. 13.
4. Stewart, George: Well Test Design and Analysis, Penn well Corporation, Tulsa, Oklahoma
(2011).
5. Deruyck, B., Ehlig-Economides, C., and Joseph, J., "Testing Design and Analyses", Oilfield
Review, Volume 4, Issue 2, 1992.
Special Core Analysis (SCAL) is a critical part of core analysis and typically includes
drainage/imbibition capillary pressure, drainage/imbibition water/oil and gas/oil relative
permeability, rock wettability, pore volume compressibility and electrical properties.
Drainage process refers to the process in which the non-wetting phase saturation increases
while the imbibition refers to the process in which the wetting phase saturation increases.
For instance, for a water-wet reservoir, oil production by water flooding is an imbibition
process which results in increasing water saturation and decreasing oil saturation.
For reservoirs with severe heterogeneity, whole core samples should be used for core
analysis.
Composite cores are often used to eliminate or minimize capillary end effects.
7.4.3 References
1. American Petroleum Institute: “Recommended practices for core analysis procedures” Dallas, TX.
API, 1998.
2. Andersen, G., “Coring and Core Analysis Handbook,” Tulsa, OK, PennWell Books, 1975.
Capillary pressure is commonly measured using one of the three methods: porous plate (or
diaphragm) method, centrifugal method and mercury injection method. The objective of the
measurement is to provide a relationship between capillary pressure and water saturation.
The resulting capillary pressure curve can relate water saturation to height above water-oil
contact in a reservoir which can be used to calculate hydrocarbons in place.
Porous plate method is also referred to as porous diaphragm or restored state method. For
a gas-brine system, the measurement is commonly performed with a semi-permeable
ceramic plate saturated with brine.
Mercury injection method is fast and reasonably accurate but conversion is required from
mercury/air capillary data to reservoir fluid systems.
The following equation is recommended to determine the maximum capillary pressure needed
to perform capillary pressure test with centrifuge
𝑃𝑐 = (𝜌𝑤 − 𝜌𝑜 )𝐻
7.5.3 References
1. Slobod, R.L., et al.:” Use of Centrifuge for Determining Connate Water, Residual Oil and
Capillary Pressure Curves of Small Core Samples,” Trans. AIME (1951) 192, 127-134.
2. Purcell, W.R.: "Capillary Pressures-Their Measurement Using Mercury and the Calculation
of Permeability Therefrom," Trans. AIME (1949) 186, 39-48.
3. Hassler, G. L., Brunner, E.: “Measurement of Capillary Pressure in Small Core Samples,”
Trans. AIME (1945) 160, 114-123.
4. Kalam, M.Z., Hammadi, K.A., Wilson, O. B., Dernaika, M., and Samosir, H.: “Importance
of Porous Plate Measurements on Carbonates at Pseudo Reservoir Conditions,” SCA2006,
28, Trondheim, Norway.
The USBM method determines core wettability by comparing the thermodynamic work
required for one fluid to displace the other fluid. The required work is found to be
proportional to the area under the drainage and imbibition capillary pressure curves. Core
wettability can be evaluated through the USBM wettability index which is calculated using
the following equation.
W log( A1 / A2 )
Where A1and A2are the areas under the drainage and imbibition capillary pressure curves
respectively.
o Spin the cores under stock tank oil until there is no water production and record the
amount of water displaced by the oil (Volume D).
o Calculate the Amott-Harvey water and oil wettability index based on the
spontaneous and forced imbibition test data using the following equation and
determine core wettability.
𝐴 𝐶
𝑊𝐼 =
𝐴+𝐵
−
𝐶+𝐷
USBM/Amott combined wettability test is recommended which would provide USBM and
Amott wettability index.
For wettability tests with restored state core samples, it is recommended to age the core
samples for 40 days to restore reservoir wettability unless there are convincing reasons to
age the core samples for a shorter period of time.
7.6.3 References
1. Anderson, W. G.: “Wettability Literature Survey: Part 2-Wettability Measurement,”
JPT (Nov., 1986).
Relative permeability is a strong function of the fluid saturation and it also depends on the
direction of saturation changes. For the same level of fluid saturation, relative permeability
can be different due to difference in interstitial fluid distribution. Thus, for the same level
of the fluid saturation, drainage (increasing non-wetting phase saturation) relative
permeability can be different from imbibition (increasing wetting phase saturation) relative
permeability.
minimize capillary end effects. Capillary continuity between the composite cores
can be improved by use of Kleenex or filter paper.
o Apply desired confining pressure and pore pressure to the cores.
o Raise the temperature of the core assembly to the reservoir temperature.
o Flush the core with certain amount of live reservoir oil containing 10 vol%
iododecane at a controlled flow rate at reservoir conditions. Determine effective oil
permeability at initial water saturation. X-ray scans the core plugs to determine CT
number.
o Age the core plugs for 40 days to restore rock wettability.
o Inject water and oil simultaneously at a low fixed water/oil ratio into the core
samples until pressure drop across the core samples reach constant. Determine
effective permeability and X-ray scans the cores to determine CT x . Repeat at
increasing water to oil injection ratios and determine corresponding effective
permeability and X-ray CT number ( CT x ).
o Determine imbibition relative permeability as a function of brine saturation.
7.7.3 References
1. Honarpour, M. and Mahmood, S.M.: “Relative Permeability Measurements: An
Overview”, SPE18565.
2. Honarpour, M., et. al.: “Relative Permeaiblity of Petroleum Reservoirs”, CRC Press Inc.,
Boca Raton, FL (1986).
3. Longeron, D. G., Kalaydjian, F., Bardon C., and Desremaux, L.M.: “Gas-Oil Capillary
Pressure: Measurements at Reservoir Conditions and Effect on Gas Gravity Drainage”,
SPE 28612 presented at the SPE 69th Annual Technical Conference and Exhibition, New
Orleans, LA, U.S.A, 25-28 September 1994.
4. Ross, W.: “Relative Permeability”, Petroleum Production Handbook, SPE, Richardson,
TX (1987), Chap. 28, 28-l-28-16.
Formation resistivity factor (FRF) should also be determined at net formation overburden
pressure.
o Measure electrical resistivities at each saturation stage until a constant value has been
attained.
o Calculate resistivity index and saturation exponent at each brine saturation value.
o Clean the core with toluene and methanol and dry the core at 60oC until a constant
weight has been achieved.
o Determine Cat-ion Exchange Capacity (CEC) using ammonium acetate wet chemistry
technique.
o Calculate clay-corrected cementation and saturation exponent using Waxman-Smits-
Thomas equations.
7.8.3 References
1. Durand, C. and Lenormand, R.: “Resistivity Measurements While Centrifuging”,
Proceeding of the International Symposium of the Society of Core Analysts, Calgary
(1997).
2. Fleury M. and Longeron D.: “Combined Resistivity and Capillary Pressure
Measurements Using Micro-pore Membrane Technique”, Proceeding of the
International Symposium of the Society of Core Analysts, Montpelier (1996).
Where, the pressure outside the parentheses indicates that the pore pressure is kept constant
when the pore volume compressibility is measured with change in confining pressure.
Pore volume compressibility is usually measured under hydrostatic stress condition, that is,
the entire outer boundary of the rock sample is subjected to the same confining pressure.
The hydrostatic loading results in a greater pore volume compressibility than in the
reservoir. It is the uniaxial pore volume compressibility that is needed for reservoir
engineering calculations. Therefore, hydrostatic compressibility must be reduced to
uniaxial compressibility using appropriate equations.
7.9.3 References
1. Teeuw, Dirk: "Prediction of Formation Compaction from Laboratory Compressibility
Data”, Trans: AIME (1971) 251, 263-271.
2. Zimmerman, R. W.: “Pore Compressibility under uniaxial Strain”, Proceedings,
International Symposium on Land Subsidence, Ravanna, Italy, 2000
If there is an obvious discrepancy in water saturation, log and core data must be critically
analyzed and adjusted to reflect the in-situ water saturation.
Calculate capillary pressure as a function of the height above free water level using the
following equation:
𝑃𝑐 = (𝜌𝑤 − 𝜌𝑜 )𝐻
0.21167∗𝑃𝑐 𝑘
𝐽= √
𝜎𝑐𝑜𝑠𝜃 ∅
∅ - porosity (fraction)
Calculate connate water saturation using the derived J-function for each rock type
Plot height versus the Pc-derived water saturation and height versus the log-derived water
saturation. Compare the water saturation and make necessary adjustment based on data
reliability.
Water saturations from other sources, such as oil based mud (OBM) core, single well
chemical tracer test etc., are recommended for use to help finalize the water saturation.
7.10.3 References
1. Efnik, M. S. et al.: “Evaluation of Water Saturation from Laboratory to Logs,” SCA2006-
56.
2. Thornton, O. F., and Marshall, D. L.: “Estimating Interstitial Water Saturation by the
Capillary Pressure Method,” Trans AIME (1946).
Other conventional decline curve analysis methods such as ARPS equation, Fetkovich
liquid system decline curves etc may be used depending upon the field / reservoir
requirements.
7.11.3 References
1. Agarwal, Ram G., Gardner, David C., Kleinsteiber, Stanley W., and Fussell, Del D.: “Analyzing Well Production
Data Using Combined Type-Curve and Decline Curve Analysis Concepts,” SPE Reservoir Eval. & Eng., Vol. 2, No.
5, October 1999, 478-486.
2. Agarwal, Ram G.: “Direct Method of Estimating Average Pressure for Flowing Oil and Gas Wells,” paper 135804
presented at the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, Sept. 19-22.
Scope :
The scope of this chapter applies to following stages/aspects of E&P activity:
Evaluation phase
Appraisal phase
Design phase
Execution/operations phase
Retiring phase
This chapter covers the following aspects:
The indicative list of applicable statutory requirements in India have been mentioned in section
8.1.3 and are applicable to sections 8.2 and 8.4 also.
Individual Health, Safety and Environment (HSE) systems, management tools and techniques have
evolved over years in line with organizational HSE principles, minimum regulatory requirements
and industry best practices. The HSE Management System (HSEMS) Framework is critical and
provides a basis for companies to consistently manage health, safety and environmental issues.
The Guidelines suggested here build on experience gained in the application of earlier systems and
arrangements and also draws on external developments such as Quality Management standards
(ISO 9000), Health and Safety Management (HS(G)65), Environmental Management (ISO 14000)
and HSE Management (E&P Forum). These Guidelines are intended to meet following objectives,
Assist in the development and application of HSEMS in exploration and production operations.
Cover relevant Health, Safety and Environment (HSE) issues in a single document.
Be relevant to the activities of the E&P operations in line with industry best practices.
Be sufficiently generic to be adaptable to different companies and their cultures.
Recognize, and be applicable to, the role of contractors and subcontractors.
Facilitate operation within the framework of statutory requirements.
Facilitate evaluation of operations to an international standard(s) as appropriate.
The Guidelines describe the main elements necessary to develop, implement and maintain an
HSEMS. They do not lay down specific performance requirements, but recommend that companies
set policies and objectives taking into account information about the significant hazards and
environmental effects of their operations. These may be used as a template by any operating or
contracting company seeking to help assure itself and others (such as regulators, neighbours,
partners, clients, insurers) of compliance with stated HSE policies within an objective-setting
management system. Furthermore, the Guidelines are intended to support, rather than to suggest
replacement of, existing sound, workable and effective company systems and practices.
The model Health, Safety and Environmental Management System (HSEMS) is described below,
These guidelines provide a basis for Contractors/Operators to develop, maintain, and implement
HSE Management Systems for all their activities. The HSE management system should include
management commitment, work flows, HSE manuals, training, environment, safety and
occupational health and hygiene audits and continuous improvement (see figure below). The actual
activities within each phase of the project as mentioned above depend on the actual project itself
and will dictate the relevant and applicable HSE protocols to adopt.
The framework details outlined below provide a structure for a comprehensive HSE management
program for upstream oil and gas development operations and as a minimum, are relevant to:
Construction activities
The company should create and sustain a company culture that supports the HSEMS, based on:
belief in the company’s desire to improve HSE performance;
motivation to improve personal HSE performance;
acceptance of individual responsibility and accountability for HSE performance;
participation and involvement at all levels in HSEMS development;
Employees of both the company and its contractors should be involved in the creation and
maintenance of such a supportive culture
Policy & Strategic Objectives: This element describes corporate intentions, principles of action and
aspirations with respect to HSE.
The company’s management should define and document its HSE policies and strategic objectives and
ensure that they:
The company should establish and periodically review strategic HSE objectives. Such objectives
should be consistent with the company’s policy and reflect the activities, relevant HSE hazards and
effects, operational and business requirements, and the views of employees, contractors, customers and
companies engaged in similar activities
Organization, Resources & Documentation: This element requires that responsibilities are assigned,
adequate resources applied, competence assured, contractor HSE performance managed, HSE matters
are effectively communicated, and documentation is controlled and maintained.
Successful handling of HSE matters is a line responsibility, requiring the active participation of all
levels of management and supervision. This should be reflected in the organizational structure and
allocation of resources. The company should define, document and communicate—with the aid of
organizational diagrams where appropriate—the roles, responsibilities, authorities, accountabilities and
interrelations necessary to implement the HSEMS, including but not limited to:
The company should stress to all employees their individual and collective responsibility for HSE
performance. It should also ensure that personnel are competent and have the necessary authority and
resources to perform their duties effectively.
The organizational structure and allocation of responsibilities should reflect the responsibility of line
managers at all levels for developing, implementing and maintaining the HSEMS in their particular
areas. The structure should describe the relationships between:
The company should maintain procedures to identify systematically the hazards and effects which may
affect or arise from its activities, and from the materials which are used or encountered in them. The
scope of the identification should cover activities from inception (e.g. prior to acreage acquisition)
through to abandonment and disposal.
Personnel at all organizational levels should be appropriately involved in the identification of hazards
and effects.
Evaluation :
Procedures should be maintained to evaluate (assess) risks and effects from identified hazards against
screening criteria, taking account of probabilities of occurrence and severity of consequences for:
People
Environment
Assets
Reputation
It should be noted that any evaluation technique provides results which themselves may be subject to a
range of uncertainties. Consequently formal risk evaluation techniques are used in conjunction with the
judgment of experienced personnel, regulators and the community.
Evaluation of health and safety risks and effects should include, where appropriate, consideration of:
Fire and explosion.
Impacts and collisions.
Drowning, asphyxiation and electrocution.
Chronic and acute exposure to chemical, physical and biological agents.
Ergonomic factors.
Evaluation of acute and chronic environmental effects should include, where appropriate, consideration
of:
Controlled and uncontrolled emissions of matter and energy to land, water and the atmosphere
Generation and disposal of solid and other wastes
Use of land, water, fuels and energy, and other natural resources
Noise, odour, dust, vibration
Effects on specific parts of the environment including ecosystems
Effects on archaeological and cultural sites and artefacts, natural areas, parks and conservation
areas
The company should maintain procedures to document those hazards and effects (chronic and acute)
identified as significant in relation to health, safety and the environment, outlining the measures in place
to reduce them and identifying the relevant HSE-critical systems and procedures.
The company should maintain procedures to record statutory requirements and codes applicable to the
HSE aspects of its operations, products and services and to ensure compliance with such requirements.
Identify prevention and mitigation measures for particular activities, products and services which
pose potential HSE risks.
Re-appraise activities to ensure that the measures proposed do reduce risks, or enable relevant
objectives to be met.
Implement, document and communicate to key personnel interim and permanent risk reduction
measures, and monitor their effectiveness.
Develop relevant measures such as plans for emergency response to recover from incidents and
mitigate their effects.
Identify hazards arising from risk prevention and mitigation and recovery measures.
Evaluate the tolerability of consequent risks and effects against the screening criteria.
Planning: This element requires that plans are developed for achieving HSE objectives, targets & risk
reduction measures, performance improvement, conduct of work activities, management of change and
emergency response.
The company should maintain, within its overall work program, plans for achieving HSE objectives
and performance criteria. These plans should include:
procedures should be suitable to address the HSE issues involved, according to the nature of the changes
and their potential consequences.
Contingency and emergency planning: The company should maintain procedures to identify
foreseeable emergencies by systematic review and analysis. A record of such identified potential
emergencies should be made, and updated at appropriate intervals in order to ensure effective response
to them.
The company should develop, document and maintain plans for responding to such potential
emergencies, and communicate such plans to :
Organisation, responsibilities, authorities and procedures for emergency response and disaster
control, including the maintenance of internal and external communications.
Systems and procedures for providing personnel refuge, evacuation, rescue and medical treatment.
Systems and procedures for preventing, mitigating and monitoring environmental effects of
emergency actions.
Procedures for communicating with authorities, relatives and other relevant parties.
Systems and procedures for mobilizing company equipment, facilities and personnel.
Arrangements and procedures for mobilizing third party resources for emergency support.
Arrangements for training response teams and for testing the emergency systems and procedures.
To assess the effectiveness of response plans, the company should maintain procedures to test
emergency plans by scenario drills and other suitable means, at appropriate intervals, and to revise them
as necessary in the light of the experience gained.
Procedures should also be in place for the periodic assessment of emergency equipment needs and the
maintenance of such equipment in a ready state.
Measurement and Feedback: This element requires that activities are conducted against relevant
procedures. Performance is measured against objectives, targets, external benchmarks and performance
criteria. Corrective action is taken when necessary.
Management should ensure, and be responsible for, the conduct and verification of activities and tasks
according to relevant procedures. This responsibility and commitment of management to the
implementation of policies and plans includes, amongst other duties, ensuring that HSE objectives are
met and that performance criteria and control limits are not breached. Management should ensure the
continuing adequacy of the HSE performance of the company through monitoring activities.
The company should maintain procedures for monitoring relevant aspects of HSE performance and for
establishing and maintaining records of the results. For each relevant activity or area, the company
should:
identify and document the monitoring information to be obtained, and specify the accuracy required
of results;
specify and document monitoring procedures, and locations and frequencies of measurement;
establish, document and maintain measurement quality control procedures;
establish and document procedures for data handling and interpretation;
establish and document actions to be taken when results breach performance criteria;
assess and document the validity of affected data when monitoring systems are found to be
malfunctioning;
safeguard measurement systems from unauthorized adjustments or damage.
Audit: This element requires that audits are conducted as a normal part of business control to
independently assess the robustness, effectiveness and continued suitability of the Management System
practices, and conformance with planned arrangements.
The company should maintain procedures for audits to be carried out, as a normal part of business
control, in order to determine:
Whether or not HSE management system elements and activities conform to planned arrangements,
and are implemented effectively.
The effective functioning of the HSEMS in fulfilling the company’s HSE policy, objectives and
performance criteria.
Compliance with relevant legislative requirements.
Identification of areas for improvement, leading to progressively better HSE management.
For this purpose, it should maintain an audit plan, dealing with the following:
Specific activities and areas to be audited. Audits should cover the operation of the HSEMS and
the extent of its integration into line activities, and should specifically address the following
elements of the HSEMS model:
o organisation, resources and documentation;
o evaluation and risk management;
o planning;
o implementation and monitoring.
Frequency of auditing specific activities/areas. Audits should be scheduled on the basis of the
contribution or potential contribution of the activity concerned to HSE performance, and the results
of previous audits.
Responsibilities for auditing specific activities/areas.
programs. Information collected during environmental and safety audits are used to improve
worker safety and health, effectively prevent injury and illness and manage environmental
hazards. This can reduce costs and avoid regulatory citations and fines. Environmental and
safety audits are important in evaluating compliance of the Operator's environment and work
safety programs through the assessment of properties, facilities, processes, and operations
against regulations and standards as well as internal policies and goals. Environmental and
safety audits should be conducted to ensure that oil and gas operators have efficient
management of environment, safety and health programs, effective self-monitoring
programs to evaluate site hazards, and effective management of hazards such as carbon,
greenhouse gases (GHG), water, effluent and waste etc. Environmental and safety audits are
performed based on safety standards such as ISO 14001, ISO 14064 and other GHG
guidelines.
Management Review: This element requires that the HSE Management System is reviewed
periodically by senior management to ensure that it continues to be effective and to identify changes
for continuous performance improvement.
The company’s senior management should, at appropriate intervals, review the HSEMS and its
performance, to ensure its continuing suitability and effectiveness. The review should specifically,
but not exclusively, address:
The possible need for changes to the policy and objectives, in the light of changing
circumstances and the commitment to strive for continual improvement.
Resource allocation for HSEMS implementation and maintenance.
Sites and/or situations on the basis of evaluated hazards and risks, and emergency planning
The review process should be documented, and its results recorded, to facilitate implementation of
consequent changes. Reviews should be used to reinforce continuous efforts to improve HSE
performance.
to provide an overview of environmental issues in the oil and gas exploration and production
industry, and of the best approaches to achieving high environmental performance.
Definitions :
Environmental Impacts:
Petroleum operations have the potential for a variety of impacts on the environment. These impacts
depend on the stage of the project, the size and complexity of the project, the nature and sensitivity
of the surrounding environment and the effectiveness of planning, pollution prevention, mitigation,
and control techniques. Most of these impacts could be harmful to the environment. However, with
proper care and attention, the adverse effects could be avoided, minimized or mitigated. It is thus
important that Contractors/Operators remain committed to the development of management
systems, operational practices and engineering technology targeted at minimizing the adverse impact
on the environment due to oil and gas activities and operations.
To that effect, best industry practices should be adopted during petroleum operations so as to
minimize or mitigate adverse impacts on the environment. First the potential impacts are discussed
for the purpose of awareness, then operational guidelines aimed at minimizing the negative impacts and
enhancing the positive impacts are provided. These guidelines are based on best industry practices
and recommendations as provided in multiple international publications including API’s
Recommended Practice 51R, technical publications by E&P Forum/UNEP, and multiple IFC
publications (see references for details). The practices presented here are in agreement with various
Acts and Rules previously adopted by the Indian Ministry of Environment, Forests and Climate
Change, other governing bodies related to HSE. The guidelines presented here do not replace the
Acts and Rules, but rather supplement (see section below for an indicative list of the Acts and
Rules). Companies engaging in petroleum operations should also refer to these documents so as to
be compliant in their practices.
Petroleum operations can have the following impacts:
Atmospheric impacts;
Aquatic impacts;
Terrestrial impacts;
Biosphere impacts.
These are further outlined below.
Atmospheric Impacts
o The primary sources of atmospheric emissions from oil and gas operations arise
from:
Flaring, venting and purging gases;
Combustion processes such as diesel engines and gas turbines;
Fugitive gases from loading operations , waste dumps, landfills, tank age
and losses from process equipment;
Airborne particulates from soil disturbance during construction and from
vehicle traffic; and
Particulates from other burning sources, such as well testing.
o The principal emission gases include carbon dioxide, carbon monoxide, methane,
volatile organic carbons and nitrogen oxides. Emissions of sulfur dioxides and
hydrogen sulphide can occur and depend upon the sulfur content of the hydrocarbon
and diesel fuel, particularly when used as a power source. In some cases sulfur
content can lead to odor near the facility.
o Flaring of produced gas is the most significant source of air emissions, particularly
where there is no infrastructure or market available for the gas. However, where
viable, gas should be processed and distributed as an important commodity. Thus,
through integrated development and providing markets for all products, the need for
flaring will be greatly reduced. Flaring may also occur on occasions as a safety
measure, during start-up, maintenance or upset in the normal processing operation.
o Flaring, venting and combustion are the primary sources of carbon dioxide
emissions from production operations, but other gases should also be considered
(See also section 6.156.15).
Aquatic Impacts
o Resource depletion due to intake of water for entire life cycle of the E & P operation
o The principal aqueous waste streams resulting from exploration and production
operations are:
Produced water;
Drilling fluids, cuttings and well treatment chemicals;
Process, wash and drainage water;
Sewerage, sanitary and domestic wastes;
Spills and leakage;
Cooling water.
o The volumes of liquid waste produced depend on the stage of the exploration and
production process. During seismic operations, waste volumes are minimal and
relate mainly to camp or vessel activities. In exploratory and appraisal drilling the
main aqueous effluents are drilling fluids and cuttings, whilst in production
operations—after the development wells are completed—the primary effluent is
produced water (See also section 6.16).
o The high pH and salt content of certain drilling fluids and cuttings pose a potential
impact to fresh-water sources. Produced water is the largest volume aqueous waste
arising from production operations, and some typical constituents may include in
varying amounts inorganic salts, heavy metals, solids, production chemicals,
hydrocarbons, benzene, PAHs, and on occasions, naturally occurring radioactive
material (NORM).
o Hydrofracturing and polymer flooding are high potential water polluting operations.
Unless reused it has potential risk of contamination and resource depletion
Terrestrial Impacts
o Potential terrestrial impacts arise from the following basic sources:
Physical disturbance as a result of construction (access roads, camps,
facilities, etc.);
Contamination resulting from spillage and leakage of oil, chemicals or
unregulated solid waste disposal; and
Indirect impact arising from opening access and social change.
o Potential impacts that may result from poor design and construction include soil
erosion due to soil structure, slope or rainfall. Left undisturbed and vegetated, soils
will maintain their integrity, but, once vegetation is removed and soil is exposed,
soil erosion may result. Alterations to soil conditions may result in widespread
secondary impacts such as changes in surface hydrology and drainage patterns,
increased siltation and habitat damage, reducing the capacity of the environment to
support vegetation and wildlife.
o In addition to causing soil erosion and altered hydrology, the removal of vegetation
may also lead to secondary ecological problems, particularly in situations where
many of the nutrients in an area is held in vegetation (such as tropical rainforests);
or where the few trees present are vital for wildlife browsing (e.g. tree savannah);
or in areas where natural recovery is very slow (e.g. Arctic and desert ecosystems).
Clearing by operators may stimulate further removal of vegetation by the local
population surrounding a development.
o Soil contamination may arise from un-regulated discharge of effluents and garbage
particularly during project stage, spills and leakage of chemicals and oil, causing
possible impact to both flora and fauna. Simple preventative techniques such as
segregated and contained drainage systems for process areas incorporating sumps
and oil traps, leak minimization and drip pans, should be incorporated into facility
design and maintenance procedures. Such techniques will effectively remove any
potential impact arising from small spills and leakage on site.
Biosphere impacts
o Plant and animal communities may also be directly affected by changes in their
environment through variations in water, air and soil/sediment quality and through
disturbance by noise, extraneous light and changes in vegetation cover. Such
changes may directly affect the ecology and biodiversity: for example, habitat, food
and nutrient supplies, breeding areas, migration routes, vulnerability to predators or
changes in herbivore grazing patterns, which may then have a secondary effect on
predators.
o Soil disturbance and removal of vegetation and secondary effects such as erosion
and siltation may have an impact on ecological integrity, and may lead to indirect
effects by upsetting nutrient balances and microbial activity in the soil. If not
properly controlled, a potential long-term effect is loss of habitat which affects both
fauna and flora, and may induce changes in species composition and primary
production cycles.
The results from the assessment are to be incorporated into the design, execution, operating and
decommissioning stages of the project.
The Environmental Management Program should clearly stipulate the Contractor’s/Operator’s
commitment to safeguarding the environment and social integrity. Based on the results from
specific project assessments, the Contractor/Operator will state clearly how it intends to meet all
the environmental and social issues/challenges that have been identified.
The Environmental Management Program should assure that the following activities are taken into
consideration and checked off before embarking on any project:
Key environmental issues are identified early enough before the start of project activities;
The community and other stakeholders related to the project are fully informed of the
project and any potential impact to the environment and/or to the community is intimated
to all parties;
Relevant environmental and social issues are taken into account during project design and
implementation, in a way that eliminates or minimizes any negative impact;
Corrective plans and the commitment to apply such plans are fully documented prior to the
start of project activities.
Regular monitoring and checking is ensured during implementation of the project to ensure
effectiveness of plans.
Furthermore, the Environmental Management Program should cover the following areas:
Regulatory requirements;
Employee training;
Emergency management;
Noise generation;
Land/Soil degradation;
Air emissions;
NORM;
Well blowouts.
General Considerations for Site Selection, Access Roads, Construction of Facilities for All
Petroleum Activities
o Conduct a detailed environmental and social impact assessment of planned
petroleum activities on the environment prior to any operations. Use the
environmental assessment to identify protected areas and sensitive areas. Consult
with local authorities and other stakeholders for preferences regarding site selection,
access roads and construction of facilities.
o Choose sites to minimize impacts on water resources, conservation interests,
settlement, agriculture, sites of historical and archaeological interest and landscape.
Consider using sites that have been cleared/disturbed previously or of low
ecological value, or which may be more easily restored, . Choose sites to encourage
natural rehabilitation by indigenous flora.
o Avoid or minimize road construction, minimize clearing and disturbance, minimize
footprint, use existing infrastructure if available. Do not cut down trees of a diameter
greater than local regulations permit.
o Minimize the size of camps/facilities consistent with operational, health and safety
requirements.
o Incorporate drainage and minimize disturbance to natural drainage patterns.
Engineer slopes and drainage to minimize erosion. Design for storm conditions to
ensure offsite natural runoff does not wash over site.
o Take account of topography, natural drainage and site runoff. Ensure adequate and
proper drainage.
o Create awareness and train the crew particularly security staff to behave sensibly to
uphold the laws, policies and procedures that protect the rights of indigenous people
and others.
record of all sighting would be kept and reported as part of the environmental
monitoring of the project.
Use soft-start procedures—also called ramp-up or slow buildup—in areas of
known marine mammal activity. This involves a gradual increase in sound
pressure to full operational levels.
Use the lowest practicable power levels to image the target surface
throughout the seismic surveys and document their use.
Where possible, use methods to reduce and/or baffle unnecessary high-
frequency noise produced by air guns or other acoustic energy sources.
For pile driving, use vibratory hammers, air bubble curtains (confined or
unconfined), temporary noise attenuation piles, air filled fabric barriers, and
isolated piles or coffer dams, where practical.
Dispose all waste materials and oily water properly to meet local, national
and international regulations. See Annex IV and Annex V of MARPOL
73/78.
Apply proper procedures for handling and maintenance of cable equipment
and particularly cable oil.
All towed equipment must be highly visible and labelled. Make adequate
allowance for deviation of towed equipment when turning.
Prepare contingency plans for lost equipment and oil spillage. Attach active
acoustic location devices to auxiliary equipment to aid location and
recovery.
Remain on planned survey track to avoid unnecessary interactions.
Pollution) Cess (Amendment) Act, 2003, MSIHC, HW-2008, MSW, PLI, electronic
waste, biomedical etc}.
o Monitor operations to minimize impact on wildlife and local population, also
monitor garbage collection, sewage treatment, drilling fluid and cuttings to assure
compliance with existing guidelines.
o During operations, practice best industry practices for health and safety of rig
personnel (see Section 8.2 ).
o Develop contingency plan for drilling accidents, such as H2S gas releases, blowouts,
oil spills and fires. Ensure that the equipment needed for controlling the incident is
available and in good working order. Practice drills for readiness. Have alarms
installed and tested for warning of various drilling accidents.
o Specifically, adopt the following operating guidelines during drilling activities:
For site preparation:
Use water based mud as practicably possible and mud chemicals should
contain heavy metals below prescribed limits.
Develop contingency plans for managing oil spills, well blowouts, and
other emergencies before starting operations.
Follow industry best practice and MSDS requirements for the storage,
handling, use and disposal of the materials used in drilling mud. The
requirements regarding hazardous materials management presented
above could be applied here for drilling mud components that are
hazardous.
Drill cuttings and used-mud return pit should be properly lined with
impermeable liner, which will form a barrier preventing the
migration of materials into the surrounding soil. The integrity of the
liner should be regularly checked to ensure there is no damage and the
liner is still impermeable.
Noise levels at the site boundary should meet local and/or company
specified levels. Ensure all machinery and equipment are properly
cladded.
Light sources should be properly shaded and directed onto site area.
Produced water from well tests must meet local and national
regulations/standards prior to discharge.
Preferentially separate and store oil from well test operations. If burnt,
ensure burner efficiency is adequate to prevent oil fallout onto sea
surface.
Collect all domestic waste and compact for onshore disposal. Ensure
proper documentation and manifesting. Ensure onshore receiving and
Contingency plans for managing oil spills, blowouts, other fires and
explosions, and other emergencies must be developed and approved
before operations commence. Personnel must be properly trained on
the plans.
Incorporate oily water treatment system for both produced water and
contaminated water treatment to meet local, national and international
discharge limits (Annex IV of MARPOL 73/78).
8.1.3 References
1. Environmental, Health and Safety General Guidelines. International Finance Corporation,
World Bank Group. 2007.
2. Environmental, Health and Safety Guidelines for Offshore Oil and Gas Development.
International Finance Corporation, World Bank Group. (2014 draft version).
3. Environmental, Health and Safety Guidelines for Onshore Oil and Gas Development.
International Finance Corporation, World Bank Group. 2007.
4. Guidelines for Offshore Oil Spill Response Plans; API Technical Report 1145, 2013.
5. MoEF&CC (http://www.envfor.nic.in/).
6. Environmental Management in Oil and Gas Exploration and Production; Joint E&P
Forum/UNEP Technical Publication.
7. Annex IV of MARPOL 73/78 Regulations for the Prevention of Pollution by Sewage from
Ships.
8. Annex V of MARPOL 73/78 Regulations for the Prevention of Pollution by Garbage from
Ships.
9. Annex VI of MARPOL 73/78 Regulations for the Prevention of Air Pollution from Ships.
10. Field Guide to Environmental Compliance, Oil and Gas Production Facility Checklists, US
EPA Archived Document.
Oil and gas exploration and production operations include hazardous activities and have the
potential for a variety of risk exposures and consequences on safety, asset integrity and
occupational health. These ‘risks and potential consequences’ depend upon the stage of the process,
the size and complexity of the project, and the effectiveness of planning, pollution prevention,
mitigation and control techniques.
The purpose of this section is as follows,
• to provide an overview of safety and occupational health issues in the oil and gas
exploration and production industry, and of the best approaches to achieving high
safety and occupational health performance.
Definitions
Occupational Health (OH): Occupational Health is a multifaceted activity concerned with
the prevention of ill health and improving the work environment. Its main aim is to prevent,
rather than cure, ill health from wherever it may arise in the workplace.
Occupational Illness: Any abnormal condition or disorder, other than one resulting from
occupational injury, caused mainly or aggravated by exposure to factors associated with
employment. It includes acute and chronic illnesses or diseases that may be caused by
inhalation, absorption, ingestion or direct contact.
Occupational Hazard: Any article, substance or situation at the workplace that has the
potential to cause harm. A hazard is defined as ‘something with the potential to cause harm’
and a health hazard is something with the potential to adversely affect an individual’s health.
The difference between safety hazards and health hazards is that safety hazards have the
potential to cause sudden injury, whereas health hazards have the potential to cause latent
occupational illness, varying degrees of disability and death.
Occupational Health
A full Health Risk Assessment (HRA) for each activity identified as a significant risk shall be
completed. HRAs shall be documented and available as a functioning tool. HRA process shall be
subjected to periodic audit, to maintain the quality and value of the process. The following hazards
shall be managed in line with recognised good practice:
Domestic/potable water
Food safety
Benzene
Exposure to chemical and biological agents
Fatigue
Stress
Ergonomics
Health risk assessment shall be reviewed whenever there are significant changes and on a regular
basis in order to capture changes that have not been otherwise noticed.
Health Surveillance:
Health surveillance programs shall be put in place in line with findings as indicated by the health
risk assessment. Health surveillance involves specifically examining individuals, in order to
determine if work exposure to health hazards is having a deleterious effect upon their health. The
results may be used in direct management of an individual’s exposure, but may also be useful as
aggregated, or collective, anonymous data to indicate if risk exposure control measures are working
(i.e. as part of the health risk assessment feedback loop.) The Health Surveillance Program shall be
reviewed on a continuous basis to ensure this is effective and helps achieve the following:
Industrial hygiene surveys shall form part of the surveys that shall help determine physical,
chemical and biological exposures to all personnel working at sites. The inputs from these
surveys will feed into the HRAs that would also be conducted on a periodic basis.
Health Surveillance activities shall either be carried out as part of the annual health assessments,
or as special campaigns. e.g. Health Surveillance activities carried out can include following
on a risk-based approach:
Vision screening;
Audiometry;
Blood pressure measurements;
Lung function tests;
ECG;
Cholesterol/blood glucose quick tests;
Urine tests;
Blood analysis;
Stress test.
Conduct Health Surveillance according to agreed Clinical Standards to ensure a consistent level of
screening, with clear fitness criteria.
Sickness Absence Management process shall be put in place to ensure that individuals suffering
illness that causes absence or impairment of work ability are treated in a fair, reasonable and
consistent manner and are given appropriate support to return to meaningful work. Sickness
absence shall be recorded by medical category and duration. Sickness absence levels shall be
recorded including the number of sickness spells and days, as well as the number of cases of
absence of more than 28 days.
A Medical Emergency Response Plan (MERP) shall be developed and maintained, which can be
integrated into a more general Emergency Response Plan, without compromising with
effectiveness of communications. Periodic tests/drills shall be carried out, dependent on risk to test
the potential medical emergency requirements and that shall include; major incident management
with multiple casualties, specific hazard management and first aid procedures. For management of
multiple casualties a Mass Casualty Response Plan (MCRP) shall be developed
Suitable and sufficient first aid provision shall be made available in all areas of operation, including
first aid trained employees, facilities and first aid kits. Designated competent first aiders shall be
made available in line with likely risks and shall be maintained through periodic exercises and
refresher training
Substance Misuse :
Offshore workers and other safety critical employees shall be tested for substance misuse at the
same intervals as routine medicals. Comprehensive Alcohol & Substance Abuse Policy shall be
implemented. Preparation and readiness shall be there at locations and installations to carry out
post-incident (‘for cause’) substance abuse testing, and after considering unannounced testing
programs if thought useful
Safety
Workplace Safety and Injury hazards include:
o Well blowouts
Uncontrolled flow of reservoir fluids into wellbore
Lack of, or ineffective blowout prevention mechanisms
o Fire and explosions (excluding well blowouts)
Presence of highly combustible hydrocarbons
Presence of oxygen and ignition source
o Motor vehicle/Transportation accidents and hazards
Narrow/poor roads to and from well sites
Unsafe driving
Fatigue due to long driving distances/hours and long working shifts
o Other hazards/injuries
Slips, trips, and falls
Accidents due to machinery and other objects
Accidents due to falling objects
The above hazards do occur at various stages of petroleum operations including seismic survey and
evaluation, exploration and appraisal drilling, development and production, and decommissioning.
To that effect:
For any given project, the results from OHS and CHS assessments will be used for health
and safety planning and management prior to and during all stages of the project.
Contractors/Operators should also be equipped with experienced onsite first aid responders
and medical facilities either onsite or offsite with the appropriate training to handle
emergencies related to company’s hazardous operations.
Based on the results from OHS and CHS assessments, the facilities and operations should
be designed to eliminate or minimize the potential for injury and the risk of accidents.
The health and safety planning and management should clearly demonstrate that sufficient
controls have been implemented and effective to reduce risks. The controls should include
a health and safety committee that provides regular training to staff, manages safety
equipment, and ensures compliance of safety protocols during all phases of the project.
between rooms, load-bearing structures that can resist explosions, walls that
can resist explosion.
o Prevent potential electrical ignition sources by proper grounding of electrical outlets
and the use of safe electrical installations
o Maintain a combination of automatic and manual fire alarm systems that can be
heard from across each facility
o Implement safety procedures for loading and unloading of flammable products into
transport systems including ships, rail and tanker trucks, vessels, etc. Safety
procedures should include the use of fail-safe control valves and emergency
shutdown equipment.
o Maintain fire suppression systems, strategically located in safe areas (protected from
fire) within each facility. Fire suppression systems include foam suppression
systems, water suppression systems, CO2 extinguishing systems, portable fire
extinguishers and specialized vehicles. The system maintained should be based on
a fire impact assessment. Check and maintain the fire-fighting equipment regularly.
o Maintain a working fire response plan
o Provide regular training on fire safety and response including the use of fire
suppression systems
o Provide personal protective equipment (PPE) for dealing with fire and explosions
Additionally for offshore operations, consider the following in the design of facilities
o Environmental conditions at the offshore location (e.g., seismicity, extreme wind
and wave events, currents, ice formations)
Install a hydrogen sulfide gas monitoring network with the number and
location of monitoring stations determined through air dispersion modelling,
taking into account the location of emissions sources and areas of
community use and habitation.
Continuous operation of the hydrogen sulfide gas monitoring systems to
facilitate early detection and warning.
Emergency planning involving community input to allow for effective
response to monitoring system warnings.
o For security purposes:
Unauthorized access to facilities should be avoided by perimeter fencing
surrounding the facility and controlled access points (guarded gates). Public
access control should be applied.
Adequate signs and closed areas should establish the areas where security
controls begin at the property boundaries
Vehicle traffic signs should clearly designate the separate entrances for
trucks / deliveries and visitor / employee vehicles
Means for detecting intrusion (for example, closed-circuit television) should
be considered. Facilities should have adequate lighting to minimize
trespassers.
8.2.3 References
1. Environmental, Health and Safety General Guidelines. International Finance Corporation,
World Bank Group. 2007.
2. Environmental, Health and Safety Guidelines for Offshore Oil and Gas Development.
International Finance Corporation, World Bank Group. (2014 draft version).
3. Environmental, Health and Safety Guidelines for Onshore Oil and Gas Development.
International Finance Corporation, World Bank Group. 2007.
4. Recommended Practice for Occupational Safety for Onshore Oil and Gas Production
Operation; API Recommended Practice 74, 2001, 2007.
5. United States National Fire Protection Association (US NFPA) Code 30.
6. OSHA Regulations (Standards -29 CFR),
7. United Kingdom Statutory Instrument (UKSI) 2005, The Control of Noise at Work
Regulations 2005
o Noise permit - documentation of the noise of the operations and reasons for allowing
over the suggested limits for the affected area. This permit is usually necessary
where it might adversely impact wildlife or nearby communities or dwellings.
o To ensure safety and security of public and property from fire and explosion,
the approval of the Chief Controller of Explosives (CCoE) is mandatory for all
electrical equipment installed in potentially explosive atmospheres. The approval of
such equipment is therefore limited to only such areas falling within the jurisdiction
of the Petroleum and Explosives Safety Organization.
o Radioactive materials permit - this permit is needed for handling radioactive
material needed for some logging operations and is the responsibility of the electric
logging contractor; however, the PSC Contractor may need it to ensure no stoppage
of operations.
o Hazardous materials permit - additional permits may be needed if other hazardous
materials are used or anticipated to be encountered during drilling. Permit requires
environmental impact documentation of the hazardous materials, storage, usage,
disposal plan and contingency plan for accidents.
o Permits from other ministries may include forestry, fisheries, agricultural, heritage,
transport, communications, police, defence, etc. These permits often require
environmental impact assessment.
Each country has a different set of requirements specific to their environmental restrictions.
As such, no published universal timelines were found. However, a range of timelines for
approval of various permissions and permits has been given in best practices below.
Permitting time from presentation of the documents to the issuance of the permit can vary
greatly from country to country and permit to permit. It is essential to follow checklists
provided for different permits from various governmental agencies and to make sure these
checklists are current with applicable laws, rules and regulations.
The potential permits and the variance seen worldwide for approval time are given below:
o Building permits - 3 weeks to 3 months
o Environmental Assessment Permit - 1 to 6 months
o Water well permit - 2 to 6 weeks
o Movement permits - 1 week to 3 months
o Dumping/Disposal permits - 3 to 12 months
o Disposal permit - 1 week to 2 months
o Chemical storage permit - 1 to 3 months
o Explosive permit - 1 to 3 months
o Noise permit - 1 to 6 weeks
o Drilling permit - 1 to 6 weeks
o Flaring permit - 3 days to 2 weeks
o Radioactive materials permit - 1 to 4 weeks
o Hazardous materials permit - 1 to 3 months
o Other ministry permits - 2 to 4 weeks
A clear standardized approval process and all needed permits with clear checklist of
required documentation or studies among the various ministries (MoPNG, MoEF & CC,
etc.) with maximum time of approvals (TOAs) for obtaining required permits is
recommended to smooth the transition from exploration to production.
8.3.3 References
1. API RP 51R - Environmental Protection for Onshore Oil and Gas Production Operations
and leases
2. API RP 67 - Oilfield Explosives Safety
3. Timeline estimates from personal knowledge of US, EU, British, Indonesian and Oman
permitting times
impacted in the event of a spill. This information is designed to help personnel involved in
responding to a spill to make reasonable, well-informed choices about protecting public health,
wild life, and the environment. This information could also be used to prioritize the containment
and cleanup effort.
Contingency planning uses hazard identification and vulnerability analysis to develop a risk
assessment. The risk assessment is then used as the basis for planning specific response actions and
strategies to the incident. The plan addresses those problems by determining how best to control the
spill, how to prevent/protect certain populations or environments from exposure to oil, and what can
be done to repair the damage done by the spill. NEBA(Net Environmental Benefit Analysis) is the
tool to be used to prioritize the action plan in responding any such contingencies.
The last step of Contingency planning is to develop response actions to address the risks that are
identified under risk assessment. A carefully designed contingency plan will describe major
actions that need to be taken when a spill occurs. The plan should have strategies, roles and
responsibilities, action plan and description of resource mobilization. These actions should take
place immediately following a spill so as to minimize hazards to human health and the
environment. The response strategies designed for implementation should carefully balance the
ecological, social and commercial concerns and should aim to minimize further adverse impact to
the environment. In selecting response strategies, consideration should also be given to
occupational health and safety risks, response times and other constraints that may limit the ability
of the response teams to undertake specific tasks. The plan should be an actionable plan, not
general in nature. It should provide the specific actions that need to be taken in the case of a given
specific incident.
Once the Contingency Plan is in place, the plan must be tested through training and exercises.
Lessons learned through testing of the plan should be used to review and update the plan.
Consistent practice and improvement can lead to more effective future responses.
The main objective of emergency response planning is to establish a common framework for
developing local response/intervention plans for the various operations carried out by companies.
The final plan provides recommendations, guidelines and technical documentation, based on
industry best practices, to assist the company in developing specific emergency response plans for
its operations.
A well designed and documented contingency plan should have all the
essential components including, but not limited to:
Hazard identification
Vulnerability analysis
Response actions/strategies
Review/Improve/Update
Contingency planning uses hazard identification and vulnerability analysis
to develop a risk assessment. The risk assessment is then used as the basis
for planning specific response actions and strategies.
o Hazard Identification
The Contractor/Operator should identify likely hazardous events and look
for potentially complex hazardous events. The Contractor/Operator should
evaluate all hazards related to all phases of operations. To have an
appropriate contingency plan, the Contractor/Operator should demonstrate
that it has a sufficient level of preparedness to mitigate the consequences of
all the identified hazards.
The following information should always be collected as part of the hazard
identification process for the case of an oil spill hazard:
o Response Actions/Strategies
Describe the actions that should be taken in the event of an incident. These
actions should factor in ecological, social and commercial concerns and take
place immediately so as to minimize adverse impacts to human health and
the environment. The response actions should be developed to address the
risks identified under the risk assessment step. The response strategy should
be an actionable plan with specific actions needed to be taken in the case of
a specific incident.
The following response actions should be included in a contingency plan:
Oil spill response quick guide. A short and clear step by step plan of
action in the event of an oil spill emergency
Spill assessment. Defining the size, position, and content of the spill;
its direction and speed of movement; and its likelihood of affecting
sensitive habitats
Protocol for ensuring the safety of all response personnel and the
public
Source control. Stopping the flow of oil from the ship, truck, or
storage facility, if possible, and preventing ignition
Recovery of the oil spill. Removing the oil and properly disposing of
the oil once it has been removed from the water or land
Tier level response actions for minor, moderate, and major spills
Environmental rehabilitation
might encounter. Such plans will provide specific guidelines for each specific
emergency.
o While the specifics of an emergency response plan may differ with incident and
operations, an adequate emergency response plan should include:
The list and the responsibilities of each member in the emergency response
team
An “Initial Response Quick Guide”
Guidelines for strategic control plans for a particular emergency
Guidelines for daily tactical action plans during emergency operations
Critical response resource requirements and availability
Issues that may adversely affect response and recovery and how to address
them
o Objectives of the Emergency Response Plan
The main objective of an emergency response plan is to provide specific
guidelines, compatible with the Contractor’s/Operator’s other emergency
programs (HSE, Contingency Plan, etc.), and with local/state regulations for
intervening in the event of an emergency.
The emergency response plan should provide a working methodology to
safely and effectively manage the emergency and to regain control of
operations.
Developing an effective/appropriate emergency response plan will require a
comprehensive assessment of potential risks and hazards associated with the
company’s operations within a specific environment. The risks and hazards
assessment should thus incorporate weather conditions and other seasonal
conditions that are prevalent in the region.
Upon development and testing, the plan should clearly:
Provide a ‘quick guide’ of the specific tasks for each member of the
emergency response team. Members are to be familiar with their
specific tasks through drills.
Be community centred
Several agencies (IFC, IPIECA, OGP, API, NDMA etc.) have developed detailed and
relevant guidelines to address oil and gas development issues related to contingency
planning, emergency response planning and disaster management. Such agency guidelines
are recommended for a more exhaustive discussion of international guidelines.
8.4.3 References
1. Environmental, Health and Safety General Guidelines. International Finance
Corporation, World Bank Group. 2007.
2. Environmental, Health and Safety Guidelines for Offshore Oil and Gas Development.
International Finance Corporation, World Bank Group.(2014 draft version).
3. Environmental, Health and Safety Guidelines for Onshore Oil and Gas Development
.International Finance Corporation, World Bank Group. 2007.
4. Guidelines for Offshore Oil Spill Response Plans; API Technical Report 1145, 2013.
5. Emergency response planning in the oil field; International fire fighter, 2010.
6. IPIECA/OGP Contingency Planning for Oil Spills on Water. 2015.
7. National Disaster Management Policy 2009; NDMA.
Procurement Procedure
9.1 Overview of Procurement Procedures
9.1.1 Definitions and Discussion
Oil and gas companies that purchase goods or services under a Production Sharing Contract, have
standard procurement procedures that guide the methods they use to acquire those goods and
services.
The provision of all necessary information that prospective bidders need to prepare their
bids starts with the issuance of bidding documents that include:
o The objectives, scope and expected results of the proposed contract
o The technical specifications of Goods and Services to be procured
o Expected contract duration and delivery schedule
o The obligations, duties and functions of the winning bidder
(In large complex projects, it is not possible to define minimum eligible criteria at EOI
stage)The Procurement Document may contain:
o Invitation to Bid
o Instruction to Bidders including:
Bid Rejection Criteria (BRC)
Bid Evaluation Criteria (BEC)
Bidder’s Qualifying Requirements
o Bid Data Sheet
o General Conditions of Contracts
o Special Conditions of Contract
o Schedule of Requirements
o Scope of Work including technical specifications of the Goods and Services to be
delivered
o Sample forms as annexed
Bid Evaluation Criteria generally stipulate that bids from the tenderers shall conform to the
technical specifications, including the Scope of Work provided in the tender documents.
Bids may be rejected by the procuring agency at its sole discretion in the event the goods
or services offered do not conform to minimum required parameters or technical
specifications. The technical evaluation and the financial evaluation are part of the Bid
Evaluation Criteria.
o During technical evaluation, the following shall be considered:
Compatibility of bids to technical requirements;
Execution methods;
Alternative options offered by bidders;
Information and/or procedures on bidders’ goods or services;
Information on bidders’ technical experience, equipment and employee’s
skills.
o During evaluation of financial offers/bids, the following shall be considered:
Offered price, taxes, tariffs and other alternatives;
Timing of delivery;
Any conditions with regards to contract’s terms;
The specification for goods must be clear and unambiguous so that both the procuring
agency and the tenderer are certain that the same product is being considered. In some cases,
when goods cannot be described in a detailed way, reference to trademarks, patents or
brands may only be made provided the words “or equivalent” are used.
wherever possible, specifications for Goods and Services should be based on International
or National Standards. The advantages of using such standards are that they:
o Represent the views of the whole market
o Ensure that a product will meet a minimum standard of performance in defined areas
o Can help avoid lengthy written specifications
o Can help ensure compatibility of equipment
The provision of goods and services is based on threshold values. The procurement can be
done in one of the following three methods depending on the technical requirements and
the thresholds based on the tender value relating to the cost for these goods and services,
and the desired number of bidders:
o Sole source procurement or purchasing on a nomination basis
o Limited procurement procedure
o Open competitive procurement
That there is no suitable substitute in the market that can be obtained at more
advantageous terms.
Some of these procurement procedures include single-part bid system and two-part bid
system.
o Single-Part Bid System
Under the single-part bid system, both the Techno-Commercial bid and Price
bid are submitted in one envelop.
o Two Part Bid System
The two-part bid system is generally used for the procurement of specialized
goods and services valued more than the single-part system.
Joint Ventures
o In case of a Joint Venture, an Operating Committee should be established in
conformity with the Joint Operating Agreement, and an Operator should be
designated to carry out petroleum operations in conformity with the PSC.
o The Operator’s procurement procedures should be approved by the Operating
Committee and submitted to the Management Committee.
The above best practices are recommended as guiding principles for establishment of
operator’s procurement procedures.
In order to maintain consistency, transparency and fairness, the same tender information,
instructions and guidance during the tendering process should be given to all suppliers and
bidders. Procedures, rules and bid evaluation criteria need to be applied consistently to the
different bids to prevent any actual or perceived discrimination or preferential treatment.
Consistency of this kind can be maintained when clear procedures are documented in
advance, when staff are fully trained in them, and when there is strong continuity in the
people who make up the tender project and advisers.
9.1.3 References
1. Various tender documents and project experience.
Other Areas
10.1 International Requirements for Reporting of Details of E&P
Activities to Ensure Ethical Operations / Share Market Compliance
Definitions and Discussion
10.1.1 Definitions and Discussion
Reporting of oil and gas activities is a requirement in the oil and gas industry. Companies are
expected to report on a regular basis all activities related to Exploration, Reserves, Drilling, Field
development, Production, Well testing, Well stimulation, Well abandonment, EOR, Environmental
impact, Accidents, etc. These reports provide governments and their regulators information
(including compliance information) concerning the activities of their oil and gas contractors and/or
operators. Reporting guidelines differ somewhat from nation to nation and from state to state for
the case of the USA. A summary of some reporting guidelines are provided below.
Norway
o Exploration activities
Detailed plans should be submitted at least 5 weeks before commencement
of exploration activity
Weekly reporting of implementation of exploration activities should be done
Any changes from proposed activities should be submitted as soon as
possible
Reporting about seismic data, gravimetric, magnetic, electromagnetic data,
analysis results, maps and profiles and results from other geophysical and
geological surveys should be submitted as soon as possible but no later than
three months of completion of the individual activities
o Drilling activities
Overall plan must be submitted with Plan for Development and Operations
(PDO)
Drilling program and registration of well paths must be done no later than
15 days before the commencement of drilling
Daily reports from drilling and wells activities should be submitted
o Testing
Plan for formation testing must be submitted in advance but no later than 72
hours before testing
o Reserves
Reserves should be reported by October 15 of each year according to
Norway's resource classification system
United Kingdom
o Exploration
Well and survey data including geophysical surveys, seismic data, well logs,
samples, gravity, magnetic data should be made available as soon as they
are ready
o Drilling
Positioning of the well requires approval from department of energy and
climate change
A minimum of 30-day notice is required for consent to straightforward
drilling operations. Earlier notice will be required for operation in busy
shipping areas
Well must be drilled within one year of consent date
Basic well data, seismic depth map, synopsis describing geologic rationale
and objective of drilling the well should be provided
o Testing/Sampling
Secretary of State's consent should be obtained in advance before flaring the
gas
Well test exceeding 4 days is considered as long term test
Frequency of cutting samples, objective of coring program, mud type, details
of well testing program should be provided in graphical or tabular form
o Production
Oil production, associated gas production, condensate production, gas
injection, water production, water injection, gas utilized, gas sold, etc.,
should be reported partially by the 16th of the following month or fully by
the 30th of the following month
o Loss/dumping of material at sea from oil and gas installations
All loss excluding material legally deposited in accordance with regulations
or unregulated dumping of solid materials should be reported within six
hours of the incident
o Reserves
over 6100 mg/L: Dewater within 30 days and backfill within one
year of completing drilling
Completion pits: Dewater within 30 days and backfill within 120 days of
well completion
o Accidents/Blowouts/H2S
Immediately notify district office by telephone
Write a letter explaining in detail the problems encountered and steps taken
to resolve situation
o Reserves
Every year all publicly listed companies are required to file a 10-K report
classifying reserves according to SEC rules before the end of the year
Activities report
Future plans
10.1.3 References
1. http://www.rrc.state.tx.us/oil-gas/forms/oil-gas-filing-checklist-from-prospect-to-
production/
2. http://www.npd.no/global/engelsk/5-rules-and-regulations/npd-
regulations/ressursforskriften_e.pdf
3. http://www.npd.no/Global/Engelsk/5-Rules-and-
regulations/Forms/RNB/General_Guidelines_RNB2012.pdf
4. https://www.gov.uk/oil-and-gas-petroleum-operations-notices
5. http://www.oiac.co.uk/resources/SORP.pdf
o The framework for facility sharing negotiations was that the facility sharing process
must:
Be fair, equitable, and understandable to all parties
Result in net increase in production, improve resource conservation, and
reduce waste
Not result in any new government regulation
Preserve and promote operational integrity
Preserve the integrity of unit rights/obligations, and tax partnerships
Reduce financial and operational risk
Introduce no significant adverse impact to existing production
Provide timely access to indicative fee structure for bona fide inquirers
Create a level playing field for all producers, where the “best” barrels are
produced
Allow for resolution of conflicts
Compensate the facility owners for their historical capital costs and lost or
deferred production
Provide equitable sharing of ongoing costs among all users
o Components of the facility sharing agreements:
Identification of Facility Owners and their intentions
Identification of Third Party Owners and their intentions
Definitions of Terms
Definition of Facilities that are and are not included in the agreement
Definition of Third Party Facilities that are third party sole responsibility
Standards of Produced Fluids (fluid compatibility and physical limitations)
Priorities Governing Production Processing: This section states that the
facility sharing agreement will maximize the total oil production. In order to
maximize oil production, high GOR and/or high WOR wells will be
curtailed first regardless of ownership. Wells of the facility owner could be
shut-in or curtailed, thereby decreasing the facility owner’s total production.
The volume not produced by the facilities owners is “backed out” to make
room for the third party production. To compensate the owners for this
backout, the backout volume is calculated via a defined process, and
transferred to the facility owners from the third party owners. The third party
owners do not pay fees on the barrels they must give up as backout
compensation.
Produced Water and Seawater: Facility owners will provide to each third
party a volume of water, for water injection that is equal to the volume of
water delivered to the facilities by the third party production.
Excess Water Volumes: To the extent that additional produced water or
seawater volumes are available and desired, facility owners will provide
third party facilities with water volumes in excess of their water production
where needed to maximize and optimize field development. A fee may apply
for this excess volume.
Facility Access Fees, which compensate facility owners for their investment
and ongoing costs incurred to provide facilities and processing of the third
party fluids.
Capital Access Fee, which compensates the facility owners on an adjusted
per barrel processed basis for their past capital investment. This fee
recognizes that the facility owners have invested large sums in the past for
the equipment and facilities that are available to the third party. Generally
this fee would have a depreciation component and a rate of return
component.
Capital Access Fee Surcharge which compensates the facility owners for
capital costs incurred after third party processing begins. This would apply
if the third party does not participate in a joint capital project but the third
party benefits from the project. This fee could be a per barrel charge which
is imposed following increments of capital expenditure.
Abandonment Fee, which compensates facility owners for future
abandonment costs of the facilities.
Abandonment Fee Surcharge, which covers abandonment costs for capital
added after third party processing begins.
Accounting: For purposes of determining volumes of third party oil
processed, the volumes in the monthly production and injection reports filed
with the Alaska Oil and Gas Conservation Commission will be used less any
adjustments caused by backout. Allocation among the owners will be
determined by the parties.
Operating and Maintenance Costs, which compensate the facility owners for
operating and maintenance costs. The costs for any facilities not benefiting
the third party shall be excluded from the calculations.
Plant Liquid Processing Fee, which is a per-barrel fee, determined by
dividing the O&M costs by the volume of total liquid production (oil plus
water) processed in the facilities. The O&M costs can include total plant
labor, direct operating costs and allocated field support costs which are
attributed to gross liquid processing operations but do not include any O&M
costs not benefiting the gross liquid processing operations.
Plant Gas Processing Fee, which is a per-mcf fee, determined by dividing
the O&M costs by the volume of total gas production and lift gas processed
in the facilities. The O&M costs can include total plant labor, direct
operating costs and allocated field support costs which are attributed to gross
gas processing operations but not include any O&M costs not benefiting the
gross gas processing operations. The fee shall be applied to the allocated
volume of fuel gas, flare gas, take-in-kind, shrinkage and lost gas
attributable to third party fluids.
Common Drillsite fee, which is a per barrel fee, determined by dividing the
O&M costs by the volume of total liquid production (oil plus water)
processed in the facilities. The O&M costs can include total drillsite labor,
direct operating costs and allocated field support costs that are attributed to
all drillsite operations but shall exclude charges for operations which do not
benefit the third party. The fee shall be applied to third party gross liquid
production (oil plus water) processed through the facilities less any
adjustments.
Water Fee, which is a per-barrel fee, determined by dividing the O&M costs
by the total make-up water volume made available and used for injection in
all reservoirs. The O&M costs can include total labor, direct operating costs,
and allocated field support costs that are attributed to seawater treatment
plant operations and associated pipelines which carry seawater to the
injection plants. This fee shall be applied to each barrel of make-up water
injected into the third party reservoir.
Ad Valorem Tax Fee: The annual ad valorem taxes chargeable to the third
party shall be determined by multiplying the total annual ad valorem taxes
by the third party adjusted gross liquid production (oil plus water) processed
in the facilities divided by the total liquid production (oil plus water)
processed in the facilities.
Fluids Associated with Backout Oil: The adjusted backout volumes have an
associated volume of water and gas. These volumes of water shall be the
gross third party water production times the adjusted third party backout
volume divided by the gross third party oil production. The gross third party
gas production times the adjusted third party backout volume divided by the
gross third party oil production is the associated gas volume.
Routine Field CAPEX Share: Routine field CAPEX shall be allocated to the
third party owners on third party’s gross liquid production (oil plus water)
processed through the facilities less any adjustments divided by the total
liquid production processed through the facilities.
Joint Capital Projects: A joint capital project may be proposed by either the
facility owners or the third party owners. The percentage voting and
procedure for proposing the projects can be negotiated by the parties and set
forth in this agreement. All construction and modifications shall be owned
solely by the facility owners.
Volume Adjustments
Tax and Royalty: To calculate the net backout share allocated to each
party, the backout volume is adjusted for severance tax and royalty
to keep the receiving parties whole on an after severance tax and
royalty basis.
Allocation and Metering: Third party owners shall pay for all metering
investments required for their fluids. Facility operator will prepare and
maintain all information necessary for the filing of any reports required by
governmental regulatory authorities relating to volume, quality, and
disposition of produced fluids. The unit operator will conduct well tests or
metering as required for the allocation of production and provide
information to all parties.
Gas Supply: Third party owners shall be responsible for fuel gas consumed
by its equipment and a proportionate share of the fuel gas used in the
facilities.
Gas Use and Reinjection: Any gas not used and consumed shall be taken in
kind, reinjected into the third party reservoir or injected into the facility
owners’ (FO) reservoir. The gas injected into the FO reservoir will be
considered indigenous to the FO reservoir and no compensation for the gas
will be given.
Warehouse Sharing: The third party facilities will be permitted to use facility
materials. The material and costs will be negotiated.
Legal and Accounting Rights, which define each party’s legal rights,
indemnity and auditing procedures.
o Trans Alaska Pipeline System (TAPS) transports all North Slope production to
Valdez, where it is loaded onto tankers.
o Other shared services:
Camp and services
Security checkpoints
Shuttle services
Grind and Inject Plant for drilling waste disposal
Terms of service
Tariffs
Accounting
Reporting
Securities transactions
infrastructure, a regulated third party access system has been established. Under this
system, processing and transportation capacity is made available for booking in
auctions. The tariffs are set by the government in the Tariff Regulations and the
transportation agreements are standardized.
o The main offshore Norwegian common carrier oil pipelines are owned by Norpipe
Oil AS, a consortium which includes ConocoPhillips Skandinavia AS (35.05%),
TotalFinaElf Exploration Norge AS (34.93%), Statoil (18.5%), Eni Norge AS
(6.52%), and SDFI (5%). It is operated by ConocoPhillips Skandinavia AS.
Canada
o A framework for infrastructure sharing has been developed, known as the Jumping
Pound formula. The most current formula is given in JP-05. This document provides
a detailed guideline for fee negotiations under a variety of different circumstances
and examples of negotiated fee arrangements.
o Ideally, the fees are successfully negotiated without regulatory intervention or the
need for a prescribed formula. When the parties cannot successfully negotiate an
agreement, the recommended JP-05 fee formula is
20% * Rate Base + Operating Costs + Lost GCA
Where:
Rate base is a negotiated number from original cost to replacement cost.
Operating costs are the same as for facility owners.
Lost GCA reflects the reduced royalty credits on unused capacity capital.
o The formula applies to:
Fees negotiated between producing (E&P) companies needing or holding
unused facility capacity, where such capacity was originally constructed for
a producer’s own use rather than for custom processing
Fees developed by companies that offer midstream processing services
Fees required by CAPL Joint Operating Agreement partners that elect non-
participation in a production facility and elect the fee option under a CAPL
operating agreement
Fees required by freehold mineral rights owners where the fees have not
been specified in the lease agreements
Fees required by parties that elect non-participation in a new facility
development to be the subject of a CO&O Agreement
Brazil
o Sharing of offshore facilities in the Campos basin has been proposed and appears to
be inspired by the success of the UK facility sharing agreements.
Definition of Facilities that are and are not included in the agreement
Definition of Third Party Facilities that are third party sole responsibility
Standards of Produced Fluids (fluid compatibility and physical limitations)
Priorities Governing Production Processing: This section states that the
facility sharing agreement will maximize the total oil production. In order to
maximize oil production, high GOR and/or high WOR wells will be
curtailed first regardless of ownership. Wells of the facility owner could be
shut-in or curtailed, thereby decreasing the facility owner’s total production.
The volume not produced by the facilities owners is “backed out” to make
room for the third party production. To compensate the owners for this
backout, the backout volume is calculated via a defined process, and
transferred to the facility owners from the third party owners. The third party
owners do not pay fees on the barrels they must give up as backout
compensation.
Produced Water and Seawater: Facility owners will provide to each third
party a volume of water, for water injection that is equal to the volume of
water delivered to the facilities by the third party production.
Excess Water Volumes: To the extent that additional produced water or
seawater volumes are available and desired, facility owners will provide
third party facilities with water volumes in excess of their water production
where needed to maximize and optimize field development. A fee may apply
for this excess volume.
Facility Access Fees, which compensate facility owners for their investment
and ongoing costs incurred to provide facilities and processing of the third
party fluids.
Capital Access Fee, which compensates the facility owners on an adjusted
per barrel processed basis for their past capital investment. This fee
recognizes that the facility owners have invested large sums in the past for
the equipment and facilities that are available to the third party. Generally
this fee would have a depreciation component and a rate of return
component.
Capital Access Fee Surcharge which compensates the facility owners for
capital costs incurred after third party processing begins. This would apply
if the third party does not participate in a joint capital project but the third
party benefits from the project. This fee could be a per barrel charge which
is imposed following increments of capital expenditure.
Abandonment Fee, which compensates facility owners for future
abandonment costs of the facilities.
in the facilities divided by the total liquid production (oil plus water)
processed in the facilities.
Fluids Associated with Backout Oil: The adjusted backout volumes have an
associated volume of water and gas. These volumes of water shall be the
gross third party water production times the adjusted third party backout
volume divided by the gross third party oil production. The gross third party
gas production times the adjusted third party backout volume divided by the
gross third party oil production is the associated gas volume.
Routine Field CAPEX Share: Routine field CAPEX shall be allocated to the
third party owners on third party’s gross liquid production (oil plus water)
processed through the facilities less any adjustments divided by the total
liquid production processed through the facilities.
Joint Capital Projects: A joint capital project may be proposed by either the
facility owners or the third party owners. The percentage voting and
procedure for proposing the projects can be negotiated by the parties and set
forth in this agreement. All construction and modifications shall be owned
solely by the facility owners.
Volume Adjustments
Tax and Royalty: To calculate the net backout share allocated to each
party, the backout volume is adjusted for severance tax and royalty
to keep the receiving parties whole on an after severance tax and
royalty basis.
Allocation and Metering: Third party owners shall pay for all metering
investments required for their fluids. Facility operator will prepare and
maintain all information necessary for the filing of any reports required by
governmental regulatory authorities relating to volume, quality, and
disposition of produced fluids. The unit operator will conduct well tests or
metering as required for the allocation of production and provide
information to all parties.
Gas Supply: Third party owners shall be responsible for fuel gas consumed
by its equipment and a proportionate share of the fuel gas used in the
facilities.
Gas Use and Reinjection: Any gas not used and consumed shall be taken in
kind, reinjected into the third party reservoir or injected into the facility
owners’ (FO) reservoir. The gas injected into the FO reservoir will be
considered indigenous to the FO reservoir and no compensation for the gas
will be given.
Warehouse Sharing: The third party facilities will be permitted to use facility
materials. The material and costs will be negotiated.
Legal and Accounting Rights, which define each party’s legal rights,
indemnity and auditing procedures.
o Other shared services:
Camp and services
Security checkpoints
Shuttle services
Grind and Inject Plant for drilling waste disposal
Terms of service
Tariffs
Accounting
Reporting
Securities transactions
Sharing of infrastructure may aid in monetization of marginal fields by lowering the costs
of bringing the fields on production. It is therefore important to have a system in place to
inform operators of the infrastructure near them and to facilitate access and utilization.
10.2.3 References
1. The UK Department of Energy and Climate Change (DECC) lists requirements for onshore
oil and conventional gas field development plans in their document “Guidance Notes for
Onshore Oil and Gas Field Development Plans (October 2009)”. The section on “Annual
Field Reports” addresses issues related to deviations from the agreed FDP.
2. “North Slope of Alaska Facility Sharing Study” prepared for Division of Oil and gas,
Alaska Department of Natural Resources. Bob Kaltenbach, Chantal Walsh, Cathy Foerster,
Tom Walsh, Jan MacDonald, Pete Stokes, Chris Livesey and Will Nebesky, Petrotechnical
Resources Alaska. May 2004.
a. http://dog.dnr.alaska.gov/publications/Documents/OtherReports/NorthSlope_Facil
ity_Sharing_Study.pdf
3. United States Federal Energy Regulatory Commission (FERC)http://www.ferc.gov
4. Norway http://uk.practicallaw.com/6-529-5206#a466457
5. “JP-05: A Recommended Practice for the Negotiation of Processing Fees”, Joint Industry
Task Force Report, prepared by Canadian Association of Petroleum Producers, Gas
Processing Association Canada, Petroleum Joint Venture Association, Small Explorers and
Producers Association of Canada. October, 2005.
a. https://www.aer.ca/documents/reports/JP05.pdf
6. Pedroso, D. C., Abdala, D. C., & Pinto, L. A. G. (2012, April 30). Infrastructure Sharing:
Creating Value for Brazilian Deepwater Offshore Assets. Offshore Technology
Conference. doi:10.4043/23004-MS
10.3 Are there any Unidentified Gaps and Ambiguities in the Indian
PSCs / Contracts?
In review of the NELP-VIII Model Production Sharing Contract, the following observations and
recommendations were made:
Article 21.5.12 states that the Contractor has 10 years from the date of discovery to
commence development of a gas field else the Discovered Area shall be excluded from the
Contract Area; however; there is no such provision in the case of oil. A similar clause for
oil scenario has been suggested.
In the case of assignment of Participating Interest, the date of govt approval may be the date
of issuance of approval letter by MOPNG. In case of CBM Contract, the commencement
of the Development Phase (Phase III and IV) may be considered from the date of issuance
of Mining Lease by the State Government.
References
1. Model Production Sharing Contract (NELP-VIII), Republic of India, 2009.
fault. If so, the claim is passed to the other party. If there is no mutual hold harmless,
the operator’s policy will respond.
o The CGL should include an endorsement for liability to Underground Resources
and Equipment. This endorsement would cover damage to adjacent reservoirs, water
tables, or equipment owned by a nearby operator. This coverage is commonly
available for CGL policies.
o It is common to find Sudden and Accidental Pollution Liability included on the
CGL, subject to the operative clause of the policy requiring Bodily Injury and/or
Property Damage to a third party; but operators should be careful of the discovery
period—the time allowed to discover the loss. Liabilities arising solely from any
obligations imposed by or on behalf of a government authority are typically
excluded.
A separate pollution policy that includes strict clean-up and/or
gradual coverage can be purchased and it is usually written on a
claims-made basis. This is commonly referred to as “Environmental
Impairment Liability” and is provided by a number of specialist
International Insurers. This is a recommended practice for operations
in environmentally sensitive areas.
o The CGL should also include several broadening endorsements if not included in
the form: Waiver of Subrogation if required by contract; Additional insured where
required by contract; Primary and Non-contributory; Cross liability, etc.
o The CGL will exclude control of well costs (blow out, etc.) as this is placed under
a separate policy called Control of Well (COW) or now often referred to as
Operators Extra Expense (OEE).
people, underground blowout, extended redrill, unlimited redrill, making wells safe
or other terms specific to the policy.
o Control of Well events related to labor unrest are generally covered in most policies
at no additional charge, but operators are recommended to check the endorsements
for policy specifics.
Automobile Insurance
o Automobile insurance is often required by law for all road-legal vehicles and written
in the standard manner. All autos owned by the company should carry liability
insurance at a minimum, not forgetting that some rigs and oilfield equipment such
as mobile rigs, cranes and forklifts may be operated on state roadways. Coverage
for hired and non-owned autos should also be considered if employees will be
driving non-owned vehicles. This enables the employees of an operator to be
covered if they are operating leased vehicles. There are broadening endorsements
that can be added onto this policy as well.
Property Insurance
o This is required and written in the standard manner to cover operational facilities
(including removal of debris/wreck) including but not limited to buildings,
equipment, furniture, contents, etc.
o Operators should pay particular attention to the “basis of valuation” clause of their
policy and ensure that they declare values appropriate to the type of coverage being
purchased.
o A special type of property coverage applies to oil companies called Crude Petroleum
in Tanks Coverage that covers oil while it is being stored.
o While Property Insurance does not generally cover any liability, it is important to
keep in order to maintain equipment that might be damaged or stolen.
o Other types of insurance may also include coverage on loss of production income /
business interruption.
Insurance Process
o Insurance is generally obtained through a broker that will assist an operator in
contacting various marketplaces or underwriters to create a policy tailored to the
needs of the Working Interest Parties. Policies should be chosen that reduce liability
and indemnify the Government.
o It is common for governments to require operators to use a local agent to underwrite
the coverage. Depending on the market capacity, it is typically expected that the
domestic marketplace be utilized to procure primary coverage for the smaller
exposures such as workers compensation, automobile liability, D&O insurance,
corporate travel, etc.
o However, in the case of many large exposures such as COW, physical damage or
umbrella liabilities, the domestic marketplace does not contain the sufficient capital
to provide the limits required. As a result these risks are generally reinsured by
international syndicates such as Lloyds of London. In these circumstances a
Reinsurance broker will typically be appointed to arrange the required reinsurance
protection on behalf of a domestic ceding company that will in turn, and upon
confirmation of such protection, be able to issue the relevant policy to the operator.
It is typically a requirement that such reinsurance protection be provided by those
Reinsurers with a financial security rating of A- or above from Standard & Poor’s
and/or AM Best.
o It is highly recommended that Operators carry GCL insurance with a limit sufficient
to cover damage to people, property or equipment reasonably within their sphere of
influence.
o COW coverage is almost universally required. As a rule, the limit for COW
insurance should be sufficient to cover foreseeable remediation (which will vary
depending on the remoteness of the location, operating environment, depth and well
type), re-drilling of the entire well, and cleanup of a sudden event of pollution
(which will depend on the local environment). Careful consideration should be
given to the particular well in question, but COW limits are commonly 3-5 times
the estimated cost of the completed well.
o Additional insurance is recommended for the specific areas of liability and property
that an insured might require for the reasons stated above. Special attention should
be given to insurance which protect people, such as workers compensation.
The above best practices detail the more common types of insurance available to
international oil and gas operators and contain various recommendations. It is the
considered view of this report that at a minimum, operators shall carry, CGL, COW and
property insurance for owned equipment. Other policies should be maintained as required
by law and as appropriate for the operating environment.
In addition to the above practices, it is important to mention that Article 24 of the (NELP-
VIII) PSC for India states that insurance policies shall include the Government as additional
insured and shall waive subrogation against the Government. This is generally permissible
but requires written agreement to do so with the assured and the waived party. Furthermore,
Article 24 states that the Contractor shall indemnify, defend and hold the Government, and
the State Government harmless against all claims, losses and damages of any nature. These
practices are mandated by the PSC and are therefore recommended.
10.4.3 References
1. https://www.travelers.com/business-insurance/specialized-industries/oil-gas/index.aspx
2. Wells Fargo Insurance Services
3. Model Production Sharing Contract (NELP-VIII), Republic of India, 2009.
Costs
o Pre-license costs - Cost that is incurred in the period prior to the acquisition of a
legal right to explore for oil and gas in a particular location.
o License acquisition costs - Costs that are incurred to purchase, lease or otherwise
acquire a property.
o Exploration and appraisal costs - Costs incurred after obtaining a license or
concession but before a decision is taken to develop a field or reservoir.
o Development costs - Costs incurred after a decision has been taken to develop a
reservoir
o Operating costs - Costs of producing oil and gas including costs of personnel
engaged in the operation, repairs and maintenance and materials, supplies and fuel
consumed and services utilized in such operations.
Decommissioning
o The process of plugging and abandoning wells, dismantlement of wellhead,
production and transport facilities and restoration of producing areas in accordance
with license requirements and/or relevant legislation.
Impairment
o Capitalized development costs - a change in circumstances leading to a conclusion
that the recoverable amount from reserves associated with capitalized development
costs is likely to be less than the amount at which those costs are carried in the
books.
Decommissioning activities
o These three basic types of activities must be accounted for using one of the two
above named generally accepted historical cost methods. These methods of
accounting have been described in the sections below.
Accounting Systems
o Successful Efforts Method
The chart below describes the functioning of the Successful Efforts Method
o The primary difference between successful efforts and the full cost is in whether a
cost is capitalized or expensed when incurred. Thus the difference is in the timing
of expense or loss charge against the revenue.
o The second difference between the two methods is the size of the cost center over
which the costs are accumulated. For the successful efforts method the cost center
is the lease, field or reservoir whereas for the full costs method the cost center is the
country.
o Under the successful efforts method only exploratory drilling costs that are
successful are considered to be a part of the cost of finding oil and gas and thus
capitalized. Unsuccessful exploratory drilling costs do not result in any economic
benefit and thus are expensed. In contrast full cost method considers both
unsuccessful and successful costs incurred in search for reserves as a necessary part
of finding oil and gas. Thus, both successful and unsuccessful costs are capitalized
even though the unsuccessful costs have not future economic benefit.
o A comparison of the accounting treatment between the various costs under both
successful efforts method and full costs method is shown in the table below:
If any commercial reserves are found after the appraisal, then the net
capitalized costs which were incurred in the process of discovering
the field should be transferred into a single field cost center. Any
subsequent development costs, should be capitalized in this cost
center.
The accounting policy of the firm should provide the basis under
which cost pools are established, for example geographic area,
region or country.
The aggregate net book value of full cost pools should be disclosed,
together with the aggregate of costs held outside cost pools.
o Production activities
All the expenses under the production activities are expensed under both
Successful Efforts and Full Cost methods of accounting.
Inventory Valuation
impairment tests
deferred taxation
interest
o Capitalized Costs
The aggregate capitalized costs relating to a company’s oil and gas
exploration and production activities and the related depreciation, depletion
and amortization should be disclosed as at the balance sheet date
o Decommissioning
Provisions for decommissioning costs should be separately disclosed in the
balance sheet
Pre-production costs are incurred or provided
Each of the following types of costs should be disclosed in total and by
geographical area for the accounting period:
Development costs
o Results of Operations
The results of operations of oil and gas exploration and production activities
should be disclosed in total and by geographical area
o Commercial Reserve Quantities
The net quantities of a company’s interest in commercial reserves of crude
oil and natural gas should be reported as at the beginning and end of each
accounting period in total and by geographical area
companies do not bother to recognize the inventory of crude oil in lease tanks when
preparing financial statements. Some companies have substantial crude oil
inventories, such as in remote foreign locations or on large ocean-going tankers;
inventories of these types should be reflected in the financial statements.
o Oil and gas inventory is recorded at the lower of cost or market (LCM). Immaterial
inventory may be carried for simplicity at posted field price or similar market price.
o Changes in inventory carrying values are often recorded as an adjustment to lease
operating expense rather than to revenues.
The inventory should be recorded using the lower of cost or market method of inventory
valuation.
10.5.3 References
1. Wright, Charlotte J., and Rebecca A. Gallun. Fundamentals of Oil and gas Accounting.
Tulsa, OK: PennWell, 2008.
2. "SORP Statements of Recommended Practice." Accounting for Oil and Gas Exploration,
Development, Production and Decomissioning Activities, Oil Industry Accounting
Committee, UK: Updated 7th June 2001.
3. Jennings, Dennis R., Horace R. Brock, Joseph B. Feiten, John P. Klingstedt, and Donald
M. Jones. Petroleum Accounting: Principles, Procedures, & Issues. Denton, TX:
Professional Development Institute, 2000. Print.
4. "Financial Reporting in the Oil and Gas Industry: International Financial Reporting
Standards." PwC. PricewaterhouseCoopers International Limited, Sept. 2011. Web. Feb.
2015. <http://www.pwc.com/gx/en/oil-gas-energy/reporting-regulatory-
compliance/publications-financial-reporting-oil-gas-industry.jhtml>.
5. Adere, Endale M. "Accounting for Oil and Gas: The Effect of the Gap between US GAAP
and IFRS on Norwegian Companies." Umea School of Business, May 2011. Web. Feb.
2015. <http%3A%2F%2Fwww.diva-
portal.org%2Fsmash%2Fget%2Fdiva2%3A478518%2FFULLTEXT03>.
6. Cortese, C. L., H. J. Irvine, and M. Kaidonis. "Extractive Industries Accounting and
Economic Consequences: Past, Present and Future." N.p., 2009. Web. Feb. 2015.
<http%3A%2F%2Fro.uow.edu.au%2Fcgi%2Fviewcontent.cgi%3Farticle%3D1533%26co
ntext%3Dcommpapers>.
7. Malmquest, David H. "EFFICIENT CONTRACTING AND THE CHOICE OF
ACCOUNTING METHOD IN THE OIL AND GAS INDUSTRY." Journal of Accounting
and Economics 12 (1990): 173-205. Securities and Exchange Commission, Washington
DC. Web. Feb. 2015.
8. Schugart, Gary. "Workbook on Oil and Gas Accounting." (2002): n. pag. Institute for
Energy, Law & Enterprise, 2002. Web. 2015.
<http://www.beg.utexas.edu/energyecon/Uganda/Oil-&-Gas-Accounting-1.pdf>.
A global, mobile workforce carrying unmanaged devices that grant access to corporate
control and management networks.
In many energy-related firms, rapid growth has introduced greater risk to corporate information,
while increasing IT workloads, and complicating regulatory compliance. The sheer volume of data
now captured and stored by digital oilfield technologies creates real value and significant
challenges. Workflow requirements have changed dramatically. A shrinking workforce means that
fewer skilled professionals and experts are tasked with sharing information across global projects,
a trend that can expose organizations to greater risk. More available data supports improved
collaboration and better insights, but it also raises dramatic new security issues.
E&P firms often have tens of thousands of computers, many of which are now mobile devices
carried all over the globe. Digital IP is easier to transport, which is both a benefit and a risk.
Production and export units must carefully guard project documentation, while meeting technical
reporting requirements for exploration projects. Across the industry, increasingly connected,
collaborative employees need faster access to sensitive systems and data.
The model described in the above steps provides the following guidelines to ensure IT
security by E&P Industry:
o Collaborative Security - Oil and gas organizations can protect their IT infrastructure
and IP assets by deploying advanced security for their key collaborative systems
and data stores.
o Endpoint Protection - Firms should take great care to secure laptops, desktops,
mobile devices such as tablets, and other endpoint systems.
o Hardened Desktops - To ensure desktop security in remote locations, organizations
deploying these systems should follow the best practices for desktop security prior
to sending them up in the field.
o Secure operating systems - A secure OS should build upon a structurally proven
base, while incorporating next-generation technologies, such as solutions for
auditing, user account controls, powerful applications control, and drive- and
device-level encryption controls.
o Server-level protection - The organization must implement servers that are designed
and built to deliver maximum reliability, flexibility, control, and security.
o Data protection - Organizations can better protect data stored on IT operating
systems, with advanced drive-level data encryption.
o Application-level protection - Organizations must ensure the control and security of
mission-critical systems in order to ensure the overall protection of a complex, high-
volume IT infrastructure.
o Access control - Oil and gas companies relying on email, intranet web sites, and
other collaborative systems to manage production, projects, and the work output of
often far-flung employees and partners must secure these systems.
o Active Directory - The organization must ensure the centralized security of the
active directory which would basically be used to manage corporate identities,
credentials, information protection, system and application settings.
o Configuration - To help prevent risks associated with out-of-date hardware,
software, and security systems, oil and gas organizations must carefully manage
configurations throughout their IT reference architecture.
o Compliance - IT administrators need fast, automated systems to configure and
manage computers, data centers, and private cloud environments. They should be
able to compare their internal standards to both industry best practices and
international standards in order to easily create new policies and configurations and
to customize group policies using rich knowledge-based tools.
10.6.3 References
1. Microsoft Best Practices for IT Security
Protect against unauthorized administrators – Ensure all employees have the authorized
access to a particular hardware. Personnel with an access to a particular hardware must
operate that particular hardware only.
Fire Proof – The environment where the device is located must be safe and not have any
incendiary materials close to the device. The environment must also follow standard fire
protection standards by installing smoke detection alarms, sprinklers and all other required
tools.
Use strong codes/passwords – Though the internal system and the software housed in the
device must have a password on its own, the particular location where the device is accessed
must also have a passcode in the form of several forms such as a room door code, rack door
code etc.
Monitoring – Install the latest cameras and sensors for monitoring personnel access within
the room where the device is housed.
Cable Security – Cables must be secured, properly color coded, named, & insulated to
ensure not only personnel safety but also device safety.
E&P Hazard Proof – Environment where the device is kept must not be susceptible to the
following:
o Vehicle Accidents
o Struck-By/Caught-In/Caught-Between
o Explosions and Fires
o Falls
o Confined Spaces
o Chemical Exposures
10.7.3 References
1. http://www.techrepublic.com/blog/10-things/10-physical-security-measures-every-
organization-should-take/
2. http://www.cableorganizer.com/articles/how-to-fireproof-your-server-room.html
3. http://www.brocade.com/downloads/documents/best_practice_guides/Cabling_Best_Pract
ices_GA-BP-036-02.pdf
Integrity
o Data encryption, which locks data by cipher
o Data backup, which stores a copy of data in an alternate location
o Access controls, including assignment of read/write privileges
o Input validation, to prevent incorrect data entry
o Data validation, to certify uncorrupted transmission
Availability
10.8.3 References
1. http://ishandbook.bsewall.com/risk/Methodology/CIA.html
2. https://technet.microsoft.com/en-us/library/bb735870.aspx
3. http://www.zdnet.com/article/10-security-best-practice-guidelines-for-businesses/
4. http://www.cyberciti.biz/tips/raid5-vs-raid-10-safety-performance.html
5. https://www.veracode.com/blog/2012/05/what-is-data-integrity
6. http://www.thedatachain.com/articles/2011/4/top_considerations_for_ensuring_99999_dat
a_availability_in_mid_range_storage
o Design research
o Plan data management (formats, storage, etc.)
o Plan consent for sharing
o Locate existing data
o Collect data (experiment, observe, measure, simulate)
o Capture and create metadata
Processing data
o Enter data, digitize, transcribe, translate
o Check, validate, clean data
o Anonymize data where necessary
o Describe data
o Manage and store data
Storing data
o Estimate capacity and ensure proper capacity planning
o Have multiple mediums of storage such as hard disk drives, tapes and even the cloud
o Ensure timely and scheduled backup of important data
o Ensure all communication channels of backup and DR are up and running
o Ensure spatial as well as geographic replication
Archiving data
o Identify data to be archived
o Create and maintain deletion policies plus data lifecycle management
o Creating an archive policy for the ages
o Implement archiving criteria: search, automation, flexibility
Destroying data
o When drafting written agreements with third parties, include provisions that specify
those data that was provided to the third party must be destroyed when no longer
needed
o Ensure accountability for destruction
10.9.3 References
1. http://www-01.ibm.com/software/data/lifecycle-management/
2. http://www.bu.edu/datamanagement/background/data-life-cycle/
3. http://searchstorage.techtarget.com/feature/Data-archiving-best-practices-Policies-
planning-and-products
4. http://ptac.ed.gov/sites/default/files/Best%20Practices%20for%20Data%20Destruction%2
0%282014-05-06%29%20%5BFinal%5D.pdf
Incorporate insider threat awareness into periodic security training for all employees.
Beginning with the hiring process, monitor and respond to suspicious or disruptive
behavior.
Define explicit security agreements for any cloud services, especially access restrictions
and monitoring capabilities.
Use a log correlation engine or security information and event management (SIEM) system
to log, monitor, and audit employee actions.
Monitor and control remote access from all end points, including mobile devices.
10.10.3 References
1. https://www.cert.org/insider-threat/best-practices/
The current state of IT infrastructure in most oil and gas businesses is unable to adequately support
and respond to analysis, operations, and business needs. In most organizations, the volume of
information is increasing exponentially because digital sensors are deployed in more exploration
and production plays, more data sources are connected to IT systems, and growing volumes of
information are captured and stored in enterprise databases. Large volumes of domain-specific
information are also embedded in various upstream applications. This data situation means it’s
difficult or impossible to use that data to quickly and efficiently get the information and answers
needed.
Data Management
Integration
Collaboration
Performance Management
o Integrated views - Workers need integrated views that reveal all relevant data, both
structured and unstructured, for a particular situation.
o Easily accessible KPIs - Management needs to implement up-to-date KPIs to fully
understand the current status and overall health of an organization.
o Plug-and-play technology - The industry needs an architectural approach that allows
upstream organizations to use more flexible and cost-efficient cloud-based plug-
and-play business logic. If a technology supplier comes up with a better web-based
seismic viewer, the architecture should allow that solution to be deployed quickly
and economically to other cloud-based solutions that could make use of it.
o Integration of structured and unstructured data - Upstream organizations need the
ability to connect and integrate the large volumes of unstructured data generated and
used by non-domain-specific sources, such as word processing and email programs,
unified communications, and collaborative applications. This requirement
recognizes that much of the information needed to manage upstream projects is in
fact hosted in non-domain applications and environments, both on-premises and
increasingly, in the cloud.
o Standards - The organization can implement XML standards-based technologies
such as WITSML, PRODML or RESQML, curated and supported by Energistics to
provide common data interfaces thus providing the foundation needed to ensure
plug-and-play access to best-in-class hardware and software solutions that run both
in the private data center and in the cloud. Further, standard industry database
schemas like the PPDM can be implemented to further support the above.
and wikis. As upstream professionals can use these technologies to manage their
personal connections better to foster cross-discipline collaboration and to better
understand and manage the upstream operations environment.
10.11.3 References
1. Microsoft Best Practices for Data & IT Management
and the government include production sharing contracts, joint venture contracts,
joint operating contracts, farm out contracts, etc. When original
contracts/agreements are violated, oil and gas companies or the consortium of oil
and gas companies can initiate a claim based on violations to the investment contract
and/or violations to an investment treaty or convention. In the oil and gas industry,
cross-border contracts and claims are mostly guided by conventions agreements
and/or treaties including the Energy Charter Treaty (ECT), the Convention on the
Recognition and Enforcement of Foreign Arbitral Awards (also called the New
York Convention), the Washington Convention of 1965 that provided for the
establishment of the International Center for the Settlement of Investment Disputes
(ICSID).
Host states wishing to attract foreign investment often advertise their
willingness to resolve foreign investment disputes using these channels.
Foreign/International companies are encouraged to invest taking comfort
from the fact that they will not be compelled to submit disputes to an
unfamiliar panel.
It is recommended that appropriate dispute resolution clauses be included in
the contracts to allow for the use of these treaties or convention agreements
to resolve potential disputes.
o Company vs. company disputes usually occur between two or more companies.
These disputes usually occur due to contracts violations including, but not limited
to joint operating agreements, unitization agreements, farm out agreements, study
and bid agreements, sale and purchase agreements, and confidentiality agreements.
One prevalent subcategory of company vs company disputes occurs between
operators and service contractors in agreements such as drilling and well servicing,
seismic related activities, construction, equipment and facilities, transportation, and
processing agreements. These disputes make up the majority of disputes in which
oil and gas companies find themselves.
o Individual vs. company disputes usually occur when an individual initiates a claim
against an oil and gas company or contractor for a variety of reasons including
personal injury, contract violations, legal fees, etc.
o During contract negotiations, it is recommended that dispute resolution clauses be
included in the contract to address the prevalent disputes between the parties
involved. An inadequate dispute resolution clause can produce much delay,
expense, and inconvenience. When writing a dispute resolution clause, keep in mind
that its purpose is to resolve disputes, not create them. Whenever disagreements
arise over the meaning of a dispute resolution clause, it is often because it failed to
address the particular needs of the parties. Use of standard, simple and straight
forward language may avoid difficulties. Drafting an effective dispute resolution
agreement is the first step on the road to successful dispute resolution.
o Disputes in the oil and gas industry are generally resolved either through litigation
or through alternative dispute resolution (ADR) channels. Alternative dispute
resolution channels include arbitration, mediation, expert determination,
reconciliation, etc. Of these dispute resolution techniques, dispute resolution
through litigation and arbitration are binding. Dispute resolution through arbitration
is currently considered the principal method of dispute resolution in the oil and gas
industry, especially when there is an international contract spanning many countries.
o Dispute Resolution through Litigation
Dispute resolution through litigation usually results when the disputing
parties are unable to resolve the dispute through ADR channels. Under these
circumstances one party, the claimant/plaintiff, files a lawsuit against
another party, the defendant, to enforce a particular right or action. The
litigation process is presided over by a judge or jury who listens to the
arguments and witnesses of both parties and then passes a judgment which
becomes binding, subject to appeal.
Oil and gas dispute resolution through litigation are most frequently used in
the domestic energy business with parties from the same jurisdiction (for
example in the U.S., in Canada, the in the UK, in Australia, and in India). It
is, however, not the preferred forum for international disputes for a number
of reasons including problems in enforcing court judgments in foreign
jurisdictions, cost and length of trials, and antipathy to local courts by
foreign investors. As a result, it is rarely chosen as a dispute resolution
mechanism in international oil and gas agreements. Litigation is sometimes
chosen in oil and gas agreements when all the parties come from the same
jurisdiction and they are all comfortable with the courts of their home
country.
As in the other industries, litigation in the oil and gas industry is a formal
process in which both sides to the dispute provide their version of the dispute
and are given enough time to provide evidence to support their argument.
As indicated, dispute resolution through litigation often results if the
disputing parties are unable to resolve their disputes through arbitration. In
certain instances, the process starts with arbitration and ends up in the courts.
Under these circumstances, the process could be lengthy and expensive
depending also on the complexity of the conflict, with no way to fast track
the process. The duration of the process could also depend on the case load
of the court assigned to the case. In some countries, including India for
example, dispute litigation through the court could experience significant
delays due to backlogs within the court system.
o Dispute Resolution through Arbitration
Arbitration involves the resolution of disputes between two or more parties
through a voluntary or a contractually required hearing with determination
The clause could specify the specific method(s) of dispute resolution. For
example, it could specify only arbitration – which yields a binding decision
– or also provide an opportunity for non-binding negotiation or mediation.
The dispute resolution clause should be signed by as many potential parties
(e.g. contractors) to a future dispute as possible.
To be fully effective, “entry of judgment” language in domestic cases is
important.
It is normally a good idea to state whether a panel of one or three arbitrator(s)
is to be selected, and to include the place where the arbitration will occur.
If the contract includes a general choice of law clause, it may govern the
arbitration proceeding. The consequences should be considered.
The parties are free to customize and refine the basic arbitration procedures
to meet their particular needs.
currently over 150 parties to this convention. This makes the enforcement of
arbitral awards easier and more widespread in the sense that a party to a
dispute is able to enforce an award rendered in one contracting state into any
of the other contracting states. To access the benefits of this convention the
seat of the arbitration should be in a country that is a signatory to the
convention and the counter-party (or its assets) against whom an agreement
or award is to be enforced should be from a country that is a party to the
New York Convention.
o The Washington Convention
The Washington Convention of 1965 also addressed issues related to the
settlement of investment disputes between nation states and citizens of other
countries. The Convention created the International Centre for Settlement of
Investment Disputes (or ICSID). The ICSID, an autonomous international
organization and a member of the family of World Bank Institutions,
provides facilities for the arbitration of investment disputes between host
governments and foreign investors. ICSID jurisdiction is limited to disputes
occurring between a contracting state and a national of another contracting
state. Although parties must consent in writing to submit disputes to the
ICSID, such consent may be expressed in bi-lateral treaties and foreign
investment laws as well as in contracts. The Convention was primarily
designed to create investor confidence, and to promote inward investment
into developing countries.
o The Energy Charter Treaty (ECT)
The ECT is an international agreement which establishes a multilateral
framework for cross-border co-operations in the energy industry. The treaty
covers all aspects of commercial energy activities including trade, transit,
investments and energy efficiency. The treaty is legally binding, including
dispute resolution procedures. Companies and states should structure their
investments and negotiate their contracts to take advantage of the investment
protection provided by the ECT and other related treaties.
o International Arbitration Institutions
There are many arbitral institutions in the world but the major ones are three
namely, the International Chamber of Commerce (ICC) International Court
of Arbitration, the American Arbitration Association’s International Center
for the Dispute Resolution (ICDR), and the London Court of International
Arbitration(LCIA).
The rules of the ICC, LCIA and ICDR are all suitable for use around the
world and for arbitrations conducted in various languages and under various
governing laws. In each case, it is for the arbitrators to resolve the dispute,
with the institutions simply administering the arbitrations. In this capacity,
the ICC, LCIA and ICDR each receive and distribute the parties’ initial
submissions, assist with the appointment of the tribunal (with or without
Ad hoc Arbitrations
o Ad hoc arbitrations are non-institutional arbitrations that often arise because parties
do not agree upon (or simply fail to provide for) any institutional arbitration. Parties
sometimes believe that, by avoiding the fees of arbitral institutions, ad hoc
arbitration might prove cheaper than institutional arbitration. Whilst this is possible
in theory, in practice, the benefits of the institution’s administrative services and the
lower charges of arbitrators under institutional rules can easily outweigh the costs
involved, especially in connection with large and complex disputes, where many
procedural issues are likely to arise. Ad hoc arbitration significantly increases the
likelihood of court intervention and these potentially significant costs must also be
considered. Prior to selecting ad hoc arbitration, parties should satisfy themselves that
they would not be better served by an institutional form of arbitration.
In fact, the Indian law is far more restrictive in laying down the extent of judicial intervention
(compared to the UNCITRAL Model Law). Section 5 of the Act provides that notwithstanding
anything contained in any other law for the time being in force, in matters governed by (this) Part
(i.e., Part I Arbitration), no judicial authority shall interfere except where so provided for. Section
8 of the Act, further provides that a judicial authority before which an action is brought in a matter
which is the subject matter of an arbitration agreement shall, on application of a party to the
arbitration agreement, or a person claiming through or under him, refer the parties to arbitration
unless it finds that prima facie no valid arbitration agreement exists. These departures made by the
Indian law demonstrate the legislative intent to minimize judicial intervention in arbitration
matters. By and large the Indian courts have well understood the spirit and intent behind the
principle of non-intervention. [Pl. see CDC Financial Services (Mauritius) Ltd v BPL
Communications: 2003 (12) SCC 140]. The Act, as seen above, allows full freedom to the parties
in the matter of appointment of arbitrators. However, if the parties fail to reach an agreement,
recourse is made to the court. The Act also enables parties to adopt an appointment procedure under
which any institution may be given specific roles in such appointment. However, in practice, resort
is seldom made to such institutional arrangements in the matter of appointment of arbitrators. The
process of ‘running to the court’ has proven to be a stumbling block in Indian arbitration. The
process has impacted significant delays to Indian arbitration based on the availability of the court.
The Arbitration and Conciliation (Amendment) Ordinance, 2015, seeks to address this issue by
insertion of a new sub-section (13) in section 11 of the Act to the effect that an application made
under the said section for appointment of an arbitrator or arbitrators shall be disposed of by the
Supreme Court or the High Court or the person or institution designated by such Court, as the case
may be, as expeditiously as possible and an endeavour shall be made to disport of the matter within
a period of sixty days from the date of service of notice on the opposite party..
o As a result of the full flexibility to appoint arbitrators given by the Act, the tendency
has been to use ad hoc arbitrators in Indian arbitration. The use of institutional
arbitration is yet to take off in any significant measure in India. Arbitration has more
or less been essentially relegated to the arbitrators themselves, without an
established time frame to conclude the arbitration or an established fee structure.
The arbitrators essentially control the arbitration time table and the fees, thus leading
to additional unnecessary delays and cost.
The recent amendments introduced in the Act through the Arbitration and Conciliation
(Amendment) Ordinance, 2015, seek to address only one of these two issues, namely, the lack of a
time-frame for making of arbitral award, by insertion of a new section 29A. which now specifies a
time limit for making the arbitral award (twelve months extendable by six months by consent of
the parties) and also provides for automatic termination of the mandate of the arbitral tribunal upon
expiry of the time period unless the Court has extended the period. However, as regards
management/administration of the arbitration process, concerted efforts are needed towards
creation and promotion of effective institutional mechanisms, so that the arbitral process becomes
streamlined and cost effective to parties. With the ICC, LCIA and ICDR, and similar institutions,
the institution essentially appoints the arbitrators, defends the arbitrators (in the case of a challenge)
and simply administers the arbitration process, which saves both time and costs for the parties.
The need to promote institutional arbitrations without having resort to court intervention seems to
be the need of the hour in order to achieve the purpose behind the relevant provisions of the Act.
o The Act is equally plagued by certain sections that render arbitral awards more or
less unenforceable. Challenges to arbitration awards can equally be tied up within
the court system for years. These delays and other technicalities have handicapped
the functioning of the Act significantly. There is thus the need to reform certain
sections of the Act
o It is recommended that an institutional arbitration structure be promoted and/or
implemented. Any adopted reform should also seek to implement a fee structure
with a potential ceiling to fees. With sufficient reforms, the entire arbitration process
will once again play the role it was meant to play.
taking comfort from the fact that they will not be compelled to submit disputes to an
unfamiliar channel/court. These recommendations equally apply to independent oil and gas
operators doing business with the state. By clearly stating the channels for dispute resolution
up front, unnecessary disputes on how to resolve disputes can be avoided.
Provided below are sample international dispute resolution through arbitration clauses that
can be considered for inclusion as part of a contract. These clauses can also be customized
for inclusion into contracts between national oil and gas operators and the state.
o Any controversy or claim arising out of or relating to this contract shall be
determined by arbitration in accordance with the rules of Arbitration contained in
the Arbitration & Conciliation Act, 1996[].
o Any dispute, controversy, or claim arising out of or relating to this contract, or the
breach thereof, shall be finally settled by arbitration administered by Indian
Council of Arbitration, The International Centre for Alternate Dispute Resolution
(ICADR) or any other body functional under the Arbitration & Conciliation Act,
1996 in India.[………..].
o Any dispute, controversy, or claim arising out of or relating to this contract, or the
breach, termination, or invalidity thereof, shall be settled by arbitration under the
UNCITRAL Arbitration Rules in effect on the date of this contract. The appointing
authority shall be as decided by the parties under the respective contract
[]…………... The case shall be administered by Indian Council of Arbitration, The
International Centre for Alternate Dispute Resolution (ICADR) or any other body
functional under the Arbitration & Conciliation Act, 1996 in India .[…………]
under its Procedures for Cases under the UNCITRAL Arbitration Rules.
Disputes in the oil and gas industry are generally resolved either through litigation or
through alternative dispute resolution (ADR) channels. Alternative dispute resolution
channels include arbitration, mediation, expert determination, reconciliation, etc. Of these
dispute resolution techniques, dispute resolution through litigation and arbitration are
binding. Dispute resolution through arbitration is currently considered the principal method
of dispute resolution in the oil and gas industry, especially when there is an international
contract spanning many countries. In some cases, an informal resolution from technical
experts is advisable before pursuing arbitration.
10.12.3 References
1. Dispute resolution in oil and gas; Muhammad Waqas, Oil and Gas Financial Journal,
January 13, 2015.
2. International dispute resolution; Tim Martin, Independent Petroleum Association of
America & Association of International Petroleum Negotiators.
3. Dispute resolution in oil and gas industry: Why Do Participants in the Oil and Gas Industry
Prefer International Commercial Arbitration to Litigation; Raphael Bahati Tweve Mgaya,
Tanzania Petroleum Development Corporation (TPDC).
4. Drafting Dispute Resolution Clauses, A Practical Guide; The American Arbitration
Association.
5. Guide to International Arbitration; Latham and Watkins, 2014.
6. Alternative Dispute Resolution Guidelines; The World Bank Group, 2011.
and extracted. These contracts need to be managed carefully with specific obligations from all
parties.
Evaluate the progress of the PSC, ensuring all deliverables are satisfactorily completed
Management Committee
o A Management Committee shall be established in a timely fashion (usually 30 days)
following the Effective Date for the purpose of providing orderly direction on all
matters pertaining to the Petroleum Operations and Work Program. Within such
period each of the GOVERNMENT and the CONTRACTOR shall by written notice
nominate its respective members of the Management Committee and their deputies.
o The Management Committee shall comprise an equal number of members
designated by each Party. For example: two (2) members designated by the
GOVERNMENT and two (2) members designated by the CONTRACTOR. Upon
ten (10) days’ notice, each Party may substitute any of its members of the
Management Committee. The chairman of the Management Committee shall be one
of the members designated by the GOVERNMENT (the “Chairman”). The vice
chairman of the Management Committee shall be one of the members designated
by the CONTRACTOR (the “Vice-Chairman”). In the absence of the Chairman, the
Vice-Chairman shall chair the meeting. Each Party shall have the right to invite a
reasonable number of observers as deemed necessary to attend the meetings of the
Management Committee in a non-voting capacity.
o The Management Committee shall review, deliberate, decide and give advice,
suggestions and recommendations to the Parties regarding the following subject
matters:
Work Programs and Budgets;
the CONTRACTOR's activity reports;
production levels submitted by the CONTRACTOR, based on generally
accepted practice in the international petroleum industry;
accounts of Petroleum Costs;
procurement procedures for potential Subcontractors, with an estimated
subcontract submitted by the CONTRACTOR;
any terms of reference which are required to be prepared and agreed for the
purposes of expert determination; and
any matter having a material adverse effect on Petroleum Operations.
o Either Party may call an extraordinary meeting of the Management Committee to
discuss important issues or developments related to Petroleum Operations, subject
to giving reasonable prior notice, specifying the matters to be discussed at the
meeting, to the other Party. The Management Committee may from time to time
make decisions by correspondence provided all the members have indicated their
approval of such decisions in such correspondence.
Government Assistance
o To the extent allowed by the State law and at the specific request of the
CONTRACTOR, the GOVERNMENT shall take all necessary steps to assist the
CONTRACTOR in, but not limited to, the following areas:
securing any necessary Permits for the use and installation of means of
transportation and communications;
securing regulatory Permits in matters of customs or import/export;
securing entry and exit visas, work and residence permits as well as any other
administrative Permits for CONTRACTOR's and its Subcontractors’ foreign
personnel (including their family members) during the implementation of
this Contract;
securing any necessary Permits to send Abroad documents, data or samples
for analysis or processing for the Petroleum Operations;
relations with federal and local authorities and administrations;
securing any necessary environmental Permits;
Additionally, the Government should create conditions for the industry to be self-regulating
10.13.3 References
1. US Federal Oil and Gas Regulations
2. PSC for Kurdistan Regional Government of Iraq
3. Model Production Sharing Contract (NELP-VIII), Republic of India, 2009
4. Johnston, Daniel. 1994. International Petroleum Fiscal Systems and Production Sharing
Contracts. Tulsa, OK. PennWell Publishing Company.
selling such 20% in the national market, the international reference price
shall not be reduced by computing any export restriction. The Commission
shall establish a compensation mechanism between the local price and the
international price which shall be payable in Argentine pesos. When the sale
of such 20% is performed in the national market, the producer seller will
have a “priority right” to freely exchange proceeds to any other currency in
the government regulated exchange market.
Possibility of extending the life of concessions: The decree creates the
category of “Non-conventional Hydrocarbon Exploitation” which consists
of extraction of liquid or gas hydrocarbons through non-conventional
stimulation techniques in formations, which are characterized by low
permeability. This category includes shale gas or shale oil, tight sands, tight
oil, tight gas and coal bed methane. Companies that are holders of
exploration permits or exploitation concessions and which have been
included in the Regime for the Promotion of the Investment for Hydrocarbon
Exploitation shall be entitled to a concession of “Non-conventional
Hydrocarbon Exploitation.”
Any exploitation concession allows the company to exploit both
conventional and non-conventional resources within the concession area. A
current concession holder may apply for a non-conventional concession and
thus be shall be entitled to a new concession for a term of 25 years. This 25
year term may be extended for an additional 10 years. Such 10-year
extension may be granted during the initial authorization of the concession.
Additionally, if the concession holder proves geographic continuity of the
conventional and non-conventional fields, the concession holder may
request that the areas be unified in the single new non-conventional
concession, thereby extending the life of the original concession for up to 35
years. If the areas are unified, the concession holder must exploit the non-
conventional resources and but also has the right to develop the conventional
resources.
If it is not possible to unify the areas into a single non-conventional
concession, the area of the original concession shall be subdivided into a
conventional concession and a non-conventional concession. The
conventional part of the concession shall expire on the date originally
stipulated.
Incentives for
Timing of
State Base Tax Rate Unconventional
Collections
Production
o The table below summarizes the state tax incentives for unconventional Natural Gas
in US. The states include Arkansas, Louisiana, New Mexico, Oklahoma,
Pennsylvania, Texas and Wyoming.
Annually, due in
Pennsylvania Annual fee schedule set by N/A
April following
the Public Utility
the calendar year
Based on the Colombian example, it is proposed to allow for an extended exploration period
in the case of discovery of unconventional hydrocarbons.
10.14.3 References
1. Regulatory Framework of Unconventional Hydrocarbons in Colombia
2. Argentina: Amendment of the Hydrocarbons Law
3. Argentina Announces: New Incentives to Foster Investment in Oil and gas Sector
4. Unconventional Oil and Natural Gas Production Tax Rates
Shale oil/gas is crude oil or natural gas trapped within shale rock formations underground.
Advances in hydraulic fracturing or "fracking" – the process of forcing fluids at high
pressure into wellbores to fracture the shale rock, allowing the oil/gas to escape.
Coalbed methane (CBM) refers to methane that is found in coal seams and is widely
considered as an unconventional source of natural gas. Typical recovery entails pumping
water out of the coal to allow the gas to escape. Methane is the principal component of
natural gas. Coalbed methane can be added to natural gas pipelines without any special
treatment. Numerous regulations designed to regulate conventional natural gas
development can and do apply to CBM exploration and exploitation. However, due to the
differences in produced water volumes and quality, well spacing, and utility infrastructure,
specific CBM regulations have been drafted by federal, state and local regulating agencies
to meet various concerns.
For CBM production to qualify, the well must have been spudded between
December 31, 1979, and January 1, 1993. The site must have been prepared,
the drilling rig set up, and the initial borehole begun. Further, capital to drill
to total depth must have been committed. At the end of December 1992,
Congress allowed Section 29 to expire.
Well setback from surface water (such as rivers) and water wells is
widely regulated, though not as widely as building setback. Of the
states surveyed, 12 have setback restrictions from some body of
water or water supply source; 9 of those have setback restrictions
from municipal water supplies (measured from the well) ranging
from 50 feet to 2,000 feet, with an average of 334 feet.
Pre-Drilling Water Well Testing Requirements
Only two states (Arkansas and New York) require production casing
to be cemented to the surface. Twelve states have specific regulations
for how much cement must be circulated. These rules vary and are
measured from similar but slightly different points. An additional 10
states regulate cementing of the production casing in their permit
processes.
Venting Regulations
Venting occurs when gas escapes from the wellbore into the
atmosphere. More than half of states surveyed (22) have some form
of venting regulations, though these vary greatly across states. Some
states have specific restrictions such as the number of days that
venting may occur, the amount of gas that may be vented, or the
development phases during which gas may be vented. That is, some
states specify that venting may be allowed during well cleanup, well
testing, and emergencies, but at no other time. Some states have
“aspirational standards,” which require operators to minimize gas
waste or not to harm public health, but impose no effective
requirement or standard. Louisiana prohibits venting unless it can be
shown that the prohibition causes economic hardship. API suggests
that all gas resources of value that cannot be captured and sold should
be flared, but that any venting be restricted to a safe location and
oriented downwind considering the prevailing wind direction at the
site.
Flaring Regulations
Water makes up by far the largest share of fracturing fluid, and the
fracturing process requires several million gallons per job. Several
states have discussed drafting water withdrawal restrictions specific
to the shale gas industry, but none has yet passed such legislation. Of
the states surveyed, 30 do generally regulate surface and
groundwater withdrawals, however. Some require permits for water
withdrawals, others require registration and reporting, and a few
require both.
Fracking Fluid Disclosure Regulations
Fluid storage needs vary over the course of the shale gas
development process. Fracking fluids must be stored before being
used, and the post-fracturing wastewater, including flowback fluids
and produced fluids, must also be stored before disposal. There are
many different types of pits, including permanent and temporary pits,
and different pits have distinct specifications, such as whether or not
they require lining. Fluids are most commonly stored in pits and
tanks; 9 surveyed states only specifically address pit storage and 19
specifically mention pits and tanks in their regulations. California
mandates a closed-loop systems in which fluids are not exposed to
the elements at any point. Michigan only allows pits to be used for
drilling fluids, muds, and cuttings; tanks must be used for produced
water, completion fluids, and other liquid wastes, and in all areas
zoned residential. Other storage options include ponds, sumps,
containers, impoundments, and ditches. API best practice stipulates
that “completion brines and other potential pollutants should be kept
in lined pits, steel pits, or storage tanks.”
Freeboard Requirements
Pit liners prevent fluids from seeping into the ground and potentially
contaminating groundwater. Most of the states surveyed that allow
fluid storage in pits (18) require pit liners. Of those states, 11 have
specific regulations about the thickness of the liners and several
states have other regulations such as permissible liner materials (for
example. re-compacted clay liners, soil mixture liners, and synthetic
liners). Alabama, Montana, and Wyoming all have conditional
requirements for pit liners, such as Alabama’s rule that liners are
only required if the bottom of the pit is not above the seasonal high
water table. Wyoming requires them only if it is “necessary” to
prevent contamination of surrounding ecosystems. California does
not allow the use of pits for fluid storage, thus pit liner requirements
are not applicable. API best practice is that “depending upon the
fluids being placed in the impoundment, the duration of the storage
and the soil conditions, an impound lining may be necessary to
prevent infiltration of fluids into the subsurface.”
Waste Water Transportation Tracking
Several state and local governments have passed bans and moratoria
on various parts of the horizontal drilling and hydraulic fracturing
process. New York State, in addition to a statewide moratorium, has
more than fifty local bans and moratoria. Several states with local or
municipal bans are currently in litigation over the legality of local
regulation of shale gas extraction. Two New York judges recently
upheld local ordinances banning the practice, whereas a judge in
West Virginia ruled a local ordinance unconstitutional and
unenforceable. Texas and Colorado do not allow local or municipal
bans, but several local governments in these states have passed
moratoria on the shale gas development process. On the map, the
New Jersey and Maryland numbers indicate the number of years the
moratoria are set to run, beginning in January 2012 and June 2011,
respectively. As of June 2012 New Jersey has six months remaining
and Maryland has two years.
Severance Tax Calculation Method
Severance taxes are taxes imposed on gas production. Each state has
a different rate, and states use one of two methods to calculate the
tax-either a percentage of the market value of the gas extracted or a
fixed dollar amount per quantity extracted. Some states use a hybrid
approach in which the percentage tax varies between different levels
based on the gas price. Rates may also vary based on production,
well vintage, or other factors. For example, in Montana, the tax rate
is 0.5 percent for the first 18 months of a well’s operation (compared
to 9 percent thereafter). In Utah, if the price of gas is below $1.51
per MCF the tax rate is 3 percent, and in Colorado the tax rate is set
based on total net gross income, with the lowest rate (2 percent)
pertaining to total net gross income less than $25,000 and the highest
(5 percent) pertaining to total net gross income greater than or equal
to $300,000. Some states (such as Maryland and Virginia) leave the
question of severance taxes to local governments, though Maryland
is debating a 4.5 percent statewide severance tax which would be
imposed on top of any local taxes (currently Allegany County’s 7
percent and Garrett County’s 5.5 percent tax). Virginia limits local
severance taxes to 1 percent. Several states offer incentive programs
that can reduce severance tax burdens. Louisiana, for instance, offers
discounts for “incapable” wells; Montana offers a decreased rate for
“nonworking interests;” Oklahoma lowers the tax according to the
price of gas at market; and Texas can lower taxes for high-cost wells
and inactive wells. Pennsylvania recently passed an “impact fee” that
provides funds to the communities where drilling is occurring to
alleviate the cost of burdens, such as road repairs, environmental
damages, and other issues. Georgia and Vermont do not have
severance taxes but that is not surprising since they do not have
production.
Selected Federal Actions Related to Unconventional Oil and Gas Production (USA)
o EPA: Clean Air Act (CAA)
Air emissions. In 2012, EPA issued regulations that revised existing rules
and promulgated new ones to regulate emissions of volatile organic
compounds (VOCs), sulfur dioxide, and hazardous air pollutants (HAPs)
from many production and processing activities in the oil and gas sector that
had not been subject previously to federal regulation.
Particularly pertinent to shale gas production are the New Source
Performance Standards (NSPS), which require reductions in emissions of
VOCs from hydraulically fractured natural gas wells. The rules require
operators to use reduced emissions completions (green completions) for all
hydraulically fractured natural gas wells beginning no later than January
2015.
Applying broadly across the sector, the NSPS require reductions of VOCs
from compressors, pneumatic controllers, storage vessels, and other
emission sources, and also revise existing standards for sulfur dioxide
emissions from onshore natural gas processing plants, and HAPs from
dehydrators and storage tanks.
In September 2013, EPA updated its 2012 performance standards for oil and
natural gas to address VOC emissions from storage tanks used by the crude
oil and natural gas production industry. The updates are intended to ensure
tanks likely to have the highest emissions are controlled first, while
providing tank owners and operators time to purchase and install VOC
controls. The amendments reflect recent information showing that more
storage tanks will be coming on line than the agency originally estimated
(thus, presumably, producers need more time to purchase and install
emission controls).
In July 2014, EPA proposed updates and clarifications to NSPS
requirements for well completions, storage tanks, and natural gas processing
plants. The proposal would not change the required emission reductions in
the rules, including standards applicable to hydraulically fractured natural
gas wells.
o EPA: Clean Water Act (CWA)
Wastewater discharge. Produced water and flowback from hydraulic
fracturing have high levels of total dissolved solids (TDS), largely chlorides,
which can harm aquatic life and affect receiving water uses (such as fishing
or irrigation). EPA is updating its chloride water quality criteria for
protection of aquatic life.
CWA Section 304(a)(1) requires EPA to develop criteria for water quality
that reflect the latest scientific understanding of the effects of pollutants on
aquatic life and human health. States use EPA-recommended criteria to
establish state water quality standards, which in turn are used to develop
enforceable discharge permits.
If reflected in state water quality standards, the revised chloride water
quality criteria could affect discharges of produced water from extraction of
conventional and unconventional oil and gas.
In 2011, EPA indicated that it was initiating two separate rulemakings to
revise the Effluent Limitations Guidelines and Standards (ELGs) for the Oil
and Gas Extraction Point Source Category to control discharges of
wastewater from (1) coalbed methane (CBM) and (2) shale gas extraction.
Under CWA Section 304(m), EPA sets national standards for discharges of
industrial wastewater based on best available technologies that are
economically achievable (BAT).
States incorporate these limits into discharge permits. Shale and CBM
wastewaters often contain high levels of total dissolved solids (TDS—i.e.,
salts), and shale gas wastewater may contain chemical contaminants,
naturally occurring radioactive materials (NORM), and metals.
Discharges to surface water: Currently, shale gas wastewater may not be
discharged directly to surface waters. CBM wastewater is not subject to
national discharge standards; rather, CBM wastewater discharge permits are
based on best professional judgments of state or EPA permit writers. EPA
was working to develop regulatory options to control direct discharges of
CBM wastewaters, but determined in 2013 that no economically achievable
technology was available.
Discharges to treatment plants: Current ELGs lack pretreatment standards
for discharges of shale gas or CBM wastewaters to publicly owned
wastewater treatment works (POTWs), which typically are not designed to
treat this wastewater. EPA is developing national pretreatment standards that
shale gas and CBM wastewaters would be required to meet before discharge
to a POTW to ensure that the receiving facility could treat the wastewater
effectively.
o EPA: Emergency Planning and Community Right-to-Know Act (EPCRA)
Chemical disclosure. EPA has been considering an October 2012 petition by
nongovernmental organizations to subject the oil and natural gas extraction
industry to Toxics Release Inventory (TRI) reporting under EPCRA. Section
313 of EPCRA requires owners or operators of certain industrial facilities to
report on releases of toxic substances to the state and EPA. EPA and states
are required to make nonproprietary data publicly available through the TRI
website.
o EPA: Safe Drinking Water Act (SDWA)
Diesel fuels. EPA has issued UIC Program Guidance for Permitting
Hydraulic Fracturing with Diesel Fuels in response to the revised SDWA
definition of “underground injection” in the Energy Policy Act (EPAct) of
2005 to explicitly exclude the underground injection of fluids (other than
diesel fuels) used in hydraulic fracturing. The guidance provides
recommendations for EPA permit writers to use in writing permits for
hydraulic fracturing operations using diesel fuels. The guidance applies in
states where EPA implements the UIC program for oil and natural gas
related (Class II) injection wells. States are not required to adopt the
guidance, but may do so.
o EPA: Toxic Substances Control Act (TSCA)
The above regulations and guidelines are practiced across the United States, one of the
largest developers of unconventional hydrocarbons. Though these are recommended, any
in-country regulations will supersede those discussed above.
10.15.3 References
1. Hydraulic Fracturing Primer-Unlocking American’s Natural Resources, American Petroleum
Institute, July 2014
2. http://www.law.du.edu/documents/faculty-highlights/Intersol-2012-HydroFracking.pdf
The following examples of contract extension policies have been summarized from various PSCs
around the world:
Oman – Contractor has the right to request a 5-yr extension to the production agreement
subject to mutual agreement between contractor and government regarding the terms and
conditions of such renewal.
Indonesia – PSCs under the 2001 Oil and Gas Law are valid for 30 years, at which point
the Contractor can request a maximum of 20-yr extension.
Kurdistan, Iraq – Contractor has the right to extend the term of the PSC for 5 years under
same terms and conditions.
Brazil – Concessionaire may request an extension via written request and submission of a
Development Plan or a Production Program if additional investments in the Field are not
requested by ANP. Duration of extension appears to be dictated by ANP (the National
Petroleum Agency) if extension is accepted. During the extension of the Production Phase,
the Parties will be bound under the terms and conditions of the original contract with the
exclusive exemption of any amendments agreed to by both Parties prior to granting of
extension.
India (NELP-VIII) - Extension by mutual agreement between Parties for (5) years or such
period agreed upon after taking into account balance recoverable reserves and balance
economic life; extension of (10) years or such period agreed upon in the event of Non-
Associated Natural Gas. Consistent terms and conditions.
United States operates under a concessionary system as opposed to a PSC system, deriving their
share of the revenues through taxes and royalties. Realizing the importance of production from
marginal wells in mature fields, the government formed policies around incentivizing continued
production from these fields in low oil or gas price environments. Tax credits and expedited
recovery of project costs have helped maintain economic production from mature fields, extending
the time till abandonment and increasing ultimate recoveries of hydrocarbons.
Benefits to the United States from enabling economic production from these fields are not only a
reduction in imported oil and gas, but provisions of jobs and economic activity for local
communities as well as additional tax dollars. By incentivizing continued development of these
mature fields, premature abandonment of large quantities of oil and gas volumes is avoided.
The main incentives provided by the United States towards development of mature oil and gas
fields are summarized below.
Section 43 of the Internal Revenue Code provides an enhanced oil recovery credit equal to 15
percent of the qualified enhanced oil recovery costs incurred in a tax year. The EOR credit phases
out as the reference price of oil exceeds an annually adjusted threshold. For the 2008 tax year, the
threshold price was $41.06 and the reference price was $66.52 based on 2007. Consequently, the
EOR tax credit was phased out completely.
Marginal oil wells are those with average production of not more than 15 barrels per day, those
producing heavy oil, or those wells producing not less than 95 percent water with average
production of not more than 25 barrels per day of oil. Marginal gas wells are those producing not
more than 90 Mcf a day. The provision allows a $3 a barrel tax credit for the first 3 barrels of daily
production from an existing marginal oil well and a $0.50 per Mcf tax credit for the first 18 Mcf of
daily natural gas production from a marginal well. The tax credit phases in and out in equal
increments as prices for oil and natural gas fall and rise. Prices triggering the tax credit are based
on the annual average wellhead price for all domestic crude oil and the annual average wellhead
price per 1,000 cubic feet for all domestic natural gas. The credit for a taxable year is based on the
average price from the previous year. The phase in/out prices are as follows:
OIL – phase in/out between $15 and $18
GAS – phase in/out between $1.67 and $2.00
For producers without taxable income for the current tax year, the amendment provides a 5-year
carryback provision allowing producers to claim the credit on taxes paid in those years.
In 2009, eighty-five percent of all American oil wells were marginal wells, and they provided ~20
percent of American oil production. Similarly, seventy-four percent of all American natural gas
wells were marginal wells, providing ~12 percent of American natural gas production.
The expensing of intangible drilling costs (IDCs) has been part of the federal tax code since 1913.
Intangible drilling costs generally include cost items that have no salvage value, but are necessary
for the drilling of exploratory or development wells. Intangible drilling costs cover a wide range of
activities and physical supplies, including ground clearing, draining, surveying, wages, repairs,
supplies, drilling mud, chemicals, and cement required to commence drilling, or to prepare for
development of a well. IDCs can be either expensed in the year incurred or amortized over a 5-year
period. The purpose of allowing current-year expensing of these costs is to attract capital to what
has historically been a highly risky investment. Current expensing allows for a quicker return of
invested funds through reduced tax payments.
Tertiary injection expenses, including the injectant cost, can be fully deducted in the current tax
year. Supporters of the favorable current treatment of these expenses point to the importance of
tertiary recovery methods in maintaining the output of older wells, as well as the environmental
advantages of injecting carbon dioxide, a primary tertiary injectant, into wells.
In the case of mature fields where operating costs are becoming prohibitive to continued
development, many countries allow a discussion between contractor and government
regarding extension of the PSC under proposed amendments to terms and conditions so as
to incentivize continued economic development of the field to extract maximum oil and gas
from the area, to the benefit of both the contractor and government. Delaying field
abandonment results in additional government revenues, lower reliance on foreign oil and
gas (for importing countries such as India and USA), preservation of local jobs, as well as
benefits to local communities.
It is recommended to allow extension of the PSC for a period of 5 years or more (up to
maximum 20 years) subject to Government approval. Government approval may be based
on criteria such as prudent field operations, adherence to PSC guidelines, etc.
In the case of mature fields where operating costs are becoming prohibitive to continued
development, it is recommended to allow for a discussion between Contractor and
Government regarding extension of the PSC under proposed amendments to terms and
conditions so as to incentivize continued economic development of the field to extract
maximum oil and gas from the area.
The Contractor should request such extensions/revisions to the PSC in a manner that
provides sufficient time for the Government to evaluate such request. The time required by
the Government to evaluate such request should be clearly stated.
10.16.3 References
1. Independent Petroleum Association of America. 2009. Enhanced Oil Recovery
http://www.api.org/~/media/files/policy/taxes/2009-03-enhancedoilrecovery.pdf
2. Independent Petroleum Association of America. 2009. Marginal Well Tax Credit
http://www.api.org/oil-and-natural-gas-overview/industry-economics/tax-
issues/~/~/media/Files/Policy/Taxes/2009-04-MarginalWellTaxCreditFactSheet.ashx
3. Pirog, Robert. 2012. Oil and Natural Gas Industry Tax Issues in the FY2013 Budget Proposal.
Congressional Research Service, March 2, 2012.
http://budget.house.gov/uploadedfiles/crsr42374.pdf
o Each party (Government and Contractor) shall have the right to invite a reasonable
number of observers as deemed necessary to attend the meetings of the Management
Committee in a non-voting capacity.
o Each party (Government and Contractor) shall have the right to bring in expert
advisors to any meeting to assist in the discussions of technical and other matters
requiring an expert advice.
o The Minister shall be entitled to attend the Management Committee meetings as an
observer in a non-voting capacity.
o With regards to Article 6.5 in the Indian PSC, it can be stressed that the unanimous
approval of the Management Committee shall be required.
o According to Article 6.13 in the Indian PSC, "In case, unanimity is not achieved in
decision making process within a reasonable period as may be required under the
circumstances, the decision of the Management Committee shall be approved by the
majority Participating Interest of seventy percent (70%) or more with Government
representative having a positive vote in favor of the decision." With regards to this,
one of the PSCs, have listed that in the event that no agreement is reached at the
second meeting, the Chairman shall have the tie-breaking vote.
o The Management Committee shall approve Contractor’s insurance program and the
programs for training and technology transfer submitted by Contractor and the
accompanying budgets for such schemes and programs.
o Any change in Operator shall be subject to the prior approval of the Management
Committee.
10.17.3 References
1. Model Production Sharing Contract (NELP-VIII), Republic of India, 2009
2. Production Sharing Contract, Kurdistan Region of Iraq
3. Model Production Sharing Contract, Republic of Kenya
4. Model Exploration and Production Sharing Contract, Republic of Cyprus, 2012
5. Model Production Sharing Contract, Timor-Leste
6. Model Production Sharing Contract, Republic of Tanzania, 2013
any act of war (whether declared or undeclared), invasion, armed conflict or act of foreign
enemy, blockade, embargo, revolution, riot, insurrection, civil commotion, or act of
terrorism;
strikes, works-to-rule, go-slows or other labor disputes, unless such strikes, works-to-rule,
go-slows or labor disputes were provoked by the unreasonable action of the management
of the affected Party or were, in the reasonable judgment of the affected Party, capable of
being resolved in a manner not contrary to such Party’s commercial interests.
Force Majeure Events shall expressly not include the following conditions, except and to the extent
that they result directly from force majeure: a delay in the performance of any contractor, including
late delivery of machinery or materials; and normal wear and tear. Nothing in this shall relieve a
Party of the obligations which arose prior to occurrence of a force majeure event.
Responsibilities of the Contractor in this particular event will include the General Notification
Obligations already-in-place. At the same time, the Rights of the Contractor will also be non-
obligations causes in-line with the "Force Majeure" event already-in-place.
o National Parks
o Urban Areas
o Firing Ranges of Police/ Armed forces, etc.
With this regard, a recent "Policy Framework for Relaxations, Extensions and Clarifications
at the Development and Production Stage" issued by the Ministry of Petroleum and Natural
Gas (MoPNG) outlines in detail the Reduction in Minimum Work Program (MWP). These
guidelines list the rights and responsibilities of the Contractor for the above said situations.
If any other reason, that is not listed above, occurs, which restricts the access to the area for
the Contractor and is not of the scale of "Force Majeure" event (to be decided by the
Management Committee) then the Contractor should immediately (e.g. within 3 days)
notify the Management Committee and ask to convene a meeting. A joint meeting of
Contractor and Management Committee shall decide the further responsibilities and rights
of the Contractor in this event, depending on the restriction to access.
It is recommended to follow the guidelines presented in the recent “Policy Framework for
Relaxations, Extensions and Clarifications at the Development and Production State” issued
by the Ministry of Petroleum and Natural Gas.
10.18.3 References
1. Model Production Sharing Contract (NELP-VIII), Government of India, 2009
2. Production Sharing Contract, Kurdistan Region of Iraq
3. Model Production Sharing Contract, Republic of Kenya
4. Model Exploration and Production Sharing Contract, Republic of Cyprus, 2012
5. Model Production Sharing Contract, Timor-Leste
6. Model Production Sharing Contract, Republic of Tanzania, 2013
7. "Policy Framework for Relaxations, Extensions and Clarifications at the Development and
Production Stage under the PSC Regime for Early Monetization of Hydrocarbon
Glossary of Terms
.gslib - Geostatistical Software Library
.las - Log ASCII Standard file format
µgal - Microgal
µms-2 - Micrometer per second squared
1P, 2P, 3P - Highest, Medium and Lowest Certainty
2C - Best Estimate of Contingent Resource
4WD - Four-Wheel Drive
A - Area, sq. feet
A/D - Analog to Digital
AAA - American Arbitration Association
AAPG - American Association of Petroleum Geologists
ACGIH - American Conference of Governmental Industrial Hygienists
ADR - Alternative Dispute Resolution
AER - Alberta Energy Regulator
AFE - Authorization for Expenditures
AGA - American Gas Association
AIME - American Institute of Mining, Metallurgical, and Petroleum Engineers
ANP - Agência Nacional do Petróleo
AOFP - Absolute Open Flow Potential
API - American Petroleum Institute
APSG - Association of Petroleum Surveying and Geomatics
ASTM - American Society for Testing and Materials
AVA - Amplitude versus Angle
AVO - Amplitude versus Offset
BAT - Best Available Technologies
BEC - Bid Evaluation Criteria
BHP - Bottom Hole Pressure
BHT - Bottom Hole Temperature
BLM - Bureau of Land Management
BO - Barrel of Oil
BOP - Blowout Preventer
BPMIGAS - Badan Pelaksana Minyak dan Gas Bumi
BRC - Bid Rejection Criteria
BS&W - Basic Sediment and Water
BTEX - Benzene, Toluene, Ethylbenzene, and Xylene
CAA - Clean Air Act
CAPEX - Capital Expenditure
CAPL - Canadian Association of Petroleum Landmen
CBL - Cement Bond Log
CBM - Coalbed Methane
CCE - Constant Composition Expansion
CCL - Cased Colar Locator
CDP - Common Depth Point
CEC - Cation Exchange Capacity
CGL - Commercial General Liability