Reservoir Permeability From Wireline Formation Testers - SPE 2013

7/23/2019 Reservoir Permeability From Wireline Formation Testers - SPE 2013

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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 been

reviewed 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 to

reproduce 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 also

relevant in overall reservoir management and development, including reservoir simulation, gravity drainage, flood

performance, assessment of gas or water coning.

Attempts to derive reservoir permeability with wireline formation testers started in the 70s, calculating drawdown mobility

from pretests taken with a single probe. However, despite drawdown mobility provides valuable information about reservoir

behavior, it is not comparable to reservoir permeability traditionally measured with Drill Stem Tests (DST). This is due to its

limited depth of investigation, the upscaling difficulties and the fact that probe type tools do not develop a complete radial

flow regime. In the 90s the introduction of the latest generation of wireline formation testers, equipped with straddle packer

modules able to develop radial flow with radius of investigation in the order of tens of meters, enabled measurement of

permeability at reservoir scale. These tests, called miniDST or IPTT (Interval Pressure Transient Testing), represent in some

cases 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 final

interpretation, 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 permeability

sources and the reservoir model, including comparison between simulated reservoir deliverability and measured well test

rates.

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

include:

- Nuclear Magnetic Resonance (NMR), providing a continuous pore size and porosity profile from which

permeability is derived. The most used equation is from Coates-Timur (Coates et al., 1973):

(1)

where is porosity. NMR permeability can be calibrated by core study, providing a, b, c values (if core study is

not 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 acoustic

wave. These are often weak correlations not reflecting real permeability distribution, especially in heterogeneous

formations.

- 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 scale

of the medium under investigation (refer to Fig. 1) and state of the rock. Without considering these factors, the

permeabilities 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



2 SPE 164924

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 and

correlations 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 chambers

or injection tests are carried out, with environmental and safety concerns. Time also matters; logs have advantage on this

since acquisition and results delivery are tipically in the order of days, while full scale DST is in the order of weeks and cores

results 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 formation

pressure. The repeat formation tester, introduced in 1975, was able to acquire two fluid samples and unlimited formation

fluid pressures. This feature became quickly a very effective method to understand reservoir fluid types through pressure

gradients, defining fluid contacts if possible, and connectivity between wells based on same pressure regime. Apart the

feature 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 the

possibility of testing only primary porosity formations with medium to good mobilities, and the high contamination of

samples , 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 subsequent

buildup during the formation fluid pressure measurement. However, despite drawdown mobility provides valuable

information about reservoir behavior, it is not comparable to reservoir permeability traditionally measured with DST mainly



SPE 164924 3

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 for

this type of technology. The modular configuration extended the range of application with respect to the previous single

probe 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 with

quick 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 acquisition

objectives (Schlumberger, 2006).

From the 90s wireline formation testing modules were enhanced in order to improve hardware (mechanical reliability as well

as capability of operating under extreme pressure and temperature conditions) and measurements. Today it is possible to

characterize 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. Formation

water properties (salinity, density, ph) can also be measured in real time. Downhole samples are normally collected and their

analysis 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 efficient

method 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 valid

alternative 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 formation

into the pretest chamber of the tool. This initial phase, called drawdown, causes a reduction in pressure that mainly depends

from 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 mobile

phase 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 gradients

and eventual fluid contacts are then determined using representative points.

Further information regarding permeability can be extracted from the representative points, with analysis of drawdown and

buildup. The pretest analysis to derive permeability was first introduced in 1962 (Moran) and later developed with the

introduction 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/cp

q is total flow rate in cc/sec

∆P is the pressure drawdown in psi

C 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 read

build up pressure and considering the effective drawdown volume only from the moment the flowline is decompressing

below 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 normally

supercharged and thus correct delta pressure cannot be determined. Also, the equation is based on steady-state drawdown

conditions, difficult to achieve in low mobilities, unless pretest rate is set extremely slow. Above 100 mD/cp the pressure

drawdown 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 on

the invaded zone, normally mud filtrate with a residual part of original fluid. Several methods are available to determine

viscosity 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 permability

sources (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 using

derivative analysis to determine kh (permeability thickness). Figure 3 shows the flowregime propagation into reservoir and its

effects on derivative; initial storage is related to compressibility effects into the tool volume between probe, gauges and

pretest chamber. Then, spherical and radial flowregimes can be observed. However, buildup analysis is seldom used for

permeability purposes, since the flowregime is influenced by heterogeneities surrounding the probe, making difficult to

determine the real contributing thickness h. Also, probe type tools do not develop a real radial flow, since pressure transient

lines 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 pressure

drawdown and buildup data simultaneously, plotting formation rate versus pressure. This method assumes that the

permeability of the formation, the viscosity of the formation fluid and the compressibility of the fluid in the tool stay constant

during a pressure test. If the data points fall on a straight line, mobility can be derived from the line slope.



SPE 164924 5

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 to

straddle selectively one section of reservoir, typically one meter, enabled the possibility to measure permeability at reservoir

scale. 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 radius

of investigation normally in the range of tens of meters, depending on production time, volume pumped, reservoir permeability and test duration (Ayan 2001, Elsahawi, 2008). Also, it is possible to perform at the same time vertical

interference tests (VIT) adding monitoring probes above or below the straddle packer. Informations that can be retrieved by

IPPT 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 few

zones 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 by

spectrometers, as well as value of insitu density and viscosity (Fig. 8). This enables the possibility to interpret permeability

tests 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 is

seldom observed, since masked by storage effects. Then if the reservoir boundaries are thicker than the straddled interval, a

negative half slope spherical flowregime develops, followed by a radial flow, corresponding to the permeability thickness of

the whole reservoir in between the impermeable boundaries.

Spherical

SphericalRadial

Radial

Storage



6 SPE 164924

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 in

the reservoir is particular important in case permeability anysotropy is one of the primary objectives; in such case it is

recommended 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 be

considered 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 the

straddled interval, rather than propagating to the main impermeable boundaries. In such case a radial flow corresponding to permeability 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 monitoring

probes. Indications on vertical connectivity and determination of k v and k v/k h across tested interval are provided by the pressure and time delay response at the observation probe (Goode et al., 1992). This method is called Vertical Interference

Spherical

Radial

Radial

First Radial



SPE 164924 7

Test (VIT) and provides an independent determination of k v that can be compared to the one obtained with straddle packer

IPTT test. In theory, if the single probe and dual packer are located in the same zone, both transient data should exhibit the

same 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 thickness

well defined between impermeable boundaries are the optimal environment. In case of laminated reservoirs, h is the straddle

packer interval since flow regime is constrained by the laminations. Uncertainties in h determination arise with thick

reservoirs 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 to

optimize 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 station

time 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 normally

considered the maximum safe limit of gas volume that can be realeased in a WBM environment (OBM is more friendly since

absorbing part of the gas pumped in the wellbore). However, the best approach is to use softwares able to simulate maximum

amount of hydrocarbons that can be discharged safely into the mud based on expected well and reservoir conditions. Drill

pipe 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 for

permeability 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 current

pumps of creating enough delta pressure to be detected by the gauges. The lower permeability limit is usually above

microdarcies 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 on

a packer. The advantage of this configuration is the elimination of sump volume in between packers while maintaining a

large flow area, with benefits on clean up time and on flowregime identification due to very limited storage. The device is

also 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 figure

summarizes the modern approach of wireline formation testing, providing not only pressure and reservoir permeability but

also 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 that

would 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 et

al, 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 of

investigation allowing identification of eventual boundaries.

Clean up profile



SPE 164924

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

Reservoir Deliverability ForecastEarly assessment of the reservoir pote

made available before casing the well

software producing Inflow Performancthe reservoir pressure and the hydroc

measurements. The IPR plot defines if

needed to increase performance. This a

(Ramaswami et al., 2012, Aguilera et al

the results have to be properly weightecompletion. Further integration and re

rates should be carried out in order to fi

DENSITY

GOR

COMPOSITION

PRESSURE

ew radial device tool summarize the modern ap hydrocarbon characterization in real time througr 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 A

the tested zone is a candidate for further developme

proach 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, especially

e tune the methodology.

9

proach of wireline formationDownhole Fluid Analysis, kv

the low permeability and the

specially if the forecast can be

casted using a Nodal Analysis

IPTT over the zone of interest,alysis, all derived by logging

t and if eventual stimulation is

roduction results in many cases

ry provided below. Of course

ptions like the skin of the finalafter observation of production

Radial Flow

Kh=1.12mDm

Spherical FlowKv /Kh=0.44



10 SPE 164924

In case IPTT tests were not carried out in all zones of interest, it is still possible to forecast the productivity of these zones

integrating and upscaling NMR permeability with kh derived from IPTT tests, obtaining a continuous calibrated permeability

profile. 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 kh NMR 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 kh NMR 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 thin

laminated sandstone multilayers, gas bearing. Due to high permeability anysotropy, the kh determined by IPTT tests is

considered 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 calibrated

with scale factor from IPTT tests over the 18 m interval to be perforated resulted 1.5 mDm, with average reservoir pressure of

2944 psi. Forecasted IPR curve is shown in Fig. 10; measured gas rate during DST cleanup was 5600 Sm3/day with flowing

bottom hole pressure of 600 psi, a rate slightly lower than simulated (7950 Sm3/day). The same interval was then fracpacked

producing 40000 Sm3/day. While discrepancies between forecasted and observed rates may be due to assumption of

completion skin , to very short DST clean up not providing the full reservoir deliverability, to the need of fine tuning the

method, overall it was possible to forecast the productivity of the several levels to be perforated in this well and thus

determine completion strategy. Zones with low forecasted rates were directly fracpacked prior to clean up in order to improve

performance, while zones with higher expected productivity, especially if near to water zones, were completed without

fracturing, with High Rate Water Pack technique.

In conclusion, the productivity forecast integrated with Downhole Fluid Analysis data, useful to discriminate gas and water

zones, 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 tests

interpretation (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.



SPE 164924 11

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, downhole

fluid analysis, sampling and permeability measurements. Through proper design and execution of IPTT tests it is possible to

determine 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) and

considerable reduction of costs. For these reasons wireline formation tests are gaining more and more popularity as possible

alternatives to well testing in exploration and appraisal activities, especially for evaluation of multilayer reservoirs with high

degree 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 the

wellbore to be detected.

Recent hardware innovations enhanced the range of applicability of IPTT tests; high rate pumps allowed testing of higher

permeability reservoirs, while a new packer with radial inlets eliminates the large storage volume of standard straddle packer

tools, 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 case

history described in this paper.

The different permeability sources are complementary and if relevant factors like the scale of the medium under investigation

and state of the rock during the measurement are taken in consideration, their reconciliation and integration with all available

data is a necessary step to build an accurate well productivity model. Each permeability measurement method has pros and

cons 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



12 SPE 164924

Wireline Formation TestingWireline Formation TestingWireline Formation TestingWireline Formation Testing IPTTIPTTIPTTIPTT DSTDSTDSTDST

Initial Formation Pressure PiInitial Formation Pressure PiInitial Formation Pressure PiInitia l Formation Pressure Pi Profile Average Value of flowing interval

Radial Permeability KhRadial Permeability KhRadial Permeability KhRadial Permeability Kh Better evaluation in multilayers Average Value of flowing interval

Vertical Permeability KvVertical Permeability KvVertical Permeability KvVertical Permeabi lity Kv yes with VIT

Only if spherical flow regime is

observed

HighHighHighHigh Permeability ReservoirsPermeability ReservoirsPermeability ReservoirsPermeability Reservoi rs Limited by low pump rate Yes

Reservoir boundariesReservoir boundariesReservoir boundariesReservoi r boundaries Only if very close Yes

Skin FactorSkin FactorSkin FactorSkin Factor Open Hole skin Total skin

Flow CapacityFlow CapacityFlow CapacityFlow Capacity Limited by low pump rate No limitations

Drainage 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 time

downhole control

Two phases sample if Pb close to

formation pressure

Water SamplesWater SamplesWater SamplesWater Samples

High quality sampling, real time

downhole 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 Ph

InvestigationInvestigationInvestigationInvestigation Limited to ten's of meters Extended and interference tests

Rock Mechanics/Sand ControlRock Mechanics/Sand ControlRock Mechanics/Sand ControlRock Mechanics/Sand Control Stress Test Yes

DetailedDetailedDetailedDetailed FluidFluidFluidFluid CharacterizationCharacterizationCharacterizationCharacterization

Fluid Composition and GOR through

DFA, 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)

SafetySafetySafetySafety No particular issues, except if

discharging big volumes of gas in mud

Issues related to hydrocarbon flowing

through complex setup

TimeTimeTimeTime 1-2 days 1-2 weeks

Table 2: Comparison IPTT vs DST: Operating Constraints

Acknowledgements

The 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 Coefficient

DFA = Downhole Fluid Analysis

DST = Drill Stem Test

H = thickness, m

IPR= Inflow Performance Relationship

IPTT = Interval Pressure Transient Testing

k = Permeability, mD

kh = Permeability thickness, mDm

k h = Horizontal Permeability, mD

k v = Vertical Permeability NMR = Nuclear Magnetic Resonance

OBM = Oil Based Mud



SPE 164924 13

P = Pressure, psi

Q = Flowrate

R = Radial Distance

S = Skin

D = DaySm3/D = Standard Cubic Meters per Day

WBM = Water Based Mud

µ = Viscosity, cp

= Porosity, V/V

P = Delta pressure, psi

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Reservoir Permeability From Wireline Formation Testers - SPE 2013

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