Reservoir Permeabilities From Wireline Formation Testers

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SPE 164924

Reservoir Permeability from Wireline Formation TestersStefano Cantini, Schlumberger, Davide Baldini, Enzo Beretta, Daniele Loi, Stefano Mazzoni, ENI E&P

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in London, United Kingdom, 10–13 June 2013.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

AbstractPermeability is an essential parameter in order to properly define well and reservoir performance. Permeability is alsorelevant in overall reservoir management and development, including reservoir simulation, gravity drainage, floodperformance, assessment of gas or water coning.Attempts to derive reservoir permeability with wireline formation testers started in the 70s, calculating drawdown mobilityfrom pretests taken with a single probe. However, despite drawdown mobility provides valuable information about reservoirbehavior, it is not comparable to reservoir permeability traditionally measured with Drill Stem Tests (DST). This is due to itslimited depth of investigation, the upscaling difficulties and the fact that probe type tools do not develop a complete radialflow regime. In the 90s the introduction of the latest generation of wireline formation testers, equipped with straddle packermodules able to develop radial flow with radius of investigation in the order of tens of meters, enabled measurement ofpermeability at reservoir scale. These tests, called miniDST or IPTT (Interval Pressure Transient Testing), represent in somecases a valid alternative to conventional DST tests, especially for the environmental, safety and the economic aspects.MiniDST/IPTT method is here described, from the design phase, very important in order to obtain a reliable test, to finalinterpretation, with a critical review of the method applicability, its limitations and comparison versus traditional DST.Latest developments in terms of hardware and interpretation techniques are included.Case histories are also provided in order to demonstrate the IPTT application, its integration with the other permeabilitysources and the reservoir model, including comparison between simulated reservoir deliverability and measured well testrates.

Overview of Permeability Measurement MethodsLogging, core measurements, and well testing methods are available to measure permeability in new wells. Logging methodsinclude:

- Nuclear Magnetic Resonance (NMR), providing a continuous pore size and porosity profile from whichpermeability is derived. The most used equation is from Coates-Timur (Coates et al., 1973):

(1)where Φ is porosity. NMR permeability can be calibrated by core study, providing a , b, c values (if core study isnot available, 2 is used for a and 4 for b, while c depends on type of rock).

- Empirical correlations of permeability vs porosity derived from nuclear and sonic logs or from Stoneley acousticwave. These are often weak correlations not reflecting real permeability distribution, especially in heterogeneousformations.

- Permeability at different scales measured by wireline formation testing, as described in detail in the followingchapters.

Often, permeabilities from logging, cores and well test methods are correlated without considering relevant factors, like scaleof the medium under investigation (refer to Fig. 1) and state of the rock. Without considering these factors, thepermeabilities determined from different sources can vary significantly, as well as the estimates of reservoir performance.

Core analysis has uncertainties related to the ability to reproduce reservoir conditions (stress in particular) and to the need ofusing native hydrocarbons for the flow tests. Log measurements, except IPTT tests, have very limited radius of investigation,thus influenced by the upscaling factor and by the filtrate in the invaded zone, but also have the benefit of being continuous



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measurements. Full scale DSTs with extended flow and shut in periods provide a representative but average permeability,valid only if single phase flow is maintained. Only taking in consideration all these factors appropriate comparisons andcorrelations among the various methods can be carried out.

On the operating aspect, relevant factors to consider for the methods of choice are: environment, safety, time (referred toacquisition and delivery of results) and cost. A full scale DST needs to flow hydrocarbons at surface, unless closed chambersor injection tests are carried out, with environmental and safety concerns. Time also matters; logs have advantage on thissince acquisition and results delivery are tipically in the order of days, while full scale DST is in the order of weeks and coresresults are often available after few months. Cost is often related to time, especially in appraisal and exploration environment.

Figure 1 – Relative scales of permeability sources

The History of Wireline Formation TestingWhen introduced in 1955 the first wireline formation tester tool was able to take one fluid sample and one formationpressure. The repeat formation tester, introduced in 1975, was able to acquire two fluid samples and unlimited formationfluid pressures. This feature became quickly a very effective method to understand reservoir fluid types through pressuregradients, defining fluid contacts if possible, and connectivity between wells based on same pressure regime. Apart thefeature of formation fluid pressure measurement, the wireline formation testing configuration did not substantially changeuntil the end of the 80s, with tools having a probe assembly and one or two sample chambers. Main limitations were thepossibility of testing only primary porosity formations with medium to good mobilities, and the high contamination ofsamples , since no clean up was possible prior to open sample chambers.Techniques to derive reservoir permeability with probe type tools were developed, analyzing the drawdown and subsequentbuildup during the formation fluid pressure measurement. However, despite drawdown mobility provides valuableinformation about reservoir behavior, it is not comparable to reservoir permeability traditionally measured with DST mainly



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due to its limited depth of investigation and the upscaling difficulties.At the beginning of the 90s, a modular formation tester tool type was introduced, representing a relevant breakthrough forthis type of technology. The modular configuration extended the range of application with respect to the previous singleprobe tools: a straddle packer module, able to isolate 1 m interval, allowed testing of fractured or low porosity formations,

while pump modules can be used to perform full cleanup prior to sampling. The clean up process is controlled in real timethrough fluid analysis modules, able to determine fluid type and composition in real time. A new generaton quartz gauge withquick stabilization was also integrated into the tool. The modular concept proved to be ideal for wireline formation testing:each module is designed to perform specific functions, thus the string can be configured depending on the acquisitionobjectives (Schlumberger, 2006).From the 90s wireline formation testing modules were enhanced in order to improve hardware (mechanical reliability as wellas capability of operating under extreme pressure and temperature conditions) and measurements. Today it is possible tocharacterize reservoir fluids in real time, with complete definition of hydrocarbon properties through downhole fluid analysis(Mullins, 2008), providing hydrocarbon typing and composition, GOR, density and viscosity at desired depths. Formationwater properties (salinity, density, ph) can also be measured in real time. Downhole samples are normally collected and theiranalysis results are later on integrated with downhole fluid analysis data.The possibility of performing a detailed fluid characterization in real time made the wireline formation testing an efficientmethod to assess reservoirs. In addition, the introduction of modular configuration with straddle packer modules enabled

measurement of permeability at reservoir scale, since able to develop radial flow with radius of investigation in the order oftens of meters. These tests, called miniDST or IPTT (Interval Pressure Transient Testing), represent in some cases a validalternative to conventional DST tests, especially for the environmental and the economic aspects (Helshahawi et al., 2008,Whittle et al., 2003).

Figure 2- Evolution of wireline formation testers

Formation Tester -1955

Repeat Formation Tester -1975

Modular Formation Tester -1990



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Permeability from Probe Type ToolsThe pretest of a single probe tool starts with withdrawal of a small amount of fluid, typically 5 to 20 cc, from the formationinto the pretest chamber of the tool. This initial phase, called drawdown, causes a reduction in pressure that mainly dependsfrom the permeability of tested zone, the viscosity of the fluid in the formation surrounding the probe, the rate of fluid

withdrawal. Then, if the tested point has enough permeability, the pressure builds up to the formation fluid pressure value(Fig. 3). Despite the drawn fluid is filtrate from the invaded zone, the buildup is representative of the pressure of mobilephase into the reservoir, as the buildup radius of investigation is enough to bypass the invaded zone.A quality control is performed on the pressures, excluding dry, tight and supercharged points; if possible, pressure gradientsand eventual fluid contacts are then determined using representative points.Further information regarding permeability can be extracted from the representative points, with analysis of drawdown andbuildup. The pretest analysis to derive permeability was first introduced in 1962 (Moran) and later developed with theintroduction of the Repeat Formation Tester in the 70s (Stewart et al. 1979, Schlumberger, 1981):

The pressure drawdown analysis uses a spherical flow equation:

∆

(2)

where k d / µ is spherical drawdown mobility in mD/cpq is total flow rate in cc/sec∆ P is the pressure drawdown in psiC is a constant which takes into account probe type and the flowregime distortion caused by the wellbore

The equation 2 was recently fine tuned using the entire drawdown and buildup history to integrate the area under the last readbuild up pressure and considering the effective drawdown volume only from the moment the flowline is decompressingbelow formation pressure.The range of application of equation (2) is typically between 0.1 and 100 mD/cp. Below 0.1 mD/cp pressures are normallysupercharged and thus correct delta pressure cannot be determined. Also, the equation is based on steady-state drawdownconditions, difficult to achieve in low mobilities, unless pretest rate is set extremely slow. Above 100 mD/cp the pressuredrawdown is in general too small and too fast to be picked up correctly by the gauges, so mobilities above this value should

be intended qualitatively only.The drawdown phase has a very limited radius of investigation, in the order of few inches, thus interesting only the fluid onthe invaded zone, normally mud filtrate with a residual part of original fluid. Several methods are available to determineviscosity of the fluid into invaded zone (Hernandez et al., 2011) in order to derive permeability from equation (2). However,the following factors should be considered when comparing or integrating the drawdown permeability with other permabilitysources (cores, NMR logs):

- The mobility value incorporates skin caused by formation damage- Soft formations may become compacted in the area surrounding the probe, leading to a pessimistic mobility

evaluation- If filtrate is different from the virgin formation fluid (i.e. WBM filtrate into oil zone), the relative permeability

effects need to be taken in account- Formation testers have different internal volumes, referring to the hydraulic circuit between pretest chamber, gauges

and probe: a smaller internal volume will be more effective in transmitting the pressure drawdown to the formation,resulting in lower mobility with respect to a tool with larger internal volume

- The drawdown permeability is spherical, dominated by horizontal permeability

Buildup has in average bigger radius of investigation than drawdown, in the order of a meter, and it is carried out usingderivative analysis to determine kh (permeability thickness). Figure 3 shows the flowregime propagation into reservoir and itseffects on derivative; initial storage is related to compressibility effects into the tool volume between probe, gauges andpretest chamber. Then, spherical and radial flowregimes can be observed. However, buildup analysis is seldom used forpermeability purposes, since the flowregime is influenced by heterogeneities surrounding the probe, making difficult todetermine the real contributing thickness h. Also, probe type tools do not develop a real radial flow, since pressure transientlines propagate around the wellbore (Fig. 3 top left).

Kasap et al. (1996) introduced a technique based on the material balance for the tool’s flowline, applicable to both pressuredrawdown and buildup data simultaneously, plotting formation rate versus pressure. This method assumes that thepermeability of the formation, the viscosity of the formation fluid and the compressibility of the fluid in the tool stay constantduring a pressure test. If the data points fall on a straight line, mobility can be derived from the line slope.



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Figure 3-Theoretical flowregimes developed by a probe type tools (left) and typical pretest pressure vs time plot (topright) and buildup derivative analysis (bottom right)

Despite permeability from probe type tools provides valuable information, uncertainties arise when upscaling it to the whole

reservoir, due to the limited depth of investigation, the sampling rate and the fact that probe type tools do not develop acomplete radial flow regime.

Permeability from Straddle Packer Tools with miniDST/IPTT testsIn the 90s the introduction of the latest generation of wireline formation testers, equipped with dual packer device able tostraddle selectively one section of reservoir, typically one meter, enabled the possibility to measure permeability at reservoirscale. As opposed to pretests where few tens of cc are produced, IPTT involve the production of 10 to 100 liters typically,followed by a pressure buildup usually lasting 1-2 hours. These tests develop a radial flow at reservoir scale and have a radiusof investigation normally in the range of tens of meters, depending on production time, volume pumped, reservoirpermeability and test duration (Ayan 2001, Elsahawi, 2008). Also, it is possible to perform at the same time verticalinterference tests (VIT) adding monitoring probes above or below the straddle packer. Informations that can be retrieved byIPPT tests include formation pressure, permeability, anysotropy, skin factor, vertical connectivity and reservoir deliverability.

Uncertainties associated with charaterization of reservoir fluids, once constrained to sample analysis possible only in fewzones and with results available few weeks after the acquisition, are now overcomed with DFA, Downhole Fluid Analysis(Mullins, 2008). While reservoir fluid is pumped by the tool, fluid typing and composition is provided in real time byspectrometers, as well as value of insitu density and viscosity (Fig. 8). This enables the possibility to interpret permeabilitytests in real time, since fluid type, composition and viscosity are critical inputs to derive permeability.

Figure 4 shows a typical buildup analysis of IPPT test carried out with a straddle packer tool; theoretically a first radial flowappears after storage, corresponding to the horizontal permeability thickness of the straddled interval. In practice this isseldom observed, since masked by storage effects. Then if the reservoir boundaries are thicker than the straddled interval, anegative half slope spherical flowregime develops, followed by a radial flow, corresponding to the permeability thickness ofthe whole reservoir in between the impermeable boundaries.

Spherical

SphericalRadial

Radial

Storage



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Spherical Flow regime is controlled by spherical permeability which can be approximated with equation 3 below:

Consequently, if spherical flowregime is observed, anysotropy permeability ratio k v /k h can be determined. Packer position inthe reservoir is particular important in case permeability anysotropy is one of the primary objectives; in such case it isrecommended to set the tool in the middle of the sand body. If the packer is set close to one of the impermeable boundaries,two parallel negative half slope lines representing hemisperical and spherical flow regimes develop, and this should beconsidered when computing k v /k h. If radial flow is then observed, the values of k v and k h can be determined.

Figure 4 - Theoretical flowregimes during IPPT test carried out with a straddle packer tool; the first radial flowcorresponds to the horizontal permeability thickness of the straddled interval. Then, if the reservoir boundaries arethicker than the straddled interval, a negative half slope spherical flowregime develops, followed by a radial flow,corresponding to the permeability thickeness of the whole reservoir in between the impermeable boundaries.

In case of a laminated reservoir or high permeability anysotropy, the flowregime may result constrained in between thestraddled interval, rather than propagating to the main impermeable boundaries. In such case a radial flow corresponding topermeability thickness of straddled interval develops directly, see Fig. 5.

Figure 5 - Theoretical flowregimes during IPPT test carried out with a straddle packer tool in a laminated reservoir; Insuch case a radial flow corresponding to permeability thickness of straddled interval develops directly, sinceconstrained by the laminations.

Due to modular configuration of the tool, it is possible to add above or below the straddle packer one or more monitoringprobes. Indications on vertical connectivity and determination of k v and k v /k h across tested interval are provided by thepressure and time delay response at the observation probe (Goode et al., 1992). This method is called Vertical Interference

Spherical

Radial

Radial

First Radial



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Test (VIT) and provides an independent determination of k v that can be compared to the one obtained with straddle packerIPTT test. In theory, if the single probe and dual packer are located in the same zone, both transient data should exhibit thesame radial flow stabilization.

Figure 6 - Theoretical flowregimes during IPPT/VIT test carried out with a straddle packer and probe tool.

IPTT Test DesignA proper pre-job design is a must to achieve representative IPTT results. Main points to consider (Bertolini et al, 2009) are:-The contributing thickness h must be clearly identified from logs. To this purpose, multilayer reservoirs of metric thicknesswell defined between impermeable boundaries are the optimal environment. In case of laminated reservoirs, h is the straddlepacker interval since flow regime is constrained by the laminations. Uncertainties in h determination arise with thickreservoirs without well defined boundaries.-It must be possibile to create enough drawdown in the tested interval, considering that average tools pump rate is ranging

between 0.3 to 1.5 liters/min. Reservoirs with very high permeability in order of a Darcy or more should be excluded due todifficulties in creating enough delta pressure to be detected by the pressure gauges.-The buildup should be long enough to reach radial flow. To this purpose, real time job monitoring is a must, in order tooptimize buildup length. It is recommended to acquire at least two good quality buildups.-The hole should be in good conditions to achieve seal with the packers, and if there are operational constraints in stationtime due to sticking, drill pipe conveyance is recommended.-There is a safety concern regarding hydrocarbons released into mud column during pumping. 800 liters of gas is normallyconsidered the maximum safe limit of gas volume that can be realeased in a WBM environment (OBM is more friendly sinceabsorbing part of the gas pumped in the wellbore). However, the best approach is to use softwares able to simulate maximumamount of hydrocarbons that can be discharged safely into the mud based on expected well and reservoir conditions. Drillpipe conveyance offers the possibility to circulate mud during the wireline formation testing acquisition, if needed.-Tool pumps should be calibrated in order to have accurate downhole rate measurement, since rate is a key input forpermeability determination.

Radial



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IPTT developmentsThe upper permeability limit of IPTT application is typically in the order of a Darcy or above, due to impossility with currentpumps of creating enough delta pressure to be detected by the gauges. The lower permeability limit is usually abovemicrodarcies due to the need of having very slow pumps able to create a steady state drawdown and a tool specifically

designed with larger flowarea than current straddle packer, and with very low storage volume.A new pump able to achieve a rate of 6 l/min recently extended IPTT application to higher permeability reservoirs.A new device to connect to the reservoir was recently introduced (Figure 7), consisting in four large radial inlets mounted ona packer. The advantage of this configuration is the elimination of sump volume in between packers while maintaining alarge flow area, with benefits on clean up time and on flowregime identification due to very limited storage. The device isalso less sensitive to borehole conditions with respect to a standard straddle packer tool.

Figure 7 – New wireline formation tester device with four large radial inlets over the packer section (left),comparison with standard straddle packer tool (right).

A case history with the new device is reported in Fig. 8, where the flowregime identification from pressure buildup analysisis very neat despite the low permeability and the short pressure buildup at the end of clean up sequence. The figuresummarizes the modern approach of wireline formation testing, providing not only pressure and reservoir permeability butalso full characterization of hydrocarbon properties in real time over the tested interval through Downhole Fluid Analysis.The new wireline formation testing technology allowed in this case the discovery of relevant hydrocarbon bearing zones thatwould not be normally assessed due to the low permeability.

Recent developments on deconvolution methods are also of relevant interest to enhance the IPTT interpretation (Pimonov etal, 2009, Wu J. et al, 2009). Deconvolution methods remove wellbore storage effects for earlier detection of radial flow,transform a noisy production interval into ideal drawdown to be eventually used for interpretation and enhance radius ofinvestigation allowing identification of eventual boundaries.

Clean up profile



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Figure 8 - Data acquired with the ntesting, providing reservoir pressure,and k h . Low tool storage enables cleashort pressure buildup time.

Reservoir Deliverability Forecast Early assessment of the reservoir potenmade available before casing the wellsoftware producing Inflow Performancthe reservoir pressure and the hydrocmeasurements. The IPR plot defines ifneeded to increase performance. This a(Ramaswami et al., 2012, Aguilera et al

the results have to be properly weightecompletion. Further integration and rerates should be carried out in order to fi

DENSITY

GOR

COMPOSITION

PRESSURE

ew radial device tool summarize the modern aphydrocarbon characterization in real time throug

r identification of spherical and radial flow despit

tial to flow hydrocarbons is of primary relevance, e. Productivity of each layer of interest can be fore

Relationship (IPR) plot. Input data are the kh fromarbon properties derived from Downhole Fluid Anthe tested zone is a candidate for further developmeproach provided a forecast close to the observed p

., 2012, Kumar et al., 2008) , including the case hist

since the simulation is carried out with some assumonciliation with all other available data, especiallye tune the methodology.

9

proach of wireline formationDownhole Fluid Analysis, k v the low permeability and the

specially if the forecast can beasted using a Nodal Analysis

IPTT over the zone of interest,alysis, all derived by loggingt and if eventual stimulation is

roduction results in many casesry provided below. Of course

ptions like the skin of the finalfter observation of production

Radial FlowKh=1.12mDm

Spherical FlowKv /Kh=0.44



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In case IPTT tests were not carried out in all zones of interest, it is still possible to forecast the productivity of these zonesintegrating and upscaling NMR permeability with kh derived from IPTT tests, obtaining a continuous calibrated permeabilityprofile. The method consists in the following steps:-Identify facies and hydraulic units from log data (NMR, nuclear, resistivity and image logs).

-Derive NMR cumulative permeability thickness ∑khNMR of each hydraulic unit, considering the unit made up of verticalsequence of n layers of thickness h (normally considering h =10 cm).-Determine scale factor for NMR permeability comparing ∑khNMR to kh from IPTT in the same hydraulic unit:

-Apply scale factor to NMR permeability log; different scale factors may be applied based on rock type and facies.-kh for each unit can be now derived integrating calibrated NMR permeability log over interval of interest-Input kh, fluid properties and pressure into Nodal Analysis software to produce IPR plots for the hydraulic units

The application of this methodology is described with a case history from Adriatic Sea, Italy (Loi et al, 2011) in thinlaminated sandstone multilayers, gas bearing. Due to high permeability anysotropy, the kh determined by IPTT tests isconsidered referred to the straddled interval between the packers, being the flow constrained by the horizontal laminations.

The simulation considers the production forecast of 18 m perforated interval. Two IPTT tests were carried out in this interval,each providing a kh over 1 m interval, used to determine the scale factor for the NMR permeability log. The kh NMR calibratedwith scale factor from IPTT tests over the 18 m interval to be perforated resulted 1.5 mDm, with average reservoir pressure of2944 psi. Forecasted IPR curve is shown in Fig. 10; measured gas rate during DST cleanup was 5600 Sm3/day with flowingbottom hole pressure of 600 psi, a rate slightly lower than simulated (7950 Sm3/day). The same interval was then fracpackedproducing 40000 Sm3/day. While discrepancies between forecasted and observed rates may be due to assumption ofcompletion skin , to very short DST clean up not providing the full reservoir deliverability, to the need of fine tuning themethod, overall it was possible to forecast the productivity of the several levels to be perforated in this well and thusdetermine completion strategy. Zones with low forecasted rates were directly fracpacked prior to clean up in order to improveperformance, while zones with higher expected productivity, especially if near to water zones, were completed withoutfracturing, with High Rate Water Pack technique.In conclusion, the productivity forecast integrated with Downhole Fluid Analysis data, useful to discriminate gas and waterzones, allowed a more efficient well testing and completion strategy, thus reducing the total cost of the well. This approach is

now used for the new wells drilled in the same environment, and further comparison of forecasted vs observed rates will beused to fine tune the model.

Figure 9 – Composite log display (left) with Gamma Ray, Induction, NMR and image logs (left ), IPTT testsinterpretation (right). IPTT tests were used to upscale the NMR permeability over 18 m interval to be perforated(highlighted in red), in order to forecast gas production.



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Figure 10 – IPR (Inflow Performance Relationship) Plot forecast from integration of NMR and IPTT tests shown inFigure 9. Measured gas rate during cleanup of the interval was 5600 m3/day with flowing bottom hole pressure of 600psi (red circle), a rate lower than simulated also due to very short DST clean up. The same interval was thenfracpacked producing 40 KSm3/day.

ConclusionsModern wireline formation testers provide a detailed reservoir characterization through formation fluid pressure, downholefluid analysis, sampling and permeability measurements. Through proper design and execution of IPTT tests it is possible todetermine permeability at reservoir scale, directly comparable to DST tests. IPTT tests are an attractive method for safety andenvironmental aspects since no hydrocarbon flaring is required, also providing results in short timeframe (days) andconsiderable reduction of costs. For these reasons wireline formation tests are gaining more and more popularity as possiblealternatives to well testing in exploration and appraisal activities, especially for evaluation of multilayer reservoirs with highdegree of heterogeneity or low permeability zones that may be difficult to test in conventional manner. Characterization offaults and boundaries should not be a primary objective in IPTT programs, as these features must be relatively close to thewellbore to be detected.

Recent hardware innovations enhanced the range of applicability of IPTT tests; high rate pumps allowed testing of higherpermeability reservoirs, while a new packer with radial inlets eliminates the large storage volume of standard straddle packertools, with faster clean up times and flowregime identification.

IPTT data acquired during logging can be used to forecast reservoir deliverability with IPR plots in a timely manner, with the

possibility of optimizing well test and completion strategy. IPTT tests can also provide a scale factor for NMR data, todetermine a continous permeability profile to be used for further reservoir deliverability forecasts, as shown by the casehistory described in this paper.

The different permeability sources are complementary and if relevant factors like the scale of the medium under investigationand state of the rock during the measurement are taken in consideration, their reconciliation and integration with all availabledata is a necessary step to build an accurate well productivity model. Each permeability measurement method has pros andcons that should be evaluated in relation to the type of reservoir, the operating constraints and the objectives to be achieved,in order to define the best acquisition strategy. To this purpose, a comparison between IPTT and standard DST tests isreported on Tables 1 and 2.

Clean up observation

Gas Deliverability Estimate



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Wireline Formation TestingWireline Formation TestingWireline Formation TestingWireline Formation Testing IPTTIPTTIPTTIPTT DSTDSTDSTDSTInitial Formation Pressure PiInitial Formation Pressure PiInitial Formation Pressure PiInitia l Formation Pressure Pi Profile Average Value of flowing intervalRadial Permeability KhRadial Permeability KhRadial Permeability KhRadial Permeabili ty Kh Better evaluation in multilayers Average Value of flowing interval

Vertical Permeability KvVertical Permeability KvVertical Permeability KvVertica l Permeabi lity Kv yes with VITOnly if spherical flow regime isobserved

HighHighHighHigh Permeability ReservoirsPermeability ReservoirsPermeability ReservoirsPermeability Reservoi rs Limited by low pump rate YesReservoir boundariesReservoir boundariesReservoir boundariesReservoi r boundaries Only if very close YesSkin FactorSkin FactorSkin FactorSkin Factor Open Hole skin Total skinFlow CapacityFlow CapacityFlow CapacityFlow Capacity Limited by low pump rate No limitationsDrainage Area ExtensionDrainage Area ExtensionDrainage Area ExtensionDrainage Area Extension No Yes

PVT Samples (Oil /Gas)PVT Samples (Oil /Gas)PVT Samples (Oil /Gas)PVT Samples (Oil /Gas)High quality sampling, real timedownhole control

Two phases sample if Pb close toformation pressure

Water SamplesWater SamplesWater SamplesWater SamplesHigh quality sampling, real timedownhole control Only if water zone is completed

H2S/C0H2S/C0H2S/C0H2S/C02/ph2/ph2/ph2/ph determinationdeterminationdeterminationdeterminati on Yes , through DFA and/or sampling H2s scavenging, no representative PhInvestigationInvestigationInvestigationInvestigation Limited to ten's of meters Extended and interference testsRock Mechanics/Sand ControlRock Mechanics/Sand ControlRock Mechanics/Sand ControlRock Mechanics/Sand Control Stress Test Yes

DetailedDetailedDetailedDetailed FluidFluidFluidFluid CharacterizationCharacterizationCharacterizationCharacterizationFluid Composition and GOR throughDFA, In-situ Density , In-situ Viscosity No

Fluid ContactsFluid ContactsFluid ContactsFluid Contacts Pressure and Fluid Scanning No

Table 1: Comparison IPTT vs DST: Data Acquisition

Wireline Formation TestingWireline Formation TestingWireline Formation TestingWireline Formation Testing IPTTIPTTIPTTIPTT DSTDSTDSTDST

Cost (US$)Cost (US$)Cost (US$)Cost (US$)----North SeaNorth SeaNorth SeaNorth Sea 0.5-1 million entire acquisition 10-30 million/testDischarge to environmentDischarge to environmentDischarge to environmentDischarge to environment None Yes (hydrocarbon flaring)SafetySafetySafetySafe ty No particular issues, except if

discharging big volumes of gas in mudIssues related to hydrocarbon flowing through complex setup

TimeTimeTimeTime 1-2 days 1-2 weeks

Table 2: Comparison IPTT vs DST: Operating Constraints

AcknowledgementsThe authors wish to thank ENI E&P management for the permission of publishing the data.Special thanks to Sameer Joshi who monitored and interpreted one of the case histories mentioned on the paper.

Nomenclature

C = Probe Type CoefficientDFA = Downhole Fluid AnalysisDST = Drill Stem TestH = thickness, mIPR= Inflow Performance RelationshipIPTT = Interval Pressure Transient Testingk = Permeability, mDkh = Permeability thickness, mDmk h = Horizontal Permeability, mD

k v = Vertical PermeabilityNMR = Nuclear Magnetic ResonanceOBM = Oil Based Mud



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P = Pressure, psiQ = FlowrateR = Radial DistanceS = Skin

D = DaySm3/D = Standard Cubic Meters per DayWBM = Water Based Mudµ = Viscosity, cpΦ = Porosity, V/V∆P = Delta pressure, psi

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14. Kumar, N.K., Joshi S., Banerjee R., Sundaram K.M., “A New Method for Gas Well deliverability Potential estimationUsing MiniDST and Single Well Modelling: Theory and Examples”, SPE 113650, 2008.

15. Pimonov E., Ayan C., Onur M., Kuchuk F., “A New Pressure/Rate Deconvolution Algorithm to Analyze WirelineFormation Tester and Well-Test Data, SPE 123982, 2009.

16. Ramaswami S., Elshahawi H, El Battawy A., “Integration of wireline Formation Testing and well Testing Evaluation-Anexample from the Caspian”, SPE 139837, 2012 .

17. Schlumberger, “Fundamental of Formations Testing”, 2006. Whittle M., Lee J., Gringarten A.C., “Will WirelineFormation Tests Replace Well Tests?”,SPE 84086, 2003.

18. Stewart G., Wittmann M., “Interpretation of the Pressure Response of the Repeat Formation Tester”, Spe 8362, 1979

19. Wu J., Georgi D., Ozkan E., “Deconvolution of Wireline Formation Testing Data”, SPE 124220, 2009.

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Reservoir Permeabilities From Wireline Formation Testers

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