Testing Design and Analysis

Bruno DeruyckMontrouge, France

Christine Ehlig-EconomidesClamart, France

Jeffrey JosephLondon, England

In this article, COMPUTEST (wellsite computer sys-tem), FPE (Fluid Properties Estimation), IMPULSE(measurement while perforating), MDT (Modular For-mation Dynamics Tester), PLT (Production LoggingTool), RFT (Repeat Formation Tester), SPG (Sapphire

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nEstimating producibility by altering theproduction rate and noting changes inbottomhole pressure (top). A well’s pro-ductivity index, or inflow performance, isthe slope of the straight line, measured inbarrels of oil per day per psi. The straight-line response curves downward oncepressure falls below bubblepoint and gasstarts coming out of solution.

In a layered reservoir, individual pro-duction rates measured using a produc-tion logging tool—layers A, B and C in thisexample—are plotted versus each layer’swellbore potential, the wellbore pressurenormalized to a datum. This so-calledselective inflow performance techniquereveals individual layer inflow perfor-mances and also pressure imbalancesbetween layers that can promote crossflow.

Well testing is performed in so many different guises that it is easy to lose

These are to confirm the economic potential

WELL TESTiNG

In its simplest form, testing provides short-term production of reservoir fluids to thesurface permitting the operator to confirmthe show—indicated by cuttings, cores andlogs—and estimate reservoir deliverability.In its subtlest form, measured pressure tran-sients caused by abrupt changes in produc-tion can characterize completion damage,reservoir permeability and distant reservoirheterogeneities.

The logistics of well testing are simple inconcept, but complex in practice. Flowingan exploration well requires a temporarycompletion. Flowing any well not con-nected to downstream facilities requiresheavy surface equipment including separa-tors and flares. Obtaining pressure transientsrequires alternately shutting and openingthe well, preferably downhole, and makingaccurate downhole measurements of pres-sure. Increasingly, testing is performed incombination with perforating and produc-

28

Pressure Gauge), STAR (Schlumberger Transient Anal-ysis and Report) and ZODIAC (Zoned Dynamic Inter-pretation Analysis and Computation) are marks ofSchlumberger.

1. Barnum RS and Vela S: “Testing Exploration Wells byObjectives,” paper SPE 13184, presented at the 59thSPE Annual Technical Conference and Exhibition,Houston, Texas, USA, September 16-19, 1984.

2. Freyss H, Guieze P, Varotsis N, Khakoo A, Lestelle Kand Simper D: “PVT Analysis for Oil Reservoirs,” The Technical Review 37, no. 1 (January 1989): 4-15.

tion logging to measure downhole flow.They are routinely run in horizontal as wellas vertical wells.

Developing the multifarious and intricatehardware to accomplish all these tasks is adesign engineer’s dream. And juggling themany options for conducting a well test pro-vides endless challenges in the field (see“The Nuts and Bolts of Well Testing,” page14). This article concentrates not on hard-ware but on the information well tests giveand how tests are designed and interpreted.

Primary concerns in testing explorationwells are obtaining representative samplesand estimating reservoir producibility.1 Fluidsamples are needed to determine variousphysical parameters required for well testanalysis, such as compressibility and viscos-ity, and for pressure-volume-temperature(PVT) analysis that unlocks how the hydro-carbon phases coexist at different pressuresand temperatures.2 For oil, a critical PVTparameter is bubblepoint pressure, the pres-sure above which oil is undersaturated ingas and below which gas within oil startsbeing released. Maintaining reservoir pres-sure above bubblepoint is key to successfultesting since the principle of transient analy-sis, described below, holds only if flow inthe reservoir remains monophasic. Estimat-ing reservoir producibility requires achiev-

Oilfield Review

sight o

of a di

Integr

ing stable flow rates at several choke sizesand then determining the productivity indexfrom the slope of the flow versus drawdownpressure data (previous page).

The type of oil as determined by a sampleand the ability of the well to produce arethe first steps toward commercial exploita-tion. If well productivity is less thanexpected, then wellbore damage may bethe cause. This is the next concern in testingexploration wells. Estimating the near-well-bore condition to perform necessary reme-dial action and ultimately to plan a wellcompletion strategy for the field is accom-plished from the transient analysis part of awell test.

Transient analysis, however, reachesdeeper than just the near-wellbore region.Today, it contributes so much to characteriz-ing the reservoir that engineers increasinglyrefer to well testing as reservoir testing.Analysis can indicate the likely producingmechanism of the formation—for example,how much production comes from frac-tures, how much from intergranular poros-

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Sealing fault

f its two real purposes.

scovery well and to maximize the cos

ated with other measurements, well t

ity—and it can determine the producingzone’s permeability-thickness product, kh. Itcan see to the limits of the reservoir indicat-ing the probable shape (but not orientation)of the reservoir boundaries and can showwhether the primary recovery mechanism isfrom water or gas-cap support. This infor-mation becomes crucial in the appraisal andproduction stages of field developmentwhen engineers combine testing interpreta-tion results with seismic and geologic datato refine their understanding of the reservoir.

How does transient pressure testing work?Imagine first an oil well in stable productionwith a certain pressure drawdown betweenthe far limits of the reservoir and the well.Now shut in the well. In the formation, asort of concertina effect takes place (below).Oil near the wellbore is the first to sense theshut-in and gets stopped in its tracks as ittries to push more oil ahead of it, gettingcompressed in the process. Then, the shockis felt farther away as news of the shut-in, soto speak, travels to the outer regions of thereservoir. Gradually, the pressure builds up

Fracture

nPlan view showing the moveprogressing away from a welldrilled near a sealing fault. Onsient moves into the formatiofracture. Farther from the welborehole. On hitting the sealintoward the borehole.

t efficiency of production in a develop

ests help provide the basis of reservo

everywhere, eventually reaching the reser-voir pressure that drives production.

The reservoir engineer follows this chainof events by measuring the pressurebuildup, or transient, and through analysisdetermines information about the reservoirfrom near the wellbore to its limits. An anal-ogous chain of events occurs if instead ofshutting in the well, the well is opened andallowed to flow. Again, it is oil near thewellbore that first senses the disturbance,but it is only a matter of time for oil deeperin the reservoir to respond and begin flow-ing too. Drawdown pressure measurementsto track these events practically mirror thebuildup response. In fact, transients can beobtained simply by increasing or decreasingthe flow rate.

Transient testing depends on accuratepressure measurements taken long enoughafter the flow rate change to observe whatthe test was designed to detect. Impulse test-ing, for example, measures the transient thatoccurs as a well is perforated, allowed toproduce for a short time and then shut in.

29

ment of wave fronts of a pressure transient. This shows a hydraulically fractured wellce wellbore storage disappears, the tran-

n along linear paths perpendicular to thel, the transient moves radially from theg fault, the transient begins reflecting back

ing or mature field.

ir characterization.

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nThree types of well testing: Impulse, conventional and interference. Impulse testingmeasures the transient caused by a very brief flow, typically just as the well is perfo-rated. Results yield skin and permeability and may indicate if remedial stimulation isrequired. Conventional well testing measures the shut-in transient after a lengthy flowperiod and is often used to detect reservoir limits. Interference testing measures thetransient in a well caused by one or more flow pulses in a nearby well. Results yielddetails about interwell transmissivity and storativity.

The primary target is the near-wellboreregion (right).3 The goal is to assess forma-tion damage and, if necessary, perform stim-ulation. Tests last just an hour or two. In aconventional test conducted to investigatereservoir boundaries, often called a limittest, the transient must be long enough forthe pressure disturbance to reach theboundaries and then create a measurableresponse in the well. How long this takesdepends on formation and fluid characteris-tics. In particular, the lower the formationpermeability, the more time is needed—testscan continue for days. Longest lasting areinterference tests, in which the effect of atransient created in one well is observed inanother, yielding information about reser-voir transmissivity and storativity.

The analysis and interpretation of welltests have evolved remarkably since thetechnique became established in the 1930s.Today, a unified methodology has devel-oped to obtain the maximum informationfrom any transient.4 The conventional teston a new well comprises two flow periodsand two shut-ins (next page). The first flowperiod, perhaps an hour long, is designed toclean up the near-wellbore region and givethe field crew time to manipulate chokes toestablish a practical, stable flow rate. Thewell is then shut in and pressure builds upto reservoir pressure, an important parame-ter for the reservoir engineer. Then begins along flow period, followed by a shut-in last-ing at least 1.2 to 1.5 times as long. This laststep generates the transient designed toyield the reservoir’s secrets. Of course, thereare many variants on this theme (see “Text-book Well Test from the Congo,” page 33).

0

3. Ayestaran L, Ayoub J, Campbell J, Fairhurst D, HerreraIC, Munsell S and Sneed BJ: “IMPULSE Testing,” TheTechnical Review 36, no. 4 (October 1988): 37-45.

4. For a review:Horne RN: Modern Well Test Analysis: A Computer-Aided Approach. Palo Alto, California, USA:Petroway, Inc, 1990.For the development of well test analysis:Ramey HJ Jr: “Advances in Practical Well Test Analy-sis,” paper SPE 20592, presented at the 65th SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 23-26, 1990.

5. Bourdet D, Whittle TM, Douglas AA and Pirard YM:“A New Set of Type Curves Simplifies Well Test Analysis,” World Oil 196 (May 1983): 95-106.Bourdet D, Ayoub JA and Pirard YM: “Use of PressureDerivative in Well Test Interpretation, paper SPE12777, presented at the 1984 California RegionalMeeting, Long Beach, California, USA, April 11-13,1984.

The basic data obtained are change inpressure, ∆p, versus elapsed time since thetransient was initiated, ∆t. In traditionalanalysis, ∆p is plotted against the logarithmof (tp + ∆t)/∆t , a dimensionless variable inwhich tp is the duration of the flow period.This is the Horner plot—(tp + ∆t )/∆t iscalled Horner time (next page)—and thetransient is analyzed by tracing theprogress of the data from right to left.

First comes wellbore storage, which refersto the obfuscating role of the wellbore fluidwhen a transient is initiated. The moment awell is shut in or allowed to flow, fluids inthe wellbore must first compress or expandbefore formation fluids can react. If flow iscontrolled from the surface, the entire well’sfluids contribute to wellbore storage and theeffect can dominate the pressure transientfor hours afterward. The effect is exacer-

bated if well pressure toward the top of thewell drops below bubblepoint and part ofthe well is filled with compressible gas.Wellbore storage is substantially reduced byshutting in the well downhole, minimizingthe volume of fluids that contribute.

As wellbore storage dissipates, the tran-sient begins to move into the formation.Pressure continues building up, but at aslower rate as the transient moves farenough to achieve radial flow toward thewellbore. This is the so-called radial-flowregime that appears as a straight line trendon the Horner plot. The radial-flow regimeis crucial to quantitative interpretation, sinceit provides values for kh and skin, S, a mea-

Oilfield Review

sure of the extra pressure drop caused bywellbore damage. Skin takes positive valuesin a damaged well when pressure drop nearthe wellbore is greater than expected andnegative values when stimulation createsless pressure drop. Next, the transientencounters the limits of the reservoir andpressure departs from its straight-line radial-flow response.

The definition of Horner time is based ona step change in flow rate, with one flowperiod followed by a buildup. In actualtests, there are always at least two prior flowperiods, often many more, and each affectsthe pressure response after it occurs. Never-theless, their cumulative effect can be deter-mined using the superposition principle,which states that transients occurringsequentially simply add up. This results ingeneralized Horner time that takes intoaccount the flow rates and flow times for allprevious flow periods. Using generalizedHorner time, the Horner plot retains itsvalidity in determining kh and skin for the

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Time

1st Flow 2nd Flow1st Buildup

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Data

nElements of a conventional two-stage buildsient test. Testing engineers use the first flowclean up formation damage and adjust the cgauge the producing capacity of the well. Thbuildup provides a first estimate of reservoir Then begins a long flow period, followed by buildup. Analysis of the transient measured second buildup reveals details of the near-wregion, formation characteristics such as perand distant limits of the reservoir.

Traditional analysis centered on the Horne(middle), in particular the straight-line trendnals radial flow. Today, the log-log plot (bottand the derivative, the slope of the Horner plto first diagnose the various flow regimes of tsient. Then, specialized plots such as the Horare used to estimate specific parameters sucmeability, skin and reservoir pressure.

most complex series of drawdowns andbuildups, providing that the radial-flowregime is present in the response.

Although the Horner plot is acceptable forinterpreting the radial-flow regime of easy-to-interpret tests, a straight-line trend is oftendifficult to pick out. Alternatively, there maybe several straight-line trends, of which onlyone represents radial flow. Also, the plotfails to provide ready insight into the natureof reservoir limits. As pressure measure-ments improved in accuracy, it was thisaspect that increasingly engaged the atten-tion of reservoir engineers. The solution, dis-covered in in the early 1980s, was a doublelogarithmic, or log-log, plot of two sets ofdata versus ∆t (below).5 One set is simply∆p, the other is the gradient, or derivative,of the response on the Horner plot. Thevirtue of the log-log plot is that reservoirssimilar in construction but perhaps differingin thickness, porosity and permeability giverise to similar looking responses and can berecognized as belonging to a class.

2nd Buildup

Horner Plot

(tp + ∆t )/

∆t

Log-Log Plot

Wellbore storage

Ra

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Radial flow

up tran- period tohoke toe first

pressure.a longerduring thisellboremeability,

r plot that sig-om) of ∆pot, is usedhe tran-ner ploth as per-

A pressure transient breaks into severalregimes on the log-log plot, each seeingdeeper than the last. The first regime typi-cally reflects wellbore storage, during whichboth the pressure and derivative curvesoverlay and increase along a straight line ofunit slope. As wellbore fluids stabilize, pres-sure continues building up, but at a slowerrate. The derivative curve swings down,eventually flattening out as the transientmoves far enough from the wellbore toachieve radial flow. Since the radial-flowregime is a straight-line trend on the Hornerplot, the derivative curve on the log-log plotis constant and traces a horizontal line. Theinterpreter’s first task always is to identifythis derivative plateau, but this may requirewaiting a long time in tests dominated bywellbore storage (page 34, top).

Lengthy wellbore storage can totally maskearlier flow regimes that occur for certainborehole-formation configurations and for-mation types, causing distinct perturbations

(continued on page 34)

31

∆t

Limitsdial flow

Wellbore storage

Limits

7 Once the radial-flow regime of the buildup is confirmed, the surface readout device is pulled out of the hole. Pressure data change color, from surface readout to downhole memory mode.

1000

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4800

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0

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10 The well is flowed back to clean up after the acid job.

1 The test begins with under-balanced perforation to minimize wellbore damage using tubing-conveyed perforating guns slung below the drillstem test tool.

3 The well is shut in so the surface readout device can belowered into the hole.

2 Downhole pressure jumps to the reservoir pressure level and then drops as the well is opened to clean up perforation debris.

4 With pressure now available at the surface (red curve), a 6-hour flow period begins, followed by a slightly longer buildup.

8 A short flow period during which a production logging profile is made,the tool passing through the fullbore drillstem tool to the newly perforated reservoir formations below. The flow profile shows good production from the sandstone but not so good from the overlying limestone, confirming that production would definitely benefit from an acid job.

11 The well is shut in so the surface readout device can be lowered again and hooked into the drillstem test tool.

9 The well is shut in as the acid job is prepared and performed.

6 During the buildup, the measured pressure transient (data points) is compared at the wellsite to the design (solid lines), which considered a range of skin values between –3 and 20. A value of –3 corresponds to a stimulated formation, 20 to a damaged one. Finding skin was crucial because it determined the necessity of an acid job. Overlaying the data on the design shows skin to be between 0 and 5—in fact, it was calculated at 1. This indicated that an acid job wouldprobably benefit production. Permeability is less important here, because it is well known in the area—100 md was assumed for the design, 85 md was estimated from the data.

13 Comparison at wellsite between pre- and post-acid buildups using surface pressure readout data. Using specialized analysis, the data indicates pre-acid skin to be 1, and post-acid skin to be –2, a substantial improvement. Because the post-acid drawdown and buildups are comparitively longer, the data sees further into the reservoir. After the radial-flow regime plateau, the post-acid derivative goes up and then down, eventually becoming noisy as gauge resolution is coming into play. This is the time to halt the test.

5 Five pressures, one obtained in surfacereadout and four in memory mode, are compared after normalization for different gauge depths. Agreement is within 12 psi, well within bounds of gauge technology.

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siSurface readoutSPG gaugeQtz. gauge 2

Qtz. gauge 1Strain gauge

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32 Oilfield Review

70 80 90 100 110 120 130

14 Toward the end of the buildup, the surface readout device is pulled out of the hole.

This textbook case study comes from an Elf exploration well in the Congo. The 2200-m [7218-ft] deep reservoir comprises a limestone overlying a sandstone, both having 20 to 22% porosity. The well test uses all the modern techniques—tubing-conveyed perforating, production logging and sampling through fullbore drillstem equipment, surface readout and wellsite validation—and is designed to accomplish two goals: One is to estimate near-wellbore damage, reducing it if necessary with a matrix acidization and then checking that the acid cleanup worked—all without removing the drillstring from the hole. This was intended not only to benefit production in the well, but also to help plan a completion strategy for field development. The other goal was to investigate reservoir volume and identify reservoir boundaries. The record of surface oil flow rate and downhole pressure for the 130-hour test tells most of the story—follow the annotations in sequence. The surface oil flow rate data points are derived from measuring outflows from the surface separators. The data are stored in the COMPUTEST wellsite computer system. The lines represent averaged values for the duration of a flow period. The green pressure curve represents data stored in downhole memory throughout the test and then read out after retrieving the drillstring. In fact, four pressure gauges were used in this downhole memory mode: one strain gauge, two quartz gauges and one SPG Sapphire Pressure Gauge. The red curve represents pressure data obtained with the surface readout device hooked into the drillstem tool and read in real time at the surface. Over 75,000 pressure data points make up the curves in the plot. Now go to 1 .

In five days, with only one pipe trip into the hole, this properly designed and executed well test has brought the exploration well to maximum potential, determined formation permeability, provided representative samples for PVT analysis, investigated far-reservoir boundaries, and set in place a completion strategy for development wells of the field.

12 A long, 24-hour flow period and a buildup lasting almost two days then followed. This wasto confirm the effectiveness of theacid job and to investigate reservoir volume and boundaries.

15 The second buildup was interpretedusing data measured in downhole memory mode and thus covering the buildup to its very end. The data were analyzed off-site, after the drillstring was pulled. This match (lines) is based on a no-flow boundary and a constant-pressure boundary (possibly the water table). Another good match to the data was obtained by assuming a composite radial model. Only the reservoir engineer in cooperation with geologist and geophysicist can decide which is more appropriate.

16 A fluid sampler is run in on wireline, through the fullbore drillstem test tool to positionopposite the producing formations. The well is allowed to flow gently to preserve bottomhole pressure above bubblepoint while sampling takes place.

17 The sampler is then pulled and a second production logging profile is madewith the well flowing at a higher rate. Comparing pre- and post-acid flow profiles, the acid job can be seen to have successfully stimulated the limestone.

∆p a

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Gilles Bourdarot Alain DesplanquesElf CongoPointe-Noire, Congo Mike Pearson Montrouge, France

Textbook Well Test from the Congo

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Pre-acid buildup

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33

on the derivative response. The signs arevaried (next page). A partially penetratedformation produces a linear trend on thederivative curve with a slope of –1/2. In wellswhere the formation is strongly layered ornaturally fractured, the derivative tends todip before it rises to the radial-flow plateau.If wellbore storage is not too dominating, thetransient can be analyzed to pinpoint themost likely explanation.

The last regime on the log-log plot occurswhen the pressure transient has travelled farfrom the well and encounters the reservoiror drainage-area limits. Testing theoristshave worked out the transient response to acatalog of boundary geometries (right). Inmost cases, the transient responses alone donot offer enough differentiation to enablethe interpreter to definitively establish theboundary type. The choice of the type aswell as the orientation of the boundarygeometry must be guided by geologic, seis-mic and log data.

There are three categories: no-flowboundary, constant pressure boundary and

the special case in which the test is longenough to reach all the no-flow boundaries,thus forming a closed system. Examples ofno-flow boundaries include sealingfaults—perhaps several of them—pinchouts,and channels. Because no-flow boundariesreflect the transient back toward the well,they cause ∆p to rise at higher than its nor-mal radial-flow rate, so the derivative curvejumps to a higher level. A sealing faultcauses the plateau value to double. Withtwo intersecting sealing faults, the jump iscorrespondingly higher. If a fault is partiallysealing, the derivative curve starts to jumpbut then falls back to its radial-flow value.

Constant-pressure boundaries, like a gascap or aquifer, allow the pressure transientto flatten out at the boundary pressure, sothe derivative takes a nosedive, which isinstantly recognizable. In a closed system,pressure is completely contained within thereservoir. How this affects the ∆p andderivative curves depends on whether thetransient is a drawdown or buildup. Indrawdown, both curves track a line of unitslope, again an easily recognizable effect. Inbuildup, the derivative curve starts movingtoward the line of unit slope but takes anosedive before reaching it, somewhat simi-lar to the constant-pressure boundary case.

These reservoir models are simpler thannature generally allows—in reality, a mix-ture of responses should be expected.Thanks to the superposition principle, how-ever, responses may be combined to pro-duce a realistic transient response for eventhe most complex situation. Simulating data,though, is the easier forward task. More dif-

34 Oilfield Review

Surface shut-in

10-2 10-1 100 101 102

10-2

10-3

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100

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Downhole shut-in

nReduction ofwellbore storagewith downholeshut-in. The log-logplot compares twowell tests, one shutin at the surface,the other shut indownhole. In thesurface shut-in test,wellbore storagemasks the radial-flow plateau forover 100 hours (4 days) (squaredata points). Theplateau emergesclearly in the down-hole shut-in dataafter just one hour(triangular datapoints).(From Joseph et al,reference 6.)

Partially Sealing Fault

Intersecting Impermeable Boundaries

Parallel Impermeable Boundaries

Truncated Channel

Pinchout

Impermeable Boundary

Well

Well

Well

Well

Well

Well

nA representative selection of no-flowboundaries studied by well-test theorists.Any of these may appear in the late-timeportion of a transient’s diagnostic log-logplot. The associated parameters definingthe boundary may then be estimated byregression analysis.

Partially Penetrating Well

Horner time Function of timeTimeHomogeneousReservoir

Dual-Porosity

Finite ConductivityVertical Fracture

Sealing Fault

Constant Pressure Boundary

Linear Channel

Infinite ConductivityVertical Fracture

Horner

∆p

Specialized

∆p

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∆p, D

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Flow Regimes

Wellbore storage coefficient

Matrix permeability × (channel width)2

∆t

Wellbore storageRadial flow

Other

(Fracture half-length)2 × matrix permeability

Fracture permeability × fracture width

∆t

∆t

∆t4

nResponse of log-log plot (left column) toseveral common reservoir systems, show-ing different flow regimes (see legend).The log-log plot is used by analysts todiagnose the flow regimes present in thetransient. Once regimes are identified, theHorner plot (semi-logarithmic) and otherspecialized plots (linear) are used to eval-uate parameters characterizing the system.

35

ficult for the analyst is the inverse procedureof finding the best model to match actualtest data (below).6

For the traditional test comprising twoflow periods and two buildups, transientanalysis focuses on the second buildup. Thefirst step is to identify the various regimes onthe log-log ∆p and derivative-curve plotsand then choose the most likely model foreach. Estimation of model parameters isthen made using specialized plots that allowa focused analysis of each flow regime (pre-vious page). For example, wellbore storagein the early data is determined from theslope of the straight-line portion of a linear∆p versus ∆t plot. Confirmation and charac-terization of a vertical, high-conductivityfracture, recognized by a half-slope deriva-tive trend on the log-log plot, come from aplot of ∆p versus . The radial-flowplateau is best analyzed using the general-ized Horner plot. And so on.

Using a workstation, the reservoir engi-neer interacts with a computer program,such as STAR Schlumberger Transient Anal-ysis and Report and ZODIAC ZonedDynamic Interpretation Analysis and Com-putation programs,7 to build a comprehen-sive model using all the parameters foundfor the various flow regimes, predict whatthe entire transient should look like, andcompare the results with the data. In thisforward modeling process, the interpretertweaks parameters, either manually or auto-matically using a nonlinear regressionscheme, and perhaps alters the choice ofmodel for one of the regimes to obtain thebest possible fit. There may be several com-binations of models that match the dataequally well. In this case, other data mustbe sought to decide which model is themost appropriate (next page).

The final interpretation step, called historymatching or verification, uses the model

established in the second buildup to predictpressure response throughout all four peri-ods of the test and confirms that the modelsatisfactorily accounts for all data. This mayresult in more parameter adjustmentbecause every period must now be matchedsimultaneously, even though the secondflow period is planned intentionally long tominimize the influence of previous periods.

In some cases, interference from earlierwell manipulations may obscure keyregimes of the transient being analyzed.Interpreters then resort to a process calleddesuperposition that attempts to isolate thetransient from earlier ones and in particularreform the given transient’s data to mimichow the reservoir would have reacted if theflow rate change had been an isolated, per-fect step.8

Designing well tests involves many of thesame steps the interpreter uses. This isbecause once a test has been proposed,both the pressure data and the data’s inter-pretation can be simulated to show that thetest as designed meets its goals—design sim-ulation requires estimates of formation andfluid parameters from nearby wells or thewell in question. By predicting the likelyshape of the log-log ∆p and derivativecurves, the engineer can demonstrate thefeasibility of detecting and characterizingthe anticipated reservoir features. For exam-ple, design simulation ensures that wellborestorage does not smother the feature beingsought and guarantees a test that is longenough to view suspected reservoir bound-aries. Another important feature of simula-tion is determining the accuracy and preci-sion required of the pressure gauges.

The design phase not only maps out themechanics of a test, but also ensures that,once underway objectives are met. Forexample, the progress of the planned tran-sient can be followed at the wellsite andcompared with that forecast during thedesign. To avoid the costly mistake of rig-ging down before the transient indicates adesired feature, wellsite validation of dataduring the test remains a must. This is bestaccomplished with surface readout ofdownhole gauges and enough computingpower at the surface to produce appropriateplots, notably the log-log diagnostic plot. Ifthe reservoir response is quite different fromthat assumed in the design, wellsite diagno-sis permits an instant correction of the job,perhaps a lengthening of the transient, to

36 Oilfield Review

Results

Parameter estimation

Specialized plots

Model diagnosis

Preprocessing

Raw data

Openhole logsPVT data Production logs

History matching

nThe order of businessin pressure transientanalysis.

∆t

nFinding the best model to fit the data. In this case, four scenar-ios fit quite well, but the dual-permeability model fits best. Dualpermeability means a two-layered formation with a differentpermeability in each layer.

April 1992

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Sealing Fault

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10310-1 100 101 102

ensure optimum use for the data. In certaincases, real-time readout is not feasible anddownhole recording must be used. Datavalidation can still be performed onsite rightafter retrieving the gauges.

Integral to well test design is selection ofhardware, which involves many options. Tominimize wellbore storage, should the wellbe shut in downhole rather than at surface?In a low producer, will the act of shutting inactually kill the well? How sensitive must thepressure gauges be? To some extent, thesequestions are decided by the operator’s stan-dard practices, the current status of the hole,the configuration of the downhole hardwareand, not least, safety considerations.

The options have expanded in recentyears. While drillstem test (DST) equipmenthas always guaranteed downhole shut-in innew wells, downhole shut-in devices forcompleted wells did not become commer-cial until the early 1980s. Pressure gaugeshave evolved from crude mechanicaldevices to quickly reacting, highly accuratequartz gauges. Perhaps the most unexpectedinnovation is a downhole flow measurement.

Traditional well testing theory dispensedwith a flow measurement because itassumed constant wellbore storage,enabling flow to be estimated from earlypressure data. But reality is less predictable.Wellbore storage often varies as the fluids inthe wellbore change during the test, and adownhole flow measurement in fact offers avaluable complement to conventional pres-sure data.

Downhole flow measurements are cur-rently performed using production logging

6. Joseph J, Ehlig-Economides CA and Kuchuk F: “TheRole of Downhole Flow and Pressure Measurementsin Reservoir Testing,” paper SPE 18379, presented atthe SPE European Petroleum Conference, London,England, October 16-19, 1988.Ehlig-Economides CA, Joseph JA, Ambrose RW Jr andNorwood C: “A Modern Approach to Reservoir Test-ing,” Journal of Petroleum Technology 42 (December1990): 1554-1563.

7. The newer ZODIAC program includes all the featuresof the older STAR program.

8. Ehlig-Economides CA, Ambrose RW and Joseph JA:“Pressure Desuperposition Technique for ImprovedLate-Time Transient Diagnosis,” paper SPE 20550,presented at the 65th SPE Annual Technical Confer-ence and Exhibition, New Orleans, Louisiana, USA,September 23-26, 1990.

37

nThe convolution integral that converts pressure response to a unit step change in flow,p(t), and actual measured flow rate, q(t), into measured pressure response, P(t). Convo-lution revolutionizes transient analysis when downhole flow measurements are avail-able, for example as measured by production logging in a flowing test. The mathemat-ical manipulation virtually wipes out wellbore storage, leaving later portions of thetransient clearly visible.

nAn exampleshowing wellborestorage virtuallyeliminated usingthe convolutionderivative. Thetransient was intro-duced by chang-ing the well’s pro-duction rate anddownhole flow wasmeasured usingproduction logging.

38

∆p a

nd D

eriv

ativ

e, p

si

10-5

Time, hr10-4 10-3 10-2 10-1 100 101

10-1

100

101

102

103

Pressure change

Pressure derivative

Convolution derivative

P(t) = q(τ) p(t-τ) dτ

Model

Flow rate

Pressure

Time

Time

∆p a

nd D

eriv

ativ

e

0

T

tools and therefore not deployable whendownhole shut-in is planned. The mostcommon uses are to measure transientscaused by either shutting in or altering theflow rate at the surface—the tool, enteredinto the well through a conventional riserand lubricator, is suspended just above theproducing zone. A drawback of the currenttechnology is the threshold and resolutionof the spinner in the logging tool that mea-sures flow. Well testing experts dream abouta robust flow measurement incorporatedinto the DST tool, enabling continuous flowmeasurements in newly drilled wells.

If flow measurements are at hand, howdoes that change testing analysis? The nec-essary theoretical ground was broken in the1980s. The underlying principle is, onceagain, superposition.9 Suppose the pressureresponse to a unit step change in flow isp(t – t0), where t0 is when the step changeoccurs. Then the pressure response, P(t), toa gradual change in downhole flow rate,q(t), may be computed by approximatingthe gradual change with a series of stairsteps, then considering each step as provid-ing a minitransient, and finally through thesuperposition principle summing all theminitransients (left). As the steps are madesmaller, this sum becomes the convolutionintegral:

During a test, downhole pressure gaugesmeasure P(t) and a flowmeter measures q(t).But p(t) is what the interpreter wants. Get-ting at it requires the reverse process ofdeconvolution, which unfortunately is arather unstable numerical procedure. Morecommonly, interpreters favor a procedurecalled logarithmic convolution that convertsthe two measurements more easily intosomething that fits existing analytical tech-niques (left).

Logarithmic convolution is a mathemati-cal trick in which a form for p(t) isassumed—usually the response for infinite-acting radial flow—that simplifies the aboveconvolution integral to a simpler expressioninvolving a rate-normalized pressureP(t)/q(t), written J(t), and a new time-scalecalled sandface rate convolution time, tsfrc.J(t ) and its derivative with respect to tsfrcoffer the same diagnostic power as the con-ventional well testing analysis describedearlier with the advantage that most of thewellbore storage is removed.

P (t ) = 0

Tq (τ) p (t–τ ) dτ .

Oilfield Review

9. Meunier D, Wittmann MJ and Stewart G: “Interpreta-tion of Pressure Buildup Test Using In-Situ Measure-ment of Afterflow,” Journal of Petroleum Technology37 (January 1985): 143-152.

10. Kucuk F, Karakas M and Ayestaran L: “Well TestAnalysis of Commingled Zones Without Crossflow,”paper SPE 13081, presented at the 59th SPE AnnualTechnical Conference and Exhibition, HoustonTexas, USA, September 16-19, 1984.Ayestaran L, Ehlig-Economides C, Shah P, Kuchuk F,Nicolson B and Wittmann M: “Layered ReservoirTesting,” The Technical Review 35, no. 4 (October1987): 4-11.

Pressure

Flow

A B C

A B C

Surface flow rate

Downhole

A

B

C

Time

nSequence of downhole pressure and flow transients measured using a production log-ging tool in a layered reservoir test. A separate transient is measured with the tool posi-tioned at the top of each zone. Analyzing the transients yields individual zone perme-ability and skin values.

There are several advantages to testing awell with downhole pressure and flow mea-surements under drawdown—and one dis-advantage. The disadvantage is that reservoirshut-in pressure is not measured. The advan-tages are: •in producing wells, little production is lost

since the well is never shut-in.•in poor producers, production is not killed

as may occur during a shut in.•in layered reservoirs, testing under draw-

down reduces the possibility of crossflowbetween producing layers, while this caneasily occur in a buildup test complicatingthe interpretation.

The technique’s most popular application inlayered reservoirs, though, is in analyzingindividual layer kh and skin values.10

This involves measuring a series of tran-sients created by changing the productionrate, one for each layer with the productionlogging tool situated at the top of the layer(right). The amount of data acquired is hugeand can be analyzed in several ways withvarying degrees of sophistication. The key,however, is to first analyze the transientmeasured with the tool situated just abovethe bottom layer, yielding that layer’s reser-voir properties. Then, a second transient ismeasured with the tool situated above thenext layer, revealing reservoir properties ofthe new layer and bottom layer combined.Since reservoir properties for the bottomlayer are already estimated, the transientcan be analyzed to reveal just the newlayer’s properties. The process continues upthe well.

Layered reservoir testing (LRT) was origi-nally conceived to investigate productionwells. Recently in offshore Congo, AGIPused the technique to evaluate a layeredreservoir encountered by an explorationwell. Conventional testing of individual payzones in an exploration well would nor-mally call for a separate DST-perforation runfor each zone. But using layered reservoirtesting, AGIP obtained reliable kh, skin andproductivity index values for individualzones with only one trip in the hole, at aconsiderable cost savings (see “ExplorationLayered Reservoir Testing in the Congo,“next page).

The drawback of using an LRT in theexploration setting is that production fromdifferent zones commingles, ruling out rep-resentative sampling from different payzones. Fortunately, a recent technological

April 1992

innovation provides a solution. Samples ofextraordinary reliability may now beobtained from any number of zones usingthe new wireline-conveyed MDT ModularFormation Dynamics Tester, but this has tobe planned in advance because the sam-pling takes place in open hole (see “TheMDT tool: A Wireline Testing Break-through,” page 58).

In addition to convolution and layeredreservoir testing, there are other advantagesto supplementing conventional pressuredata with production logging measure-ments. A flow profile run during stabilizedproduction or shut-in can pinpoint whereproduction is coming from and provideinvaluable data on crossflow betweenzones. The information may directly influ-ence testing interpretation. For example, if azone is producing only from its upper part,a portion of the transient will react as if thewell were only partially completed. Thediagnosis must be adjusted accordingly. Thefluid density measurement in productionlogging also plays a role by indicatingwhether gas is coming out of solution, giv-ing a warning that a test may be occurringat below bubblepoint conditions.

Perhaps the most valuable contribution ofdownhole flow measurements is in testing

(continued on page 45)

39

40

Exploration Layered Reservoir Testing in the Congo

Luigi Piero

AGIP CongoPointe-Noire, Congo

Augustine Alagoa

Pointe-Noire, Congo

292

300

308

RFT Pressure

100 20 30 40

Pre

ssur

e po

tent

ial,

bar

Bottomhole flow rate, m3/hr

Upper layerLower layer

Composite

nReservoir geometry near the two layersinvestigated by a layered reservoir test inAGIP’s Congo exploration well.

nSelective inflow performance plot for thetwo reservoir layers, showing the lowerlayer to be easily the more productiveand the reservoir pressure corrected to adepth datum of 2735 m to be the same inboth layers—315 bars.

AGIP’s innovative use of layered reservoir testing

(LRT) in an exploration well occurred offshore

Congo. The goal of the test was to evaluate two

producing layers only a few meters apart with

only one trip into the hole, a much less costly

undertaking than the usual two trips. The LRT

technique was originally developed for testing

production wells, in which several layers produce

commingled—in this case, LRT is a must to eval-

uate each layer’s dynamic properties. Here, AGIP

extended the method to the exploration environ-

ment, where openhole data suggest several pay

zones quite close to each other.

The discovered field is an elongated structure

bounded by two faults forming a V shape (left).

The well penetrates several reservoirs. Five tests

were performed in the well, two using the LRT

technique. Each LRT test looked at two distinct

layers. This example presents results from the

shallower pair.

The bottom layer is a 17-m [56-ft] thick sand-

stone/limestone mix of 26% porosity, while the

top layer is a 7-m [23-ft] thick limestone of 20%

porosity. The layers are separated by about 4 m

[13 ft] of silts. The well was completed with 7-in.

casing and perforated underbalanced with 4 1/2-

in. tubing-conveyed perforating (TCP) guns to

enhance cleanup and control perforation damage.

The test began with a flow period to clean up

the well, then a shut-in during which a production

logging profile was recorded. The well was then

opened on a 3/8-in. choke, and transient pressure

and flow measurements were recorded with the

production logging tool positioned above the top

zone (above). After flow stabilized, a second pro-

duction logging profile showed that 95% of pro-

duction came from 10 m [33 ft] of the bottom

layer and just 5% from the top layer. The tool was

then moved to the top of the bottom zone and a

new transient measured after the choke was

increased to 1/2 in. The choke was finally

increased to 3/4 in. and a final transient mea-

sured with the tool back above the top zone.

First, the flow profiles were analyzed to obtain

the inflow performance of and reservoir pressure

in each layer. Plots of pressure normalized to a

Oilfield Review

13.5

0.0

Spi

nner

, rp

s

0

272

316

Pre

ssur

e,

bar

3 6 9 12 15

Time, hr

nRaw downhole pressure and flow ratetransients measured with a productionlogging tool during the layered reservoirtest.

Nor

mal

ized

∆p

and

Der

ivat

ive,

bar

/m3 /

hr 101

100

10-1

10-3 10-210-4 10-1 100 101

Elapsed time, hr

∆pDerivativeConvolution derivativeModel

nLog-log plots of rate-normalized pressure, derivative and convolution derivative forthe second transient, with the best-fit model response superimposed. Arrows on theconvolution-derivative data mark the plateau corresponding to the radial flow regime.

LRT Results

Interpretation

Flow Profile

Production contribution, %

Productivity Index, m3/day/bar

Transient

Permeability, md

Skin

Top Layer

5

1.4

7

-1

Bottom Layer

95

30

105

-3.5

datum versus sandface flow rate confirmed that

the bottom layer was easily the most productive

(above). But more importantly, the plots showed

the two layers to be in equilibrium. Both had a

normalized pressure of 315 bars, close to the

RFT Repeat Formation Tester values obtained

during openhole logging. The similar values pre-

clude crossflow during shut-in, confirmed by the

shut-in flow profile.

Next, data from the first two transients were

analyzed—the third transient was considered

invalid after it was noticed that bottomhole flow-

ing pressure had dropped below estimated bub-

blepoint pressure. Bubblepoint and other fluid

parameters such as viscosity had been measured

at the wellsite on samples using the FPE Fluid

Properties Estimation device. Fortunately, the

first two transients provided an adequate inter-

pretation. We will follow interpretation of the

second transient, obtained with the production

logging tool situated above the bottom layer, as

an example (right).

The first step is model diagnosis. The convolu-

tion-derivative plot reveals the radial-flow

plateau. Before and after radial flow, the trends

are less well-defined making it difficult to diag-

nose the nature of the formation—homogeneous

or dual porosity—and reservoir limits.

Analysis of the radial-flow regime gave initial

values for the bottom layer’s permeability and

skin. Then, several formation models and reser-

voir configurations were considered to match the

flow and pressure data of the entire transient. A

good match was obtained (see solid lines on plot)

assuming a dual-porosity model, suggested by

log and core data, and a flow barrier located

April 1992

about 70 m [230 ft] from the wellbore. This tied

in with results from a deeper test that placed the

well between two flow barriers spaced about 110

m [360 ft] apart. That meant the well was about

55 m [180 ft] from each barrier, confirming that a

V-shaped fault structure bounded the reservoir.

When both transients were analyzed, skin val-

ues for the two layers were found to be negative,

more so for the bottom layer (see “LRT Results,”

bottom). This is expected as most of the produc-

tion comes from the bottom layer—it probably

got the best chance of an effective cleanup during

underbalanced perforating. The less favorable

skin value in the upper layer suggests production

here would benefit from stimulation.

AGIP’s experience proves the validity of the

LRT technique in an exploration setting. The

technique is usually difficult to apply when, as in

this case, one zone monopolizes production. Yet

the results seem reliable and even extend to clar-

ifying the reservoir boundaries. The cost savings

from reducing the rig time needed for the test are

considerable. They accrue from only needing one

trip in the hole, the elimination of a bridge plug

run that would have been required if the two

zones had been tested conventionally, and finally

only needing one cleanup period rather than two.

These cost savings would increase as the number

of zones increases.

41

Horizontal Well Testing in the Gulf of Guinea

nComposite of production logging passes along a horizontal producing well in the Gulf of Guinea, West Africa with well trajectory.Passes during shut-in reveal possible crossflow and settling of water and oil in troughs and peaks of the well geometry. Passes whileproducing indicate no flow coming from the initial section of the horizontal trajectory and a fluid density equivalent to a 20% waterholdup. In all passes, pressure correlates with true vertical depth.

Simon Domzalski

Port-Gentil, GabonJean-Pierre Yver

Montrouge, France

Fluid Velocity Profile

Pro

duc

tio

n Lo

gs

Flo

win

g

Pressure

Fluid Density

Pro

duc

tio

n Lo

gs

Shu

t-in

Fluid Velocity Profile

Pressure

Fluid Density

Wel

l Ske

tch

Op

enho

le L

og

s

0.10

1000

0.10

1000

45.01.95

2.95 -15

-0.25

0.25

RFT

1084

1091

Caliper

Gamma Ray

TVD

ohm-mIldIlm

∆ρ ∅ N %ρB

m

1.2

0.2

160

-40

200

01650

1637.5

1650

1637.5

m/min

13.5 in.7.5 in.

g/cm3

m/min

psi

psi

g/cm31.2

0.2

42 Oilfield Review

43

A recent test in a horizontal well in the Gulf of

Guinea, West Africa illustrates the key role pro-

duction logging can play in horizontal transient

testing. The well taps separate units of a sand-

stone oil reservoir with a 560-m [1840-ft] hori-

zontal trajectory that travels about 23 m [75 ft]

below the gas/oil contact and 14 m [46 ft] above

the water/oil contact. At 860-m [2820-ft] mea-

sured depth, the well crosses a fault.

The well was completed with a prepacked

screen and slotted liner. For testing, shut-in was

at surface and the PLT Production Logging Tool

measuring flow, pressure and fluid density was

pushed along the horizontal section with coiled

tubing. Density was measured with a nuclear

fluid densitometer, because the conventional

pressure difference method employed by a gradio-

manometer is inoperative in the horizontal envi-

ronment. An obstruction prevented logging for the

last 200 m [660 ft] of the horizontal trajectory.

Day one of the two-day test began with produc-

tion logging passes up and down the well while

the well was flowing about 9900 barrels of oil per

day (BOPD). The well was then shut in and a brief

30-minute buildup test made with the tool posi-

tioned at the beginning of the horizontal section.

A second series of up and down passes were then

made with the well still shut-in (previous page).

With the well flowing, the fluid velocity profile

shows 60% of production coming from below the

obstruction at 980 m, 40% coming from between

the obstruction and 860 m, and practically noth-

ing coming from the initial section of the horizon-

tal section. The fluid density profiles indicate a

value intermediate between the water density of

nDiagnostic plotfor the two buildupscombined and spe-cialized Hornerplot for the secondbuildup test. Thediagnostic plotincludes pressurechange, the pres-sure changederivative and theconvolution deriva-tive (green opentriangles and dia-monds only shownat early time whendifferent fromderivative).

Characteristic ofhorizontal welltests, two plateauscan be picked outthat on the special-ized plots give hor-izontal and verticalpermeability val-ues and skin. Theconvolution deriva-tive that eliminateswellbore storageproves most reli-able for establish-ing the first plateau.

passes is at 860 m, where a shift in the oil/water

interface may indicate water entry from the fault

known to intersect the well at that depth. Under

shut-in and flowing conditions, pressure can be

seen to correlate precisely with true vertical depth.

Day two of the test comprised a buildup lasting

three hours, with the production logging tool

positioned again at the beginning of the horizon-

tal section and the well having previously been

producing through a 156/64-in. choke at about

10,100 BOPD.

A diagnostic plot combining data from both

buildups reveals the characteristic double

plateau of horizontal wells (above). The first

Elapsed time, hr10-4 10-3 10-2 10-1 100 101

10-5

10-4

10-3

10-2

Pre

ssur

e an

d D

eriv

ativ

e, p

si

Log-Log Plot

Horner Plot1675

1665

1655

1645

163520,000 30,000 40,000 50,000 60,000 70,000

Pre

ssur

e, p

si

Generalized Horner time

Late-timeradial

Early-timeradial

1.07 g/cm3 and the oil density of 0.6 gm/cm3, giv-

ing a water holdup of about 20%. The slight

increase in fluid density from 930 to 910 m prob-

ably reflects an increase in holdup caused by

water accumulation in this uphill section of the

trajectory. The effect is later masked by an

increase in production.

During shut-in, the fluid velocity profile indicates

some crossflow—formation pressure measure-

ments made just after drilling indicated a 12-psi

spread along the horizontal trajectory, a signifi-

cant amount for a high permeability reservoir.

The up and down fluid density passes indicate

water settling in the trajectory troughs and oil fill-

ing the peaks. The only movement between the

April 1992

44 Oilfield Review

plateau corresponds to early-time radial flow in

the vertical plane, while the later plateau corre-

sponds to radial flow in the horizontal plane.

With a Horner plot, horizontal and vertical perme-

abilities were estimated. Although the results

were of the same order of magnitude as those

obtained from previous tests conducted in vertical

wells and cores from these wells, the assumed

homogeneous formation model failed to match

the test data at later time—the derivative data

show a flattening trend while the model shows a

decreasing trend (above).

This discrepancy could have three causes:

First, it may not be correct to assume that the

entire horizontal length past the restriction is pro-

ducing. Second, the fit should perhaps be made

with a layered rather than homogeneous model.

Third, there may have been crossflow during the

second buildup, just as was observed in the first

buildup. The only way to eliminate this factor is

to conduct a transient test under drawdown.

This test, like most other horizontal well tests,

would have been impossible to analyze without

the production logging profiles, particularly the

flow profiles. These clearly indicated that the first

segment of the producing section did not pro-

duce, essential information for the regression

analysis; the downhole flow rates made possible

a convolution derivative plot that gave much

firmer indication of the early-time radial flow than

the normal derivative; and the shut-in profiles

pointed to crossflow, a caution to the wise analyst.

Time, hr

Pre

ssur

e an

d D

eriv

ativ

e, p

si

100

101

102

10-4 10-3 10-2 10-1 100 101

nA regression analysis best fit (solid lines) to the buildup dataassuming a homogeneous formation model for the reservoir. Thefit is reasonable except toward the end of the test. Possible rea-sons for this discrepancy include crossflow after shut-in, a wrongassumption about the length of horizontal trajectory actually pro-ducing, and the formation being layered rather than homogeneous.

11. Clark G, Shah P, Deruyck B, Gupta DK and SharmaSK: “Horizontal Well Testing in India,” OilfieldReview 2, no. 3 (July 1990): 64-67.Shah PC, Gupta DK, Singh L and Deruyck BG: “AField Application of the Methodology for Interpreta-tion of Horizontal Well Transient Tests,” paper SPE20611, presented at the 65th SPE Annual TechnicalConference and Exhibition, New Orleans, Louisiana,USA, September 23-26, 1990.

12. Ahmed U and Badry R: “Production Logging as an

zy

x

nPhases in a horizontal well transient test. After wellbore storage has disappeared,flow is first radial toward the well in the vertical y-z plane, then linear in the y-z plane,finally radial in the x-y plane. The first and third regimes produce plateaus on the log-log diagnostic plot and can be analyzed to provide vertical and horizontal permeability.

horizontal wells.11 Horizontal wells posetwo special problems for the reservoir engi-neer. The first is the unavoidably large well-bore storage effect. Horizontal sections mayextend for thousands of feet and cannot beisolated from the transient. The second isthe more complex nature of the transient.Once wellbore storage is stabilized, threeregimes possibly replace the radial-flowregime of a conventional test (right).

First is radial flow in a vertical planetoward the well, indicated by a plateau onthe derivative curve on the log-logplot—this regime is termed early-time,pseudo-radial because permeabilityanisotropy (vertical to horizontal) actuallycauses an elliptical flow pattern. The secondregime begins when the transient reachesthe upper and lower boundaries of the pro-ducing zone and flow becomes lineartoward the well within a horizontal plane.The derivative curve traces a line of slope1/2. The third regime occurs as the transientmoves so far from the well that flowbecomes radial again, but this time in thehorizontal plane. The derivative curveenters a second plateau.

Although this makes diagnosis more diffi-cult, it also offers benefits. As in conven-tional testing, the first plateau gives kh andskin, but k is now the geometric average ofpermeability in the vertical plane perpen-dicular to the horizontal wellbore trajec-tory, , the wellbore trajectory beingconsidered parallel to the x-axis. The inter-mediate linear flow period gives horizontalpermeability along the y axis, ky, and thesecond plateau gives the average perme-ability in the horizontal plane, . Intheory, the three regimes together can pro-vide a breakdown of permeability into itsthree components.

The key to a successful interpretation isrecognizing the first plateau, not onlybecause this alone gives kz , but alsobecause it is the only regime that candirectly provide skin. However, it is theregime most likely to get swamped by thelarge wellbore storage occurring in a hori-zontal well. The key to this dilemma iseither downhole shut-in, or downhole flowmeasurements and logarithmic convolution.

Because of the length of a horizontalwell’s producing zone, supplementing test

ky kz

kx ky

Integral Part of Horizontal Well Transient PressureTest,” paper SPE 20980, presented at Europec 90,The Hague, The Netherlands, October 22-24, 1990.

April 1992

data with flow profiles measured duringproduction logging is even more crucial forpinpointing production and recognizingcrossflow (see “Horizontal Well Testing inthe Gulf of Guinea” page 42).12 Crossflow iscommon in horizontal wells as in verticalwells, particularly during a buildup test, andmay seriously jeopardize interpretation.Drawdown tests are therefore recommendedas an insurance policy, particularly for newwells in developed fields where differentialdepletion may exacerbate crossflow.

The underpinnings of horizontal well test-ing theory are developing rapidly. Interfer-ence testing of horizontal wells is beingworked out, as is the influence on the hori-zontal well-test response of the same rangeof reservoir heterogeneities and boundariesthat are now well understood for conven-tional testing.

The future of testing is assured, of course.What will accelerate its use and impact isbetter integration with other reservoir data,improved downhole pressure and flow sen-sors, further development of transient theoryand a continued evolution of the interactivecomputer software that now aids interpreters.

—HE

45