A Project Report On: High Pressure-High Temperature (HPHT) Challenges
A Project Report On: High Pressure-High Temperature (HPHT) Challenges
A Project Report On: High Pressure-High Temperature (HPHT) Challenges
A PROJECT REPORT ON
HIGH PRESSURE-HIGH TEMPERATURE (HPHT)
CHALLENGES
IV SEM, B.Tech
In
Petroleum Engineering
SUBMITTED BY:
Shlok Rai Pratik Marandi
Adm No : 2013JE0117 Adm No: 2013JE0198
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Acknowledgement
Apart from the efforts of me, the success of any project depends largely on the
encouragement and guidelines of many others. I take this opportunity to express
my gratitude to the people who have been instrumental in the successful
completion of this project.
I would like to show my greatest appreciation to my guide Prof. A.K PATHAK. I cant
say thank you enough for his tremendous support and help. I feel motivated and
encouraged every time I discussed the project HIGH PRESSURE AND HIGH
TEMPERATURE CHALLENGES IN DRILLING AND PRODUCTION with him. Without his
encouragement and guidance this project would not have materialized.
The guidance and support received from all the friends who contributed and who
are contributing to this project, was vital for the success of the project. I am
grateful for their constant support and help.
ADMN NO.-2013JE0198
3
Acknowledgement
I would also thank to my friends and seniors for their support and help.
SHLOK RAI
ADMN NO: 2013JE0117
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CONTENTS
Introduction
Conclusion
References
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INTRODUCTION
As conventional sources of oil and gas decline, operators are increasingly turning their
attention to unexplored or underdeveloped areas. High temperatures and/or high pressures are
often found in these uncharted territories, presenting complex challenges including casing
buckling, accelerated drilling fluid chemical reactions, rock collapse, kick etc.
Perhaps the best definition has been coined by the UK Department of Energy:
Wells where the undisturbed bottomhole temperature at prospective reservoir depth or total
depth is greater than 300F [150C] and either the maximum anticipated pore pressure of any
porous formation to be drilled exceed a hydrostatic gradient of 0.8 psi/ft or pressure control
equipment with a rated working pressure in excess of 10,000 psi is required.
The main challenge indirectly affect the drilling includes conditions that limit the range of
suitable materials and affect equipment performance. Even if the margins of error are small, the
potential consequences of failure are great. The well control relies on surface equipment being
able to function reliably under extreme conditions. BOP, elastomers and hoses must be rated to
withstand the temperatures and pressure for long enough to evacuate a rig during the worst
scenario. Evaluating HPHT wells requires special logging and testing, with downhole mechanical
and electrical equipment capable of withstanding harsh conditions of elevated temperature and
pressure.
The report discuss about the drilling fluid challenges, properties of drilling fluid (like rheology,
special additives, etc.). The different parameters related to drilling are described which must be
given attention for optimizing the drilling and well construction with overall safety. Different
guidelines and strategies are defined for Kick prevention, kick detection and well control in harsh
HPHT environment with narrow pressure margins. Further, casing and cementing process
desirable in HPHT conditions are described. Properties of cement slurry, its rheology and design
are discussed to provide efficient cementation and safety from high pressure formations. At last
optimizing HPHT drilling is discussed taking in account all above described points which must be
used applied to increase production from high potential HPHT wells.
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Chapter: 1
Special Drilling techniques used for HPHT drilling
Introduction
In deep-well and deepwater drilling, conventional fluids and casing programs result in numerous
fluid density changes to navigate pore-pressure and fracture-gradient windows and multiple
casing strings, which ultimately restrict well depth achievable in the desired hole size.
In depleted producing zones, mud and cuttings invasion impairs achievable well productivity.
The benefit MPD produces is drilling what may otherwise be economically undrillable
prospects so that total recoverable assets can be increased at an economically viable
cost.
The adoption of MPD techniques is usually Drillability driven when there is a need to
mitigate drilling hazards and maximize drilling AFE cost certainty. The intent in applying
MPD is to optimize the drilling process by decreasing nonproductive time (NPT) and
mitigating drilling hazards.
The primary distinction between MPD and the other related techniques of performance
drilling and underbalanced reservoir drilling practiced is that influx of hydrocarbon-
bearing formation fluids is not invited during the MPD drilling process.
Reactive MPD: The technique is effectively on standby as an enhanced form of passive well
control to help manage unexpected downhole pressures.
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Proactive MPD: The technique is used to its maximum effectiveness to mitigate a wide range of
drilling hazards. Proactive MPD radically reduces drilling NPT by enabling fundamental changes
to fluid, casing and openhole programs.
The four primary variants of proactive MPD enable deeper openhole sections; reduce the
number of casing strings, NPT and mud-density changes needed to reach total depth objectives;
and enhance well control.
Dual gradient-variant MPD enabled us to drill total well depth in the right hole size in
deep-well and deepwater wells.
In dual-gradient MPD, the wellbore is drilled with two different annulus fluid gradients in place.
How this is accomplished depends on the operating environment. Techniques to achieve a dual
gradient include injecting a lower-density fluid through a parasite casing string in a land well or
through the marine riser when operating subsea, or actively pumping fluid returns from the
seafloor through lines external to a seawater-filled riser. In all cases the objective is to allow
adjustment of the bottomhole pressure (BHP) to within a predetermined range without changing
the base weight of the drilling mud.
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On land wells and Jackup or platform rigs with a surface blowout preventer (BOP), dual
gradient MPD is most often accomplished by injecting, through a parasite string, an inert
gas or light liquid to some predetermined depth in the casing.
On a deepwater rig with a subsea or surface BOP, the rig's existing booster pump line may
be used as a conduit to gasify returns and reduce hydrostatic head resulting from the mud
and cuttings in the riser.
Internal-riser Rotating Control Device (RCD): It is latched into a housing spool of the riser,
serves as an annulus barrier. Mud and cuttings are diverted to the riser chokeline or to a
dedicated additional returns line and back to the rig. A parasite string injects nitrogen to
gas-lift returns in this line.
Much of the potential of dual-gradient MPD can be delivered with relatively minor rig-
system modifications. For example, limited dual-gradient MPD can be practiced using a
nitrogen production unit, an RCD and a semi-submersible rig's existing booster pump line.
Dual-gradient techniques are most often associated with the challenges of drilling in
deep water from floating rigs; however, these techniques are applicable in other
operating environments, specifically when drilling deep wells in shallow water or on land.
Dual-gradient MPD can be applied in concert with other MPD techniques. Pressurized
mudcap drilling (PMCD) and constant bottomhole pressure (CBHP) are the MPD variants
most likely to be applicable.
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Chapter 2:
HPHT Cementing
Special considerations for cementing of HPHT wells:
Cementing of a liner in deep HPHT wells should be carried out so as to achieve a good
mixing of additives and achieve uniform rheological properties of the cement mix. This
can be achieved by using separate mixing tanks or corresponding methods.
Consider using two cement systems with different setting times.
Optimize cement properties with regards to- Fluid loss, hydration, rheology, setting
times, temperature, Short term & long term strength, gas density, free water.
In particular the risk of migration should be given particular attention.
Displacement of drilling mud with cement requires consideration to be attended to the
following:
Optimum stand-off (centralization) between well diameter and the casing.
Improved procedures for pumping of drilling mud prior to cementing (mud gel
removal!)
Use of compatible fluids, spacers and cement slurries and those they are properly
tested.
Optimization displacement velocities, the use of centralizers.
Rotation and reciprocation of casing & liners.
Preparation of procedures / technologies for squeeze cementing of loss zones shall be
emphasized.
Small changes in testing temperature can make substantial changes to the slurry properties,
thickening time in particular. E.g. increased temperature escalates the hydration of the cement,
and therefore decreases the thickening time. Other factors such as rheology, fluid loss, stability
and compressive strength also vary greatly with temperature.
It is important therefore to obtain the most accurate temperature data from the well. This data
will normally be in the form of maximum logged temperature at a maximum log depth. Details of
the circulation and static periods should be provided with the temperature data so that analyses
can be performed to estimate the BHST from which the BHCT will be derived.
BHST prediction
Is the natural temperature of the formation under static conditions. It is most commonly
estimated from wire-line logs. It is however vital to know how it is measured.
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If the well has been static for 36hrs or more, the temperature is considered static.
The temperature can also be logged at different time intervals after different circulation times
and by extrapolation techniques calculated back to static BHST.
BHCT prediction
The BHCT is a qualified guess of temperature or can be determined approximately by API tables.
The API tables are based solely on well depth and temperature gradient.
Experience show that the HPHT wells are cooled down very rapidly with circulation, much more
compared to conventional wells i.e. the difference between BHST and BHCT is big i.e. up to 30
degrees C.
In general the design temperature has been estimated too high. With new improved API
methods for deep wells, the maximum overestimation has been reduced to approx. 20 degrees
C.
Underestimating may lead to flash cement and costly remedial work. Overestimating the
temperature and testing of cement slurry at a too high circulating temperature may be
detrimental to the result of the cement job. E.g. Over-retarded, too low compressive strength,
poor rheology resulting in soft casing shoes, poor zonal isolation, and costly remedial job.
If modeled correctly, over estimation of BHCT can be further reduced to provide the following
benefits
Minimized waiting on cement
Increased job safety
Allows design to follow well conditions
Optimizes circulating times and rates
Eliminates risk of premature setting
Aids in retarder selection
Retarder sensitivity
Sensitivity checks must therefore be carried out on the cement slurry to determine whether the
proposed cement slurry is acceptable. The selection of correct retarder is very important to
avoid over-retardation.
The best recommendation is to run thickening time and compressive strength tests both at TD
and at TOC (in case of very high TOC) with the actual temperature, pressure and heat-up and
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cool-down times. Some cementing service companies have software that can generate these
data.
Cement Sensitivity
Batch control and the properties of the cement itself are very dependent on quality of slurry
achieved. The cement can vary over time, in storage, transportation, with humidity etc. It is
important therefore, that in laboratory tests, the same cement as being used offshore is tested.
All cements respond differently with additives. At high temperature these differences become
more pronounced and some cement is better than other. It is also not uncommon for one batch
or mill-run of a manufactures cement to behave quite differently from a separate batch or mill-
run of the same manufacture.
Poor cement for use at high temperature may be characterized by one or more of the following
Failure to obtain sufficient thickening time with common high temperature retarders
Significant viscosity increases or humps in the consistency well before the end of the
pumping time.
Extreme sensitivity of common retarders such that the sensitivity checks cannot be
achieved.
If these problems cannot be overcome with cementing additives, then an alternative batch, mill-
run or manufacture of cement should be sought. Because of variations from one batch to
another, the quantity of cement destined for the HPHT job must be identified and isolated.
Composition of Slurry
Some slurry designs sometimes tend to be very complicated with up to 8 or 9 additives, both
liquid and dry. This is of course undesired because there will be an uncertainty in the amounts
added for each, which in turn adds up and may affect the properties significantly. A practical
solution to better control the amounts added is to premix the additives with very accurate
proportioning.
If the premix is prepared in the mud tanks there is always a danger for contamination. Be aware
that mix-water that is prepared a long time before the cement job (e.g. 6 hours) can experience
ageing effects. Slurry mixed with an aged mix-water can have different properties from those
designed. It is recommended either to mix the mix-water just before it is required for the cement
job or to check the ageing sensitivity of the mix-water in the laboratory.
The high temperature and high cement density does not necessitate highly complicated slurries.
The minimum required additives are as follows:
Cement (most likely API class G or H)
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Weighting agents should not be required for cement slurries that are less than 2.05 SG.
If silica sand is used it should be added separately to the batch mixer and not pre-
blended since it can settle out of the bulk cement. However, Silica flour may be pre-
blended with cement without problems.
In wells with temperature above 110 degrees Centigrade, Silica addition should be
considered for the whole casing length, also at shallow depth. This is because if the
cement column is exposed to the well temperature, the integrity of the cement must be
remains intact. Silica prevents strength retrogression from occurring.
A very fine Manganese Oxide has successfully been used as weighting agent both in
cement slurries and cement spacers. The fine Manganese Oxide can be slurrified, and
therefore the slurry density can easily be adjusted after the cement blend has arrived on
the rig. The fine Manganese Oxide improves the stability of the cement slurry and spacer.
Particle size distribution of material must be compatible with cement. (Larger particles
will settle out of the slurry, smaller particles tend to increase slurry viscosity.)
Water requirement must be low.
Material must be inert with respect to cement hydration, and compatible with other
cement additives.
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Any volume change within the cement will increase the chance of a pore pressure reduction in
the cement. This may lead to gas intrusion from the formation. If the cement has a poor fluid
loss the chance of bridging off across a permeable zone increases. A bridge will prevent full
hydrostatic pressure from being exerted on the formation, can lead to gas intrusion.
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Density
Density variance of the slurry mixed and pumped down hole is very critical in HPHT wells. Very
often the density is the same as the mud weight and is therefore important for keeping well
control. Slurry pumped downhole should be monitored and recorded continuously. Spot checks
with pressurized mud balance should be taken at certain intervals. Density variations will also
affect the retardation of the slurry.
The cements used for HPHT wells must be high sulphate resistant, due to the chance of H2S. The
requirement for good isolation of the casing from possible sour environments is especially
important in these wells. Corrosion inhibitors are widely used to prevent such problems.
Displacement Issues
The low density difference between mud spacer and cement and the low displacement rates
that are required to prevent losses will reduce the displacement efficiency significantly.
The spacer should be more viscous and dense than the mud it displaces. The cement should be
more viscous and dense than the spacer it displaces.
Ensure that stand-off is the best possible: This is likely to be the only variable that can be
used to maximum advantage under these conditions. In vertical hole, one centralizer per
alternate joint is recommended from the shoe joint and across the sections where zonal
isolation is required.
Maximize the (small) density difference between mud, spacer and cement: At high
densities, cements and spacers cannot be designed to be pumped in turbulent flow at
low displacement rates without being unstable and settling out of solids. The
displacement will have to be a laminar flow displacement.
Design the spacer and cement rheology such that the apparent viscosity, at the annular
shear rate, are in the order mud<spacer<cement with the difference between successive
fluids being at least 20%.
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Ensure that the hole is properly cleaned of cuttings then reduce mud gels to the lowest
acceptable value prior to pulling the drillstring for the final time before running
casing/liner.
Circulate mud for at least 4 times the open hole annular volume prior to starting the
cement operation. Check that 4 open hole annular volumes is sufficient to cool the hole
to the BHCT used by the laboratory to design the slurry formulation. If possible, rotate
the liner while circulating.
Once the liner has been landed. Try to maintain circulation continuously until the cement
has been displaced. Minimize the length of any shut-down.
Mixing Issues:
The mixing of the cement slurry can be improved by using s batch mixer, premixed water, large
averaging tanks when mixing direct, better density control etc. Mixing equipment also varies
from rig to rig and must be evaluated before executing a HPHT cement job.
Furthermore, experience has shown that retardation of HPHT slurries may be significantly
influenced by the mixing energy put into the slurry while mixing.
If the slurry is planned to be batch mixed, then this should be simulated in the laboratory to
reveal impact on thickening time and other properties on the cement slurry. The cement slurry
should be batch mixed to guarantee correct cement density is pumped downhole.
Normal API mixing and thickening time testing procedures do not simulate the time that the
slurry spends on surface while being mixed in the batch mixer. Time spent in a batch mixer can
reduce the downhole thickening time and can result in viscosity increases that may render the
cement non-mixable in the field. These effects may not be seen if the slurry is simply mixed and
tested for thickening time using just the API procedure.
To simulate batch mixing, the following mixing and thickening time test is recommended:
Mix additives into a Waring blender in the order to be added in the field. Add the entire
cement/silica/weighting agent at 4000 rpm as fast as possible but preventing dry cement
building up at the top of the blender. Shear at 12000 rpm, or the maximum attainable speed if
less than this, for 35 sec. Pour the slurry into consistometer cup and stir on consistometer
without applying pressure or temperature for 90 minutes. Observe consistency. Apply pressure
and temperature and proceed with the thickening time tester retarder.
Any undesirable viscosity increases should be seen during the 90 minutes ambient stirring. The
downhole thickening time is the time from application of temperature and pressure to the 70 Bc
point.
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Simulations based on these parameters provide the several combinations of pump rates, Fluid
densities and rheology.
Designing:
Slurry design generally consists of formulating cement additives to give the desired density, fluid-
loss control, rheology while pumping, the appropriate setting time and adequate strength when
set. Slurry properties must ensure solids stay in suspension, just as barite must be suspended in
mud. Failure to do so can result in loss of well control and channeling on the high side of
deviated holes. As cement particles settle to the low side, a continuous water channel may form
on the upper side of the hole, creating a path for gas migration.8 Cement slurry design involves
special considerations in HPHT wells. Neat cement (without additives) is susceptible to loss of
strength and increasing permeability due to shrinkage at temperatures above 230F [110C]. To
prevent this, part of the cement, typically 25%, is routinely replaced by silica flour (grain size 40
to 50 _m).9 Slurry density of up to 17.5 ppg [2.1 g/cm3] can be achieved by adjusting solids
content. Slurry having density greater than this are frequently needed in HPHT wells and can be
achieved by adding hematite to the slurry design. Avoiding unpredictable slurry performance is
the highest priority in cementing HPHTwells.
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Chapter 3:
HPHT Completion Challenges
Introduction
The new higher temperature and pressure (HPHT) horizons being drilled today requires an
industry-wide technology and development effort in order to deliver a reliable completion.
Recent HPHT history indicates that infantile failures happen, usually caused by something that no
one considered an issue. History has shown that infantile failures (well failures in the first few
months of production) are more likely with new equipment designs and service conditions.
Description:
Yellow sure it can be done, but either have not done yet or very limited
experience.
Estimated time in years for design, testing and manufacturing.
Table summarizes the gaps and expected lead times to develop equipment for HPHT wells
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Packers
Packers have been designed and tested for 15 ksi applications, but sizes are limited. Only one
packer has been designed for 20-ksi service.
Limited sizes currently are available.
o 20 ksi 7 in., 55.3#.
Packers should be run with completion tubing and set either hydraulically or
hydrostatically.
o Allows for a metal-to-metal back off sub or metal-to metal threaded connection
to packer.
What pressure rating is required? Should it be equal to the bottom hole pressure or
expected differential across packer plus a safety factor to account for kill operations,
acidizing etc.
Test facilities are limited to 4600F and 20 ksi. Significant investment required for higher
temperatures and pressures.
Limited setting range on HPHT packers.
o May require honed or extremely tight casing tolerances to get differential rating.
Casing stress caused by packer and tubing could be critical if casing is unsupportive.
Milling of CRA packers is extremely difficult. Loss of well a possibility.
What are the temperature limits of Inconel 718/725?
o At high temperatures Inconel 718/725 becomes susceptible to corrosion and
environmental cracking when exposed to certain agents. Aging may be an issue.
o Testing needs to include exposure to heavy weight brines or cesium formates.
Tieback casing design and sour service material qualification is the critical path issue for ultra
HPHT completions. Issues include:
Qualification of high strength carbon steels for the expected pressures, temperatures,
and environment.
Connection design and testing.
Nickel based CRAs may be a solution, but have never been made in the sizes required.
Tieback weight may be beyond capacity of most rigs. Tieback may have to be run in
sections.
What casing test pressure is required on initial completion SITP? Requires BOPs rated to
SITP or test the casing with the tree installed.
SCSSVs
Again, limited work has been done on SCSSVs, but not at the ultra HPHT conditions above 20 ksi.
Limited sizes currently available with pressure rating greater than 15 ksi.
o 4.5 in., 20 ksi OD 7.13 in., ID 3.437 in.
o 3.5 in., 20 ksi OD 5.49 in., ID 2.313 in.
o 3.5 in., 16.7 ksi - OD 5.65 in, ID 2.87 in.
With API 14A requirement of a test pressure of 1.5 times the working pressure, maximum
pressure rating is 20 ksi and 4000F due to verification test limits at Southwest Research.
Is more than one SCSSV needed?
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HPHT wellheads, 20 ksi and some 30 ksi, have been built. Most of the 30-ksi equipment was for
land wells. These wells were mostly low rate, < 20 MMCFPD. The conditions and expected high
rates of ultra HPHT wells will create new issues.
20 ksi, 3500F clad trees and wellheads are available 6months to 1-year lead-time
required.
New design or qualification testing required if >3500Fand 20 ksi for:
o Tubing spools
o Back pressure valve prep
o Stem packing
o Gate valves and seats
o Chokes
What is the long term reliability of gates, seats and hard surfacing?
A positive and adjustable choke in series will be required to handle pressure drops.
Perforating
Three options exist for perforating. TCP guns can be installed below the permanent production
packer, and then detonated after the tree is installed. The well can be perforated through tubing
either with multiple wireline runs, or guns can be hung off and fired hydraulically.
TCP
Gun systems, carriers and firing heads currently rated to ~24 ksi and 4500 F.
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HNS guns systems good for only 107 hrs at this temperature.
Development of a contingency plan to perforate if TCP guns dont work is required.
o Can guns be dropped off?
o Difficult to mill up CRA packers and unlikely to be able to cut tubing to drop guns.
If we drop the tubing string or if guns fall off while running in hole, will guns fire? Since it
is likely completion fluid will not be kill weight the risk is very high, even though the
probability occurrence is low.
Limited availability of 20-ksi lubricators. Six month lead time for new 20-ksi equipment, however,
vendor safety standards typically limit use to 80% of rated working pressure.
Well Control
Well control in the event of an infantile failure is a major gap HPHT completion technology.
Limited 20 ksi BOPs stacks and choke manifolds. Stacks have not been used in years and
may need reconditioning. It will require two years for new BOP stacks. No equipment
available for pressures > 20 ksi. Is it prudent to complete a well without having a BOP
stack available hat can handle maximum SITP?
Can the shear rams shear the heavy wall, high strength tubulars that will be run?
Well kill - Currently limited availability of 20 ksi equipment and none available for
pressures > 20 ksi. Pumps, piping, chick sans, or coflexit would have to be developed, 1-2
years delivery. Is it prudent to complete a well without having equipment rated to the
maximum SITP available in industry for an emergency kill?
Height and weight of BOPs, wellheads, choke manifolds etc. will be larger then what is
currently used and may require special handling equipment.
Kill weight completion fluids.
o Can heavy weight brines be inhibited at these high temperatures? Corrosion
inhibitors for ZnBr tend to degrade to H2S and zinc sulfide scales. Needs to be
tested with CRAs, elastomers, high strength work strings etc.
o Oil base mud will work, but there are issues.
OBM can destabilize and the weighting agent drop out over time plugging
the tubing, complicating future work over. Clean out of the weighting
agent with coiled tubing difficult due to low pump rates.
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Remedial Operations
Remedial operations are not normally planned as part of an initial completion. However, for ultra
HPHT wells contingency planning will be required.
Workstrings
o Heavy wall tiebacks and liners will limit workstring sizes and torque ratings. May
not be able to washover.
o S-135 workstrings can be used in inhibited mud or completion brines before
perforating (i.e. no H2S),but can heavy weight completion brines be inhibited
sufficiently for use of S-135 for remedial operations?
o Premium connections such as XTM40 or PH6 will be required. These connections
are very susceptible topitting on MTM seal face in heavy weight brines.
o Workstrings that are sour gas compatible are in limited supply and may not have
sufficient strength. Long lead time required for new strings.
Sand Control
Mud engineering- Consideration must be given to maintaining the drilling fluid in good condition
through efficient solids control, minimization of dilution requirements and the reduction of fluid
retention by cuttings. Although many criteria must be considered when designing HPHT drilling
fluid, often one desirable property will be achieved only at the expense of another. Dowell has
developed a method to optimize formulation properties until all criteria can be met the
satisfaction of the mud engineer.
Fluid behavior
1) Low conditioning requirements
2) Low ECD and risk of fracture
3) High rate of penetration
4) Differential sticking minimized
5) Sagging minimized
6) Good hole cleaning
7) Maximum kick prevention
8) Good hole stability: Washouts minimized
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Dowell mud design flow chart. Dowell has developed a standard procedure to optimize mud rheology and
hydraulics. Starting with hole cleaning performance, a range of properties of the proposed mud are checked by
modeling. Parameter changes are made as required until the properties and performance of the proposed mud
system meet specifications.
Weighting uponce the base fluid has been selected, PVT data provide the basis for local
density modeling. The static pressure will already have been computed so as to exceed
formation pore pressure by a minimum safety margin at all depths. Although this seems
straightforward, variations in mud density due to temperature and pressure must be considered
in determining the static pressure. Further complications may be encountered offshore where
the minimum static pressure is required to overcome pore pressure when the marine riser is
disconnected. The riser margin is a safety margin needed when moving off a well in an
emergency, and increases the minimum dynamic pressures used while drillingespecially in
deep water where the additional pressure with the riser connected is high.
Weighting material is chosen to achieve the required mud weight based on offset well pressures
and factors such as sag and gelling behavior of the mud. Barite, milled to achieve desired particle
size (typically less than 75 m), is a common weighting agent.
High-quality barite is essential for HPHT mud because impurities or poor particle size distribution
may result in problems that are magnified in the HPHT environment. The presence of clay
impurities in barite can result in gelation at 275F [135C] as the clays burn out. Carbonate and
iron minerals also cause changes in the mud as their solubility with changing mud temperature
causes flocculation. Other chemical residues lead to severe foaming problems at high
temperature. Sagging problems can be reduced by specifying ultrafine particle size (less than 15
m).
In high-density mud systems, barite can account for up to 78% by mass and up to 45% by
volume. When high mud weights are required, the solids ratio may reach a point where the mud
becomes susceptible to gelling in the event of fluid loss. The solids ratio can be reduced by using
high-density weighting agents such as hematite. In any case, the mud engineer routinely
measures solids content and fluid loss during mud checks to ensure they do not exceed design
parameters during drilling.
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BARITE SAMPLE A B C D E
Specific Gravity 4.25 4.23 4.27 4.22 4.30
PV, cp 31 34 34 38 34
YP, lbf/100ft 16 4 20 0 0
API fluid loss, ml 11.5 6.0 14.0 11.5 2.5
Suspension properties VG P VG G G
Surface area m/g 1.3 1.1 4.1 1.7 0.4
Effects of barite quality. Susceptibility to sagging in a drilling fluid is greatly affected by the particle size of the
weighting material. The smaller the particle size, the slower the speed with which it falls through a static fluid, and
static sag is less likely to occur. The effects of barite quality are summarized in the table, which shows the plastic
viscosity (PV), yield point (YP), API fluid loss and qualitative particle suspension of a water-base bentonite mud
recipe made up with five different barite samples. Suspension properties have been rated as follows: VG = very
good, G = good, P = poor. The barite particle size is reflected by the surface area (m/g). The smaller the particles,
the greater their surface area per gram, so the finer barite has a larger surface area.
Problematic gelsGels and high-viscosity fluids have considerable effects on the mud pressure
acting on the formation when tripping in or out of the hole. They are controlled by varying the
appropriate mud additives to prevent excessive gelation while ensuring that weighting agents
stay in suspension. If the gel strength and viscosity can be determined at downhole conditions,
their effects on dynamic pressure can be simulated. When influx cannot be prevented by
restricting tripping speed and acceleration, special procedures are needed to permit operations
to continue. The simplest procedure is to increase the mud weight before pulling out, but other
techniques are possible.
If the predicted swab pressure is greater than the trip margin, the pumps can be operated while
tripping out. The additional dynamic pressure resulting from maintaining circulation can be made
sufficient to achieve the desired margin above pore pressure. Alternatively, a heavy-weight slug
can be spotted to minimize the risk of a kick. With careful design of both the volume and weight
of the slug, a hydrostatic pressure profile is achieved that avoids fracturing the formation while
maintaining the desired overbalance for tripping.
Excessive swabbing is not the only problem associated with high gel strength. The pressure
increment needed to break (initiate) circulation in the presence of gels can be much higher
than circulating pressures. In the worst case, the formation fracture pressure can be reached
before the gel is broken. Gel strength needs to be sufficient to support the heavy particles in the
mud but no more, otherwise excessive pressures may be needed to break the gel. The pressures
needed to break circulation can be modelled at the design stage, and the implications of these
additional dynamic pressures accounted for in the design.
Excessive gel strength can result in a further hazardtrapped pressure. An influx of formation
fluid below a gel will not be observed as a flow at surface until the gel is broken, by which time a
large influx may have occurred, resulting in a rapidly deteriorating well-control situation. The
problem is magnified by the ability of gas influx to cause gelling in water-base muds under
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certain conditions. If the gas contains carbon dioxide [CO2], the pH is reduced, causing
dispersants to become less effective, and the carbonate and bicarbonate ions in the mud to
continue promoting gelation. Freshwater gel muds with high solids contents are particularly
susceptible to this effect. To minimize trapped pressure, the gel content must be kept as low as
practically possible.
Gel support of pressure differentials. Absence of movement within a drilling fluid can result in the formation of gels,
which act as weak elastic solids. When breaking circulation, some of the pressure beneath the gel will be taken by
the pipe or borehole walls. This pressure could be high depending on the gel strength and can result in formation
fracture. In the case of an influx of formation fluid beneath a gel, the influx cannot be detected unless the
differential pressure is high enough to break the gel. A significant well-control hazard exists when the gel is
eventually broken down during circulation, resulting in a kick being taken.
Controlling mud densityfrequent checks of mud density are essential to maintaining downhole
pressures within the mud pressure operating window. Recently a technique has been developed
to correct surface measurements of mud density for temperature effects and has been used by
Shell UK and Dowell in drilling Heron and Shearwater HPHT wells in the UK sector of the North
Sea. The drilling program for these wells specified that the overbalance should be limited to 200
psi [1.4 MPa]. Based on the conventional procedure for measuring the mud weight, the error in
mud-pressure gradient resulting from a temperature that was 5F to 15F [3C to 8C] different
from the assumed temperature was estimated at 1.5 pptf (psi per thousand ft) to 4.5 pptf
[0.0035 SG to 0.0104 SG]. With true vertical depths (TVD) in excess of 15,000 feet, the errors in
downhole pressure were estimated at up to 67 psi [460 kPa], far greater than what was
acceptable with such a small planned overpressure. By modifying the procedure for taking the
mud sample temperature during measurement of the mud weight, such errors have been largely
eliminated.
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Pump ratesMinimum pump rates to clean the well are usually low due to the buoyancy of
cuttings in high-density drilling fluids. Therefore, in vertical boreholes, hole cleaning is not
usually a big concern in HPHT wells, and pump rates in HPHT wells are more likely to be decided
by other factors. Although low pump rates help maintain low ECD, the well program may call for
higher rates to reduce bottom-up time and permit timely analysis of drilled cuttings lithology,
background or connection gas, and mud solids. It is good practice to design for pump pressures
below rig capacity to enable dynamic kill, the intentional increase of dynamic pressure by
increasing annular flow rates, to be used when attempting to control the well.
Controlling sagIf hole cleaning is not a concern, the mud engineer can focus on assessing the
possibility and effects of sagging. Modeling sagging behavior is difficult, and is usually empirically
assessed in lab experiments and minimized as far as possible.
At the wellsite, the amount of sag occurring in a mud can be quantified from the heaviest and
the lightest components of the circulating mud. After assessment of the amount of sag of the
circulating mud, appropriate procedures are used to minimize it. In particular, if changes in mud
weight indicate density segregation is occurring, laminar shear at low pump rates (which
promotes sag) should be avoided. Similarly, circulation at low pump rates prior to cementing
should be minimized.
Once sag behavior is defined, the hydraulic properties of the mud formulation can be considered
in the design process. The goal of the mud engineer is to design a mud that will continue to
function between pore pressure and fracture pressure at all times. These pressure limits define
the critical mud pressure operating window and must include margins to account for dynamic
pressure resulting from swab and surge when tripping.
Conclusion
Well construction strives to balance many conflicting requirements. Drilling performance must
not compromise well control, and cementing pressure must not jeopardize formation integrity.
In HPHT wells, the margins between these conflicting constraints are narrow and careful analysis
is required to plan for success. Implementation of the HPHT well construction program requires
skilled personnel, guided by established procedures, with accurate information on surface
parameters. Software models and downhole measurements help complete the picture by
predicting downhole fluid behavior with enough accuracy to permit safe drilling. With all these
factors in place, increasingly challenging HPHT wells will continue to be successfully and safely
constructed in the future.
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References
weatherford.com, Dual Gradient drilling
HPHT Cementing Coursework, Peter Aird., Kingdom Drilling Services Ltd.
SPE 97589, HPHT Completion Challenges, Ron Zenrigue, SPE, Shell
Exploration & Production Co.
HIGH-PRESSURE,HIGH-TEMPERATURE WELL CONSTRUCTION, Keelan
Adamson, Georga Birch, Erhu Gao, Steve Hand, Colin Macdonald, David
Mack, Anver Quadri, Aberdeen, Scotland, UK
IADC/SPE 151413; RHEOLOGICAL PROPERTIES OF INVERT EMULSION
DRILLING FLUID UNDER EXTREME HPHT CONDITIONS, John Lee, M-I
SWACO; Arash Shadravan, Texas A&M University; Steve Young, M-I
SWACO; 2012
IADC/SPE 103731; HP/HT DRILLING FLUIDS CHALLENGES, Ron Bland,
SPE, Greg Mullen, SPE, Yohnny Gonzalez, SPE, Floyd Harvey, SPE, and
Marvin Pless, SPE, Baker Huges Drilling Fluids, 2006
HPHT DRILLING FLUIDS, edited: Peter air, Ref:HTHP03
DRILLING AND TESTING HOT, HIGH-PRESSURE WELLS, Robert
MacAndrew, Ranger Oil(UK) Ltd Aberdeen, Scotland; Nigel Parry,
Phillips Petroleum Company, United Kingdom Ltd, Aberdeen, Scotland;
Jean-Marie Prieur, Conoco (UK) Ltd, Aberdeen, Scotland; Jan
Wiggelman, Shell UK Exploration and Production, Aberdeen, Scotland;
Eric Diggins, Brunei Shell Petroleum, Brunei; Patrick Guicheney,
Montrouge,France; Doug Carmen, Adrian Stewart, Aberdeen, Scotland;
April/July 1993