Well Testing Handouts
Well Testing Handouts
Well Testing Handouts
Lecture 05
Previous class learnings: You know!
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Constituents of hydrocarbons
Alkane, alkene, alkynes, asphaltene, aromatics, resins, etc.
Types of reservoir fluids
WELL Dry
Wet
gas
gas
COMPLETION Volatile oil
Gas condensate
TESTING AND Black oil
Testing of oil/gas well plays important role in the form of initial stage to
Need for Well Test matured state of any field.
Conditions for Well test The acquired data is widely used in various situations to evaluate different
reservoir characteristics for reservoir engineering calculations or to know the
Types of well: Exploration, Delineation, productivity/deliverability of well.
Development wells The job is assigned to a big group called Reservoir Data Acquisition group.
The job of the group is to do the testing of wells on regular interval of time and
Flow Behavior interpret the testing results.
Well testing provides a description of the reservoir under dynamic conditions,
Types of Flow
which indicates flow pattern within the reservoir.
It uses the pressures and rates under a standard condition for the determination
of parameters which influences the fluid flow through porous media, e.g.,
permeability, fault, fluid contacts, etc. Measuring the variation in pressure versus
Jitendra Sangwai, IITM, 2011 time and interpreting them gives data on the reservoir and well.
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There are few special pressure transient tests, which can be used to Purpose of well testing
determine the areal extent of a reservoir and to estimate the It serves as one of the primary tools for defining the systems
volumes of fluid in place (for ex., in case of delineation well test approach to well completions and work over jobs
analysis). It provides information about dynamic behavior of the
Delineation well: Drilled at a distance from a discovery well to determine reservoir
physical extent, reserves and likely production rate of a new oil or gas field.
Predict short term well productivity: an evaluation of well
In case of composite systems like in-situ combustion, steam flooding deliverability at the present time under various operating
or polymer flooding, these well tests can accurately predict the conditions
swept zone parameters, enabling the engineers to determine the Predict long term well productivity: a description of the
efficacy of the EOR processes. decline curve which may be expected from the well over a
period of several years.
Pressure measurements can also be interpreted to yield quantitative
Static well pressure: it is a measurement of the stage of
estimation of the well condition, so the efficacy of stimulation
depletion of a reservoir
treatments on well productivity can be evaluated.
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Flow Regime Characteristics Three possible cases for well test analysis
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When well is opened to production from shut-in Infinite reservoir : well is in infinite radial extent
conditions, the pressure disturbances created at the Bounded cylindrical reservoir: well is in centre,
well travels outwards thorough the rock at a velocity
governed by the rock and fluid properties. no flow across external boundary
Various flow conditions are defined with respect to Constant pressure outer boundary: constant
behavior of these pressure disturbances pressure along outer boundary
Types of Flow:
Steady state flow
Unsteady state flow
Pseudo-steady state flow
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Next class:
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What we learned till now When well is opened to production from shut-in
Flow equation for single phase fluid flow conditions, the pressure disturbances created at the
Both Cartesian coordinate and radial coordinate well travels outwards thorough the rock at a
velocity governed by the rock and fluid properties.
Various flow conditions are defined with respect to
Flow equation for multiphase fluid flow (and with final forms behavior of these pressure disturbances
for gas, oil and water Martins Eq.)
Types of reservoir analysis (three types: Infinite, bounded
Types of Flow:
cylindrical, const. pressure outer boundary) Steady state flow
Solution of single phase fluid flow equation for Infinite Unsteady state flow
reservoir case..) Pseudo-steady state flow
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Three possible cases for well test analysis Radial flow equation
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Pressure at the wellbore, Pwf, for the cases when re When tDw, is sufficiently large,
>> rw,
The unfamiliarity with Bessel function is not the cause for worry. We will
use some simpler form to calculate the numerical values of Pwf
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The pressure funnel in this case is expected to reach at At t = t1, only small portion of
reservoir experience pressure
no-flow boundary conditions. drop resulting in a flow for
radius, r1.
The no flow boundary condition are may be due to
As the flow rate near the well
sealing faults, or boundaries of drainage area of to be kept constant, the
adjacent wells, etc. pressure curve remains in
parallel and decreasing in
magnitude over the period
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Constant pressure
properties
at outer Reservoir pressure
boundary (steady
state condition)
re
Inflow performance or reservoir Shut-in condition, reservoir pressure Production rates at various drawdown pressures are used to
flow capacity construct the IPR curve, which reflects the ability of the
A mathematical tool used in production Absolute Open Flow Potential, AOF reservoir to deliver fluid to the wellbore.
engineering to assess well performance by
plotting the well production rate against Combining this with a curve reflecting the tubing performance
the flowing bottomhole pressure (BHP). identifies the operating point.
The data required to create the IPR are
obtained by measuring the production
rates under various drawdown pressures.
The reservoir fluid composition and
behavior of the fluid phases under flowing
conditions determine the shape of the
curve.
IPR curve or reservoir flow capacity curve requires relationship between
flow rate coming into well and the sand-face pressure or flowing bottom
hole pressure (FBHP)!!! Jitendra Sangwai, IITM, 2011
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The calculated or measured rate a gas well will IPR Equation: general form C : flow coefficient Empirical constant
produce for a given bottomhole or wellhead pressure. n : exponent
Stabilized flow capacity of any oil/gas field is
required for reservoir management Taking log
Flow capacity must be determined for various FBHP, this
will give indication of change in flow capacity with
average reservoir pressure.
Several test can be carried out for determined oil/gas
deliverability
In multipoint testing, the well is produced at several Once the value of n
different rates (usually four) and from the data determined from plot, C
obtained, an inflow performance is evaluated. can be calculated as;
Once the well has been tested and the inflow Liquid saturation in the gas reservoir:
performance or deliverability equation is As pressure declines due to depletion, the gas expands
established, it is desirable to predict how changes in to keep sg constant, unless retrograde condensation
occurs in which case Sg may change. This effects the
certain parameter affect the IPR curve. permeability of gas, k. for dry gas reservoir, the
The changes due to effect of several parameters change in k with time can be considered negligible.
are due to reservoir depletion, or due to well Formation thickness, h:
workover operations. In most cases this is constant. However this may get
changed if the well is perforated for longer section.
Various factors that affect IPR curve are given
below: Reservoir temperature
T will be constant except for small change near well-
bore
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Oil or Gas viscosity and compressibility factor Transient test or un-steady tests are useful to obtain
These are sensitive to change in reservoir pressure, PR. information on reservoir properties, such as,
permeability, skin factor, an average reservoir pressure,
The drainage radius, re PR, etc.
This depend largely on well spacing. If the test may continued into pseudo-steady state flow
The well bore radius, rw regime, an estimation of reservoir size can be made
This considered to remain constant. The effective wellbore based on the data obtained from such tests.
radius may be changed due to well stimulation, however this Most common transient tests are Drawdown Test and
change can be taken care by skin factor. Pressure Buildup Test. The same information may be
The skin factor, S obtained from the above two tests, however the choice
of particular test is depend on the field conditions.
This value can be changed due to fracturing or acidizing a
well. The well should be re-tested after fracturing to re- These tests involves change in flow rates during the
evaluate IPR curve parameters course of testing time and hence involves well know
principal called as, principal of superposition
During the life time the well will not be produced at This principal states that if
constant flow rate the pressure disturbance is
Some of the pressure analysis techniques, such as crated in the reservoir, the
disturbances continues to
pressure drawdown, or, pressure buildup tests, travel through the reservoir
involves use of pressure date obtained for different even though the source of
t flow rates. disturbance may change or
This principal makes us possible the generation of ceases. This means that in
order to determine the
pressure behavior for several producing rate pressure at a locations as
schedules from the basic constant rate pressure function of time, all of the
solutions. pressure disturbances effects
must be added.
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till t1
or
Pressure drop till t; (ant time after t1)
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If the well is now closed in for time t, then by principal of This extrapolated values for Log
superposition, we can calculate the pressure drop ( more correctly (t+t)/t should ideally be initial
pressure
pressure difference or pressure buildup) as,
Or
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After introducing skin equation into, we find well To calculate the skin factor, it is necessary to
pressure after a production time t measure the well pressure both before and after
closing. By combining following equation:
Gives pressure before closing
Comparing the above equation with:
Gives pressure after closing
it is observed that this flowing pressure Pwf is lower by an To get: (approximating as 1 and taking
amount ~ than the pressure in the absence t as 1 hour)
of a skin.
The skin factor can be calculated as below The radius rs of the skin zone around
equation, where, P1hrs is a pressure is an
extrapolated pressure at 1 hrs (t = 1 hrs) from the well and permeability ks in this
opening the well. This pressure is observed on zone are related to skin factor as,
ideal curve. One can choose other times to define
this pressure, such as, P2 hrs, P10 hrs, (i.e., t = 2 hrs,
t = 10 hrs, etc.) etc., so accordingly constant
(3.23) in the below equation will change.
General practice is to use P1hr as a reference This mean that if the Ks is small than k, the S will be positive, if
pressure to determine skin factor these are equal, s is zero, and if k is small than ks (as in case of
hydraulic fractured reservoir, acidizing well, etc.) s is negative.
It is not possible to obtain both the factor, ks and rs, from above
equation. One has to define a new term called effective well bore
The pressure Pwf is measured pressure before
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The effective well bore radius is defined as the Flow efficiency is defined as the
ratio of actual productivity index
radius which makes the calculated pressure of a well to its productivity index
drop in an ideal reservoir equal to the real if there is no skin. Thus,
reservoir with skin Flow efficiency = Jactual / Jideal
J actual = q / (P* - Pwf)
J ideal = q / (P*-Pwf-Pskin)
Example Solutions
67 68
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Steps:
Calculate the skin factor s
P1 hr is at (tp+t)/t)= (72+1)/1 = 73
Take up one idea. Make that one idea your life - The test consist of flowing the well at a constant rate, qsc, for
think of it, dream of it, live on idea. Let the brain, period of time, t, and then shutting the well in at t = 0; and
measuring the wellbore pressure increase with shut-in time at
muscles, nerves, every part of your body, be full every t.
of that idea, and just leave every other idea This test is developed by Horner and is considered the best
alone. This is the way to success. methods of all others and given by Miller, Dyes and
-- Swami Vivekananda-- Hutchinson, Muskat, etc.
The governing equation is;
The plot of (P)2 vs. Log [(t+ t)/ t] will have slope,
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The plot of Log (P)2 vs. Log [(t+ t)/ t] will have slope,
The plot of Log(P)2 vs. Log [(t+t)/t] The slope of the graph can be obtained as below
The plot of (Pws)2 vs. Log [(t+t)/t] and used to calculate permeability,
Therefore,
PR = 3731 psia
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When to use pressure drawdown test as against to pressure buildup test ? Odeh and Nabor established that if
Ideally drawdown test would start with a uniform pressure in the reservoir so new wells the time, t, for flow period equals,
are good candidate for having drawdown well test method analysis.
Secondly, if the well is closed for sufficient time for workover operation or recompletion
and if the economic condition support closing the well for sufficient time to buildup the Transient flow
pressure in the well, then drawdown test can be carried out on such wells. conditions are
established
Thirdly, if there are uncertainties in the pressure build up test data. In such cases, pressure
buildup test followed by pressure drawdwon test affords pressure data which can be 1
3 2
used for comparative analysis. Semi steady state
Extended drwadown test are also called condition established
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In the late transient period pressure drop due to The governing equation for this case is
production has been felt at the drainage boundary Reproduced from Pressure
Buildup and flow test in a
of the well. well by Matthew and Russel
bounded reservoir.
Therefore, the solution for bounded reservoir
developed earlier can be utilized for this region.
Where, average reservoir pressure
Skin factor can be determined from
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Where, k is in milidarcies
Where;
The slope of line, (P2) vs. Log (t) will have slope, m,
Example Solution
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Solution contd.
102
As m is given by,
Sampling: A Well Testing Operation
Seperator
rely on the early determination of
Stock tank expected reserves and production
PSTC, TSTC Oil (sto)
Sampling rates. In such cases, it is important Sequential Formation Test Tool (SFTT)
for measuring precise formation and
that the new well be cleaned up wellbore-hydrostatic pressure readings,
Recombination collect reservoir fluid samples 2.75-gallon
Reservoir
Sampling before sampling to remove all chambers and optional 1.0, 5.0 and 8.0
(Representative)
traces of drilling fluid from the gallon chambers.
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OIL/GAS RESERVOIR Reservoir Fluid Sample well and wellbore area. Ref.: http://www.hlsasia.com
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The producing conditions and surface or subsurface If samples of oil and gas are taken at the surface, it is vital that
equipment can be important considerations in the producing rates and gas-oil ratio be accurately determined
in order that the fluids may be recombined in the correct ratios
designing a sampling procedure. The most to formulate a representative sample.
important of these are;
If the well is not producing with stable GORs, or if separation
The type of fluid being sampled facilities are not adequate for accurate measurements, a surface
The stability and accuracy of gas rate, oil rate, and recombination sample should not be considered.
GOR measurements Water production can be troublesome, even in small amounts. If
The proximity of gas-oil or oil-water contacts to the possible, no well that is producing water should be considered
productive interval. for obtaining a representative hydrocarbon sample. If necessary,
a water-producing well may be sampled if precautions are taken
The dimension of downhole equipment.
to obtain the sample from above the oil-water contact in the well
The well location. or separator.
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The objective of well conditioning is to replace the After conditioning the well, samples may be taken
non-representative reservoir fluid located around with a bottom hole sampling device, or individual
the wellbore with original reservoir fluid by samples of oil and gas may be taken at the surface
displacing it into and up the wellbore. and recombined to obtain a representative
reservoir fluid sample.
A flowing oil well is conditioned by producing it at Choice may be due to
successively lower rates until the nonrepresentative The volume of samples required.
oil has been produced. The well is considered to be The type of reservoir fluid to be sampled.
conditioned when further reductions in flow rate The degree of reservoir depletion.
have no effect on the stabilised gas-oil ratio. The surface and subsurface equipment.
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Generally, a bottom hole sample is preferred if gas The best and easy way to
and oil surface measurement capabilities are in insure the validity of a sample
is to measure its bubble point
question. However, if they are reliable, the surface pressure and compare it with
sampling technique can give a statistically valid the bubble point pressure
value of GOR measured over a long period of measured on a duplicate
time. Whenever possible, separator liquid and gas sample taken at the same sample
samples should be taken simultaneously in order to conditions.
have the same sampling conditions for both fluids. If sample contains H2S, on site
analysis is recommended, or the Pb or Pd
lab analysis within 24 hrs is
highly required PVT cell
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IPR Equation: general form C : flow coefficient Empirical constant This test start from shut-in
n : exponent condition
The well is opened for
Taking log particular choke size and
is not disturbed until flow
rate and Pwf are
stabilized.
A well is usually
stabilized in 15-20
minutes.
At each stabilization, Pwf
and qsc are measure.
Once the value of n
This procedure is
determined from plot, C repeated for some more
can be calculated as; sample points
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Solution Solution
PR2=1952*1952=3810*103
IPR curve
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Types of Tests
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Productivity well testing, the simplest form of testing, provides: Estimation of the formations flow capacity, characterisation of wellbore
damage and evaluation of a workover or stimulation treatment all require
Identification of productive fluids, a transient test because a stabilised test is unable to provide unique values
the collection of representative samples and determination of reservoir for mobility-thickness and skin.
deliverability Transient tests are performed by introducing abrupt changes in surface
production rates and recording the associated changes in bottomhole
Formation fluid samples are used for PVT analysis pressure.
PVT analysis also provides fluid physical properties required for well test Production changes, carried out during a transient well test, induce pressure
analysis and fluid flow simulation. disturbances in the wellbore and surrounding rock.
Reservoir deliverability requires relating flow rates to drawdown pressures. These pressure disturbances travel into the formation and are affected in
This can be achieved by flowing the well at several flow rates (different choke various ways by rock features. For example, a pressure disturbance will
sizes) and measuring the stabilised bottomhole pressure and temperature prior have difficulty entering a tight reservoir zone, but will pass unhindered
through an area of high permeability.
to changing the choke.
Therefore, a record of wellbore pressure response over time produces a
The plot of flow data verses drawdown pressure is known as the inflow curve whose shape is defined by the reservoirs unique characteristics.
performance relationship (IPR).
Unlocking the information contained in pressure transient curves is the
The IPR is governed by properties of the rock-fluid system and near wellbore fundamental objective of well test interpretation.
conditions. Jitendra Sangwai, IITM, 2011 Jitendra Sangwai, IITM, 2011
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129
Seismic
Cores
Logs
IF YOU FAIL TO PLAN, YOU ARE PLANNING TO FAIL
--- Sir W. Churchil
Well tests
wireline
matching packer
pressure, temperature gauge
perforations
Model input Mathematical Model Model output
formation
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Pwf Pwf
Time tp Time
Reservoir Engineers
Production Engineers
Reservoir characterization
Test radius of investigation
Average reservoir pressure Formation permeability (vertical, horizontal)
Productivity index Barriers to flow (sealing or leaky)
Shale bed boundaries
Skin Structural limits (fault, salt dome, pinch out)
Rate dependent skin
Skin components Fluid contacts
Gas cap, aquifer
Post treatment skin after perforating, gravel packing, acid injection, or hydraulic
Injection well swept zone
fracturing
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q q
PI
p p p wf
Well near sealing fault
PI dependent upon:
permeability-thickness (kh)
viscosity Well near another producing well
skin
rate (special cases)
140
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Pressure transient curve analysis probably provides more Typical pressure responses that might be observed
information about reservoir characteristics than any other technique. with different formation characteristics are shown
in Figure
Horizontal and vertical permeability, well damage, fracture length, The top curve represents the pressure changes
and interporosity flow coefficient are just a few of the associated with an abrupt production rate
characteristics that can be determined. perturbation, and the bottom curve (termed the
derivative curve) indicates the rate of pressure
In addition pressure transient curves can indicate the reservoirs change with respect to time
extent and boundary details. The bottom curves shows the sensitivity to transient
The shape of the curve, however, is also affected by the reservoirs features resulting from well and reservoir
production history. geometries (which are virtually too subtle to
recognise in the pressure change response) makes
Each change in production rate generates a new pressure transient the derivative curve the single most effective
that passes into the reservoir and merges with previous pressure interpretation tool.
effects. However, it is always viewed together with the
pressure change curve to quantify skin effects that
The observed pressures at the wellbore will be a result of the are not recognised in the derivative response
superposition of all these pressure changes. alone.
PD PD
143 144
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PD
145 146
PD
147 148
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