Well Testing

5/27/2018 Well Testing

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WELL TESTINGIntroductionWell testing has come a long way since the first drill stem test was run in 1926. From a simple

composite packer and valve run on drill string, the scope of well testing has blossomed into a broad array of

sophisticated down hole and surface technologies.

What is well test?A well test is a period of time during which the rate and/or pressure of a well is recorded

to estimate well or reservoir properties, to prove reservoir productivity, or to obtain general

reservoir management data.

Why do we test well?The main reason for testing an exploration well is to take a fluid sample. Further reasons

are to measure the initial pressure, estimate a minimum reservoir volume, evaluate the well

permeability and skin effect, and identify heterogeneities and boundaries.Testing producing wells aims at verifying permeability and skin effect, identifying fluid

behavior, estimating the average reservoir pressure, confirming heterogeneities and boundaries,

and assessing hydraulic connectivity.

By measuring in-situ reservoir conditions and fluids as they flow from the formation, the testing

process gives E&P companies access to a variety of dynamic and often unique measurements.Depending on the scale of a test, some parameters are measured at multiple points along the flowpath, allowing engineers to compare down hole pressures, temperatures and flow rates against

surface measurements of the same parameters.Through well testing, operators can extract

reservoir fluid samples both down hole and at the surface to observe changes in fluid propertiesand composition between the perforation and the wellhead.

Data Measuring PointDepending on the scale of the test, a variety of measurement may be obtained down hole,

at the surface, and the different floe path.

Surface Acquisition

Depending on the scale of the test, a variety of Depending on the scale of the test, a variety of

Measurements may be obtained down hole, at

the surface, and at different



Points along the flow path Points along the flow path








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Down Hole Acquisition







Well Test Objectives

Exploration well:

On initial well, confirm HC existence, predict a first production forecast (DST: fluid

nature, Pi, reservoir properties

The exploration well predicts the following characteristics:

Nature and rate of produced fluid Initial pressure Reservoir properties

Appraisal well:Refine previous interpretation, PVT sampling, (longer test: production testing)

The appraisal well predicts the following characteristics:

Reservoir properties Permeability Heterogeneity Reservoir boundaries Well productivity Fluid properties (sampling)

Development well:On production well, satisfy need for well treatment, interference testing, Pav

The development well predicts the following characteristics:

Reservoir properties Drainage mechanism (permanent gauges) Communication between wells Well productivity Average pressure

Pre-Job MeetingThe following information should be discussed prior to the job.

Test Objectives Pressure and temperature data

Flow rates Downhole samples

Test duration

Test multiple zones Type of data collectionsurface readout, memory gauges

Analysis of collected data


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Well Information

Expected bottom hole temperature Elastomers required Data collection required Weight of annular fluid

Surface pressure- Pressure rating required for the surface equipment

Down hole pressurePressure rating required for the downhole tools

Packer required Type of cushion required Data collection system required Tubular required

Type of Productioncrude, dry gas, H2S, CO2, etc.

Elastomers required Tools required

Surface equipment required Test durationType of mud systemwater based, oil based, brine

- Elastomers required

- Tools required Casing or liner

Size and weightto determine size of tools

- Pressure rating- Location of liner lap

- Pressure rating of liner lap

Hole conditions

- Total Measured Depth (MD)- True Vertical Depth (TVD)

- Maximum deviationcan have an effect on what tools are used and if wire line is practical

- Type of formationwill sand be produced?

Perforating- Tubing conveyed perforatingpressure activated, bar job

- Perforating before test- Wireline guns through down hole tools

Type of work string

- Tubingrecommended for high pressure gas, HPHT

- Drill collarsdrift needed for wire line passage

- Landing stringfor floating vessel Drill pipe

Cushion

- Type of cushiondetermines type of elastomers required- Weight of cushiondeterminespressure differential across test tools and works tring - Method of cushion placementspot, self-

fill, fill at surface


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Well site Preparation

Prior to testing, the following preparations need to be completed. Equipment Preparation

Pressure test blowout preventers (BOP) Pressure test subsea equipment

Pressure test surface equipment

Function test downhole tools Pressure test downholetools Drift all equipment

Obtain work permits for pressure testing

Personnel Preparation Hold safety meeting before test

- Know location of firefighting equipment

- Know evacuation procedures

- Stress no smoking rule during test- No welding or open flames during testing

- No lifting over surface well test area

- Use correct personal safety equipment Instruct all essential personnel what procedures will be followed during testing.- Running in hole (RIH)

- Firing tubing conveyed

Perforating (TCP) guns- Flowing well

- Shut-ins

- Wireline procedures- Sampling

- Killing well

- Reversing out

- Pulling out of hole (POOH)Know when to abort test.- H2S detected over flowing limitequipment not rated for H2S service

- Downhole tool malfunction- Subsea tool malfunction

- Surface leak that cannot be bypassed or repaired quickly

- Deteriorating weather conditions- Leak in string, casing, tubing, etc.

Establish methods of

communication.

- Voice

- Hand signals- Hand radios

Conducting a Safe Well Test

During a test, there are numerous factors to be considered to help ensure a safe well test.Picking Up Tools

Only qualified personnel to sling and direct crane operator

Use a guide rope line for long assemblies

Always use handling subs


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Making Up Tools All tools to be measured and drifted prior to running in well

Tool operator to direct the make up of the tools and advise driller on proper torquerequirements

Use safety clamp or dog collar any time the elevators are released from the tool

Always use a hole cover Do not use iron rough neck on toolsRunning in Well Ensure the hole is filled before running in

Ensure the hole is stable before running in

Types of Well TestingDuring well test reservoir fluid are produced to a separator at varying rates according the

prescribed schedule. These days take less than two days to evaluate a single well or months toevaluate reservoir extent.

The most common test include are:

Build up test Draw down test Fall of test Injection test Interference test Isochronal test (a series of buildup and draw down test) Back Pressure Test

Build up TestingTest ObjectivesThe primary purpose of performing a build-up test is to determine the:

Wellbore damage (skin) & stimulation Determination of reservoir permeability. Determination of pressure level in the surrounding formation Reservoir limits test

However, during the course of a build-up, it is possible to encounter reservoirboundaries. If all the reservoir's boundaries are contacted during the build-up, the size of the

reservoir can also be determined. If the well has been pressure tested before, subsequent testing

allows relative material balance calculations (decline curve analysis), as well as thedetermination of the drive mechanism for the reservoir.

In ideal build up test we mean a test in an infinite, homogenous, isotropic reservoir containing a

slightly compressible, single phase fluid which constant fluid properties. Any well bore damage

or stimulation is considered to be concentrated in a skin of zero thickness at the well bore.Now we suppose that well is producing from an infinite acting reservoir, the formation and fluid

have uniform properties so that Eifunction applied, the Horners pseudo producing time

approximation is applicable.

Basic Equation for Buildup TestThe basic equations of pressure build up test are:

Pws = Pi - (162.6qBo/kh) log (tp+t/t)


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This is the equation of a straight line when plotted as Pw Vs log (tp+t/t) (Hornerplot) with slope m =162.6qBo/kh and intercept Pi

From this k& scan be determined as k = 162.6(qBo/mh)

S = 1.1513(((P1hr-Pwf)/m)-log (k/ Ctrw2) +3.23) Fault distance= (0.0122ktx/ Ct) 1/2 Pskin= 0.87ms

Procedure

Install the SPIDR on a well that has been flowing steadily for several days. Check forleaks in the system after installation. The SPIDR must be recording for at least 15 minutes prior

to shut in (check the box for the SPIDR wake-up time). Shut the well in manually at the wing.

After the well has been shut in, check for leaks again. When the build-up is over, the SPIDR may

be rigged down and returned, or it may be left on the well for further testing while the well isflowing.

Installation of SPIDR

The SPIDR is not position sensitive. However, it is strongly recommended that it be installed onthe crown of the well. Before installing "Tee" between the needle valve and gauge on the crown,

crack open the needle valve to blow clear any foreign material.Do not use tools on the capillary tubing's knurled nuts. If finger tight does not affect a seal, try

reversing the capillary tube assembly. Avoid kinking or crushing the capillary tubing. Teflon

tape or thread dope should be used on all threaded fittings. DO NOT use tape or any type ofsealant on the capillary tubing. If running a build-up, periodically check all fittings for leaks withthe SNOOP leak detector, especially after a shut-in. The electrical port protector caps on the

SPIDR must be in place when a port is not in use.

A schematic of a SPIDR well-head installation is shown below


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Build up test graph

Advantages

A build-up test is one of the simplest tests to perform. The biggest advantage in

performing a build-up is that it is a constant rate test: Q = 0. Simply install the equipment whilethe well is flowing, and then shut the well in upstream of the choke.

Disadvantages

The drawback to performing a build-up test is that you lose cash flow. (Some people

might think that you are actually losing gas, but it's still down there.) Nevertheless, if the testobjectives are to determine skin and perm, and the rock has permeability greater than 2 milli

Darcies, most build-up tests can be limited to 2 days.

CommentaryIt has been our experience that it is easier to obtain management approval for a build-up test

when it is done in conjunction with a planned shut in due to facilities scheduled maintenance.

After a build-up it is advisable to perform a single rate drawdown, or a Modified Isochronal test.

Draw Down TestTest ObjectivesThe objectives of a drawdown test are to determine:

Estimates of permeability Skin factor Reservoir volume

These tests are particularly applicable to:

New wells Wells that have been particularly shut in sufficiently long to allow the pressure to

stabilize

Wells in which loss of revenue incurred in buildup test would be difficult to accept.


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Exploratory wells are frequent applicant for lengthy draw down test, with common objectives of

determining minimum or total volume being drained by the well.

Basic Equations for Draw Down testBasic equations are as follows:

Pwf=Pi(162.6qBo/kh)((log t + log (k/Ctrw2)3.23+0.87s) This is the equation of a straight line with slope m = 162.6(q Bo /kh) From slope permeability and skin can be calculated as k = 162.6(q Bo /mh) S = 1.151(((P1hr - Pwf)/m) - log(k/ Ctrw2 )+3.23)

Procedure

Install the SPIDR on a well that has been shut-in and stable. "Stable" is defined as theshut-in well head pressure changing at a rate of less than 1 psi per hour. Check for leaks in the

system after installation. The SPIDR must be recording for at least 15 minutes prior to opening

the well (check the box for the SPIDR wake-up time). Begin flowing the well on a single choke

size. If the well must be "stepped-up", try to get the well up to full rate within 30 minutes.Continue flowing on a constant choke size for the duration of the test. If shut-ins or flow

interruptions occur during the course of the drawdown, try to get the well back on-line as soon as

possible on the same choke size.

Graph for Draw down Test

AdvantagesThe main benefit of running a drawdown is that cash flow is not interrupted. Another

advantage is that reservoir boundaries are easier to locate, relative to build-up tests.

Disadvantages

The drawback to running a drawdown is that the rate may not be constant. However,changing the choke periodically to maintain a constant rate will cause more problems than letting


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the rate fluctuate. In order to get accurate analysis on a drawdown, it is critical that no choke

changes occur during the test.

Fall of TestBasic definition

The measurement and analysis of pressure data taken after an injection well is shut in.These data are often the easiest transient well-test data to obtain .Wellhead pressure rises during

injection, and if the well remains full of liquid after shut-in of an injector, the pressure can bemeasured at the surface, and bottom hole pressures can be calculated by adding the pressure from

the hydrostatic column to the wellhead pressure. Since most water-injection wells are fractured

during injection, and injection wells often go on vacuum, the fluid level can fall below thesurface. Dealing with this complication requires reverting to bottom hole pressure gauges

or sonic devices.

ExplanationFall-off (IFO) testing typically refers to testing done in either Water disposal wells or

injector wells for pressure maintenance or secondary/tertiary recovery methods.They are most often employed when either a new well is drilled and completed for this purpose

or more commonly a pre-existing production well is converted into a disposal/injectionwell. The IFO is the mirror image of a Pressure Build-Up (PBU) on a producing well and

analysis can derive the same types of fundamental wellbore/reservoir information on an injector

well that can with a producing well, skin, permeability and reservoir pressure. The main interestin the IFO is to understand skin and its effect on injector. Because we are limited to 0.5 psi/ft. on

injection surface pressures, an increasing skin will require ever higher injection pressures to

maintain the same injection rates. At some future point we will be limited by the surface

injection pressure limitation, as set by the state, not mentioning the increased cost of fuelinginjection pumps. If the well in question is a Saltwater Disposal (SWD) well, which often have

less stringent separation/filter requirements for the injected fluid, skin accretion can happenquickly. Knowing your "original" wellbore condition before injection begins and then testingperiodically thereafter or when you notice increasing injection pressures would be a good idea.

Injection Well TestingA well in which fluids are injected rather than produced, the primary objective typically

being to maintainreservoirpressure.Two main types of injection are common: gas and water.

Separated gas fromproduction wells or possibly imported gas may be reinjected into the upper

gas section of the reservoir. Water-injection wells are common offshore, where filtered and

treated seawater is injected into a lower water-bearing section of the reservoir.

A useful injection well measure should be:

1. Actionable: useful for initiating cost-effective maintenance

2. Reliable: physically based, free of extraneous effects3. Comparable: at a well, over time, with accumulated injection

4. Comparable: between wells in a well field and between wells in different well fields, aquifers

A key technical challenge in selecting and applying a useful injection well measure is that
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it should be clearly distinct and isolated from other effects that cause water levels to rise in an

injection well.The mechanical wellbore skin surrounding a well is the thin (inches at most)

radius starting at the original borehole wall and extending out into the aquifer. It is the radiuswhere sediments finer than that in the aquifer and microbial colonies accumulate. The adjective

mechanical is needed because the petroleum and natural gas industry well tests analysts have

called a wide variety of near-well processes that add to drawdown or build-up skins: partialpenetration, nonlinear flow.

Traditional Measures of Injection Well PerformanceThe traditional measures of injection well performance organize into three categories:

Purely data-based methods, Methods comparing data and simple models, and Simulation model parameter estimation methods

Purely Data-based Methods

The purely data-based methods compare only measured quantities or simplearithmetic operations on measured quantities. The catalog accumulated here includes:

1. Water-level rise in injection well at a standard time 2. Water-level rise/injection rate for injection well at a standard time 3. Injection rate/water-level rise for injection well at a standard time 4. Difference in water-level rises at a standard time between injection well and separate

observation well

5. Water-level rise at a standard time normalized to standard injection rate and standardviscosity

The purely data-based methods are by far the most attractive because they are verysimple to compile and many professionals have compiled some or all of these measures

for several decades, which lends confidence in their use.The disadvantages of these purely data-based methods are that:

1. The base for calculating the rise of water levels can be complexthe preinjectionwater level may not be a stable starting point

2. The standard time for comparison has an unreliable foundation - it isnt standardandanalysis of injection in each well and aquifer combination would likely benefit from a

unique standard time

3. With the exception of comparing rises in an injection well and a nearby observationwell, these measures dont isolate mechanical wellbore skin fromother effects

4. These measures cant be reliably compared across other wells and well fields andtherefore the profession is limited from accumulating transferable experience and

judgment as has developed using AWTA in the petroleum and natural gas industry.

Comparisons of Data and Simple ModelsThese measures are variations on the efficiency idea from engineering in which

observations are compared to theoretically perfect operations. The catalog accumulated

here includes:

1. Ratio of observed water-level rise in the injection well at standard time to water levelrise simulated with the Theis equation at standard time


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2. Difference between observed water-level rise in injection well at standard time andwater-level rise simulated with Theis equation at standard time. The advantages of these

efficiency-based methods are that they are relatively simple to compile and that many

professionals have calculated these measures for several decades, which lends confidenceto their use.

The disadvantages of these efficiency-based methods are that: 1. The base for calculating the rise of water levels can be complexthe preinjection

water level may not be a stable starting point

2. The standard time for comparison has an unreliable foundation - it isnt standard andanalysis of injection in each well and aquifer combination would likely benefit from a

unique standard time

3. Situations are rare for which the Theis Equation is theoretically perfect performance.Theis doesnt incorporate many significant and well-understood processes (e.g., finitediameter well, mechanical wellbore skin, partial penetration, etc.)

4. These measures are not comparable across different settings.Parameters from Fitting to Simple ModelsMethods in this class match a selected simple model (short equation) to observations by

methodically estimating the model parameters (i.e., coefficients). The coefficients can becompared over time to track injection well performance. The catalog accumulated here

includes:

BQ+CQnparameters are B, C, and n [although n should be 2] Other polynomials or similar equations Artificial Neural Networks

The disadvantages of these methods comparing data and simple models are

that: Standard time for making calculations has an unreliable foundation Physical interpretation of the coefficients is unclear Casing versus aquifer inertial flows not separated Mechanical wellbore skin is ambiguously mixed in several coefficients Some coefficients change with time, while some do not change with time These measures are not comparable across different settings

Isochronal TestA fundamental reason that the conventional test is theoretically sound is that theradius of

investigation is constant for each flow period. In order to uphold this principle, the isochronal

test takes advantage of the fact that theradius of investigation is a function of time and not flowrate. An isochronal test is conducted by flowing a well at several different flow rates for periodsof equal duration, normally much less than the time required for stabilization. A shut-in, long

enough for the pressure to reach essentially static conditions, is performed between each flow

period. In addition, an extended flow rate, long enough to reach pressure stabilization, is

required. In tight reservoirs the length of time required to reach pressure stabilization betweenflow periods could make the isochronal test impractical.

Modified Isochronal Test
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The modified isochronal test is an isochronal test which requires that each shut-in

between flow periods, rather than being long enough to attain essentially static conditions should

be of the same duration as each flow period. It also requires an extended flow period.

Single Point TestA single point test consists only of an extended flow period. They require an estimate of

the degree of turbulent flow in the formation. This estimate is often based on informationprovided by other wells in the same formation or calculated from reservoir andfluid properties.

AOF Flow ConditionsExtended Flow

Normally an isochronal test includes one flow rate that is extended to stabilization and a

stabilized pressure and flow rate point is determined. This point is the extended flow pressure

and flow rate for the test. Single point tests do not include the multi-rate portion of a test andconsist of only an extended rate and pressure.

Stabilized Shut-in

Stabilized generally refers to a test in which the pressure no longer changes significantly

with time. For AOF tests, the stabilized shut-in pressure is a pressure that reflects theaveragereservoir pressure at the time. It is either measured during the test or determined from the

interpretation of the data.

Stabilized FlowIn highpermeability reservoirs or wells with smalldrainage areas,it may be possible to

flow the well until stabilization during the extended flow period of a deliverability test. In these

cases, the stabilized pressure and flow rate point is the extended flow point.

Many tests, however, are not flowed to stabilization because of time constraints (especially in

tight reservoirs). An extended flow and stabilized shut-in are still performed at the end of thesedeliverability tests so that the buildup data can be analyzed and from that the stabilized rate

calculated. Stabilized flow can be determined by calculation or by creating amodel of thereservoir, doing a forecast at a specified pressure, and finding the point when the rate has

stabilized (usually at 3 months, 6 months, or 1 year) .

Types of AnalysesTwo types of analysis are available, the simplified analysis or the laminar-inertial-

turbulent (LIT) analysis.

LIT analysisIs more rigorous than simplified analysis and is usually only used in tests where

turbulence is dominant and the extrapolation to the AOF is large. However, in most cases the

simplified analysis is sufficient to determine the AOF and deliverability.

Pressure Method

For both the simplified and LIT analysis, two pressure options are available, the pressuresquared or thepseudo-pressure approach.

Pressure SquaredThe pressure squared approach is the more traditional method, and is often used because

it is easier to understand and calculate. However, it is only valid for medium to low pressure

ranges but is just as accurate as thepseudo-pressure approach in this range.

Pseudo-Pressure
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Usingpseudo-pressure will be more accurate than the pressure squared approach,

especially when dealing with a high pressure system, wheregas viscosity

(mg) andcompressibility (cg) cannot be assumed to be constant. Thus, pseudo works for allpressure ranges, although it is more difficult to calculate and requires more computational time.

Simplified Analysis

The simplified analysis is based on the following equation:

Pressure squared orPseudo-pressure

The analysis of a modified isochronal test using the simplified method is illustrated below. For

the modified isochronal test, pwsmust be used instead of pRbecause the duration of each

shut-in period is too short to reach static conditions.

The data is plotted on a log-log plot of2versus qstwhere

2is defined as:

The flow and shut-in periods of equal duration provide the information required to plot four

points. A straight line, called the transient deliverability line, is drawn through these four points.The duration of the last flow rate is extended until the pressure response has stabilized. This

information is used to plot another point called the stabilized point. A line parallel to the transientdeliverability line is drawn through the stabilized point. This is called the stabilized deliverability line.
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If the extended flow period does not reach pressure stabilization, a stabilized point can be foundby calculation from a buildup testThe parameter ncan be determined from the slope of the line as follows:

Thus, slope is equal to 1 / n, and nis called the inverse slope.

The other parameter, C, can be determined using nand the coordinates (qstandpR) of any point

on the stabilized deliverability line (e.g. the stabilized point) as follows:

Note that Cand n are considered to be constant for a limited range of flow rates. In theory, it isexpected that this form of the deliverability relationship will be used only for the range of flow

rates used during the test. However, in practice it is used indiscriminately for a wide range ofrates and pressures.

LIT AnalysisThe LIT analysis is used with dealing with high rate wells where turbulence is a major

factor. Only thepseudo-pressure approach can be used in this situation since pressures are in a

higher range due to the turbulence effects. LIT analysis is defined by the following equation:
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Note that thepseudo-pressure squared terms (a qstandb qst2) are equivalent toskin due to

damage (sd) andskin due to turbulence (sturb). The coefficients aand bare defined in the

example below.The analysis of an isochronal test using the LIT method is illustrated below.

Data is plotted on a Cartesian plot ofDy / qversus qstwhereDy / qis defined as:
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As in the simplified analysis, the transient deliverability line is drawn through the four isochronalpoints and a parallel stabilized deliverability line is drawn through the stabilized point.The LIT coefficients, aand b, can be obtained by re-arranging the deliverability equation into the

form below and plottingDy / qversus qston Cartesian coordinates.

From this equation the slope of the line is equal to b. The parameter ais determined by re-

arranging the above equation to solve for aand then substituting band the coordinates

(qstandyR) of any point on the line.

Back Pressure TestDuring a back pressure test a well is allowed to flowed against a specific back pressured

until its BHP and surface pressure are stabilized an indication that flow is coming from the outer

reaches of the drainage area.

Absolute Open Flow (AOF)The absolute open flow (AOF) potential of a well is the rate at which the well would

produce against zero sand face back pressure. It is used as a measure of gas well performancebecause it quantifies the ability of a reservoir to deliver gas to the wellbore. Deliverability tests

make possible the prediction of flow rates against any particular back pressure, including AOF

when the back pressure is zero. This result is illustrated on the following inflow performance

relationship (IPR) plot.


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Note that the AOF and deliverability plots can be generated at both wellhead and sand face.

Types of Deliverability TestsThere are a number of tests which can be conducted in order to calculate the

deliverability of a well as described below.

Conventional Back Pressure TestThe conventional back pressure test is conducted by flowing a well at different

rates. Each rate is sustained until theradius of investigation has reached the outer edge of

thedrainage area and pressure stabilization has been reached. This type of test is not practical

for lowpermeability reservoirs because the time to reach pressure stabilization for each rate isexcessive.

Interference Well TestingThepressure variation with time recorded in observation wells resulting from changes in

rates inproduction or injection wells. In commercially viable reservoirs, it usually takesconsiderable time for production at one well to measurably affect the pressure at an adjacent

well. Consequently, interference testing has been uncommon because of the cost and the

difficulty in maintaining fixed flow rates over an extended time period. With the increasingnumber of permanent gauge installations, interference testing may become more common than inthe past.

Targets of interference test:

The target is defined by the customer. Survey program is designed in order clarify maximumissues.

Interwell communication test (between active and observe wells). Reservoir parameters

estimation;

Fault between wells rectification; Productive layers pitching detection;

Development correction according to the interference test results;

Reserves confirmation (SEC classification);

Brief description

Description, advantages and disadvantages of interference test.
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Parameters determinationReservoir parameters

Reservoir parameters such as reservoir pressure, Bubble point pressure, porosity; totalsCompressibility, pay thickness distribution are analyzed and clarified in order to estimate its

influence on disturbance wave propagation through the tested part of reservoir.

Fluid parametersFluid parameters such as saturation, water cut, fluid densities, viscosities, volume factors etc. are

analyzed and clarified in order to estimate its influence on disturbance wave propagation throughthe tested part of reservoir.

Operation parameters

Considering the task the following parameters are defined:

An observation and disturbing wells Number of pulses

Pulse duration

Test duration Operationregimes of wells

Test duration criteriaTest tool parameters, reservoir nose influence are considered while choosing the duration of test.

Zone of silence

The zone where there no changes of operation regimes should be done is defined. The zone ofinvestigation is defined considering reservoir parameters.

Tools technical characteristics

Required parameters of tools (range of measurements, sensibility, resolution, accuracy, memorycapacity, continuous operation time etc.) and appropriate tools are selected.

Results of designCalculation results

Disturbing well continuous operation time (one cycle): in hours

Observation well shut down time (one cycle): in hours Whole test duration: in hours

Signal delay: in hours

Cumulative volume of injected/produced water: in cu.m

Bottom hole pressure: bar

Basing on the calculated model the well test is designed. Predicted plots of bottom hole pressure

of production/injection wells are submitted;

Interpretation

Interference test data quality estimation the following aspects are depicted in result of test dataanalysis:


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External processes influence on the pressure disturbance wave propagation from disturbing till

observation well;

Technical errors; Range of data for interpretation;

Average rate of disturbing cycles (pulses) for interpretation;

Possibility of interpretation of available data and its result;

The criteria of interference test response time definition

Time response depicts the time necessary for pressure disturbance pulse traveling fromdisturbing well till observation well. Accuracy of this parameter estimation depends on the

reservoir noise amplitude, duration of noise from disturbing well and pressure gauges sensitivity.

Basing on the time of pulse traveling within the reservoir the order of wells which sensed the

pulse the conclusions about Interwell connectivity should be done.

Fault location

Basing on the amplitude and pressure response time the location of fault may be done.

Test parameters tuning

After comparison of interference test design and obtained data the further tests are adjusted.Simulation model is tuned. New adjusted and refined filtration model will be able to match the

history of field development.

Interpretation data and parameters of test comparisonThe trajectory of pressure propagation wave is defined, qualitative estimation of reservoir

features, pitching and further well test recommendations are generated on the basis of data

correlation.

Influence of test results on reserves estimation

The basis of reserves classification is on the proved reserves. In the results of interference test

interpretation and Interwell connectivity the new regions of proved reserves grows are defined,areas and volumes of corresponding types of reserves are estimated.

Multi-rate Well TestingThe different types of multi-rate tests, as well as addressing which type of well test should beperformed to meet a given objective. Different types of multi-rate tests are performed to meet the

following objectives:

1. Evaluate the completion (skin, type of skin, DeltaP across completion)2. Evaluate the reservoir (permeability, distance to limits, reservoir volume, P*)

3. Satisfy state or federal regulations (MMS initial or annual survey, state mandated

deliverability tests, etc.)4. Determine deliverability or AOF as required by pipeline operators


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Rate-After-Rate TestThe most common type of multi-rate test is rate-after-rate test. To perform this type of

test, pressures are recorded during a build-up and during successively increasing rate steps as the

well is opened. Rates, as well as pressures, should be recorded during the flow periods. It is

recommended for SPIDR (surface) tests that this initial rate be 1.2 times the unloading velocity

of the well bore. After the rate and pressure have stabilized, or after a given fixed time interval,the rate is then increased. This process is then repeated as desired (usually 4 rates for a 4-pt. test),

and then the well is either shut-in again or simply allowed to produce. It is common practice to

have the final rate be 2-3 times as long as the previous rates. Once the data has been gathered,the BHP's are plotted on an Absolute Open Flow (AOF) plot to determine the deliverability of

the well and the Absolute Open Flow of the well. AOF is defined as the number of cubic feet of

gas per 24 hours that would be produced by a well if the only pressure against the face of the

producing reservoir in the well bore were atmospheric pressure. The flow of gas to the well borecan be described as Q=C (BHPsi2 - BHP wf2)n where Q is the rate, BHPsi is the shut in BHP

and BHPwf is the flowing BHP, C is a constant that describes the position of the stabilized

deliverability line, and n is an exponent that accounts for non-ideal gas and non-steady state

flow.Rate Modified Drawdown Test

Another version of a multi-rate test is a 2-rate modified drawdown. In this case, a flowing

well has its rate doubled to start a new transient. The drop in Flowing Bottom Hole Pressure's

(FBHP's) enables reservoir and completion evaluation. Another type of 2-rate test is performedby reducing the rate and observing the pressure increase in the FBHP's. This type of test is

performed on wells where there is concern for phase re-segregation during a build-up.

Hypothetically, this partial build-up should provide everything that a normal build-up would

provide. In practice, this type of test should only be used to determine if the well has a significantskin and to provide a rough estimate of permeability. Another use of a 2-rate test is to estimate

the reservoir pressure by assuming a constant PI (productivity index) and plotting (Pinitial -

Pwell flowing)/Q. However, this technique is only valid in high-permeability reservoirs.

One of the difficulties in a rate-after-rate test is that some of the rate changes may not be large

enough to create a new transient in the reservoir. To ensure a new transient is created each time

the rate is changed, the new rate should be double the previous rate. If this is not the case,boundaries may affect the pressure decline differently for different rates, which often leads to an

underestimation of the well's PI. To mitigate this problem, isochronal tests may be performed.

Isochronal (Modified) TestsIsochronal tests (and Modified Isochronal tests) provide more accurate deliverabilitys

than those provided by a rate-after-rate test and also permit evaluation of rate-dependent skin.After a stabilized SIBHP is achieved, the well is produced in the same sequence as a rate-after-rate test, except that at the end of each rate, the well is shut-in. In an Isochronal test, the well is

shut-in until the SIBHP stabilizes; in a Modified Isochronal test, the well is shut-in for the length

of time of the previous flow period. The last flow period is generally 4-6 times the length of the

other flow periods. After the final flow period, the well may be shut-in again, especially if theinitial shut-in data were not gathered. In practice, modified isochronal tests are performed much

more often than regular isochronal tests, since they are less open-ended (fixed shut-in times),


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take less time and provide equivalent results. Deliver abilities are determined in a similar fashion

to rate-after-rate tests, except that the final shut-in pressure prior to the rates is used to calculate

the effective Delta across the reservoir, instead of a fixed P*.

In general, the only drawback to a multi-rate test is that it has to be executed properly to get

meaningful results. All flow periods must be the same length of time except the final "stabilizedflow" period which should be 2-3 times the length of the previous flow periods for a rate-after-rate or 4-6 times the flow period for Isochronal tests. Rate-after-rate tests should have at least 3

rates and isochronal tests should at least 4. Most importantly, each successive flow rate should be

HIGHER than the previous rate.

SummaryMulti-rates are useful for completion and reservoir evaluation, regulatory testing and

AOF or deliverability of the well.A "rule of thumb" for drawdown testing (after shut-in) is that it is usually believable up to 2

TIMES the length of the previous shut-in. Therefore if the well has been shut-in for 2 days prior

to the drawdown the first 4 days of the drawdown is typically reliable information.Constant Choke, not constant rate. Simultaneously test while selling gas Multi-rate or flowingtests are typically not well-suited for type-curve analysis methods.

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Well Testing