the nature of naturally fractured reservoirs

4 Oilfield Review

The Nature of Naturally Fractured Reservoirs

Tom BrattonDenver, Colorado, USA

Dao Viet CanhNguyen Van QueCuu Long Joint Operating Company (JOC)Ho Chi Minh City, Vietnam

Nguyen V. DucVietSovPetroVung Tau City, Vietnam

Paul GillespieDavid HuntHydroBergen, Norway

Bingjian LiAhmadi, Kuwait

Richard MarcinewSatyaki RayCalgary, Alberta, Canada

Bernard MontaronDubai, United Arab Emirates

Ron Nelson Broken N Consulting, IncorporatedCat Spring, Texas, USA

David SchoderbekConocoPhillipsCalgary

Lars SonnelandStavanger, Norway

For help in preparation of this article, thanks to Lee Conn,MI LLC, Houston; Phil Christie, John Cook and Michael Williams, Cambridge, England; Adam Donald andOmer Gurpinar, Denver, Colorado; Peter Kaufman, Pittsburgh,Pennsylvania, USA; and John Lassek, Sugar Land, Texas.BorTex, ClearFRAC, CMR (Combinable Magnetic Resonance),ECLIPSE, FMI (Fullbore Formation MicroImager), FormationMicroScanner, GeoFrame, geoVISION, MDT (Modular Formation Dynamics Tester), Petrel, RAB (Resistivity-at-the-Bit), Sonic Scanner, Variable Density and VDA (ViscoelasticDiverting Acid) are marks of Schlumberger.

Naturally fractured reservoirs present a production paradox. They include reservoirs

with low hydrocarbon recovery: these reservoirs initially may appear highly

productive, only to decline rapidly. They are also notorious for early gas or water

breakthrough. On the other hand, they represent some of the largest, most productive

reservoirs on Earth. The paradoxical nature of this class of reservoirs is the impetus

behind the industry’s efforts to learn more about them and model them with a

reasonable amount of certainty.

Nearly all hydrocarbon reservoirs are affected insome way by natural fractures, yet the effects offractures are often poorly understood and largelyunderestimated. In carbonate reservoirs, naturalfractures help create secondary porosity andpromote communication between reservoircompartments. However, these high-permeabilityconduits sometimes short-circuit fluid flowwithin a reservoir, leading to premature water orgas production and making secondary-recoveryefforts ineffective. Natural fractures also occur insiliciclastic reservoirs of all types, complicatingseemingly straightforward matrix-dominatedproduction behavior. In addition, natural fracturesare the main producibility factor in a wide rangeof less conventional reservoirs, includingcoalbed-methane (CBM), shale-gas, basement-rock and volcanic-rock reservoirs. Althoughnatural fractures play a lesser role in high-porosity, high-permeability reservoirs such asturbidites, they commonly form barriers to flow,frustrating attempts to accurately calculaterecoverable reserves and predict production over time.

Ignoring the presence of fractures is notoptimal reservoir management; eventually, frac -tures cannot be ignored because the tech nicaland economic performance of the reservoirdegrades.1 The biggest risk in not characterizingnatural fractures early is that such an oversightcan severely limit future field-developmentoptions. For example, a company that does not

take advantage of the opportunities to evaluatenatural fractures during the early developmentstage may waste resources on unnecessary infilldrilling. Asset teams may never extract thehydrocarbons originally deemed recoverablebecause, without understanding the impact ofnatural fractures on production behavior, theyhave not adequately prepared the field forsecondary recovery.

This article examines the impact of naturalfractures on hydrocarbon reservoirs at differentstages of reservoir development. The classifi -cations of natural fractures and naturally frac -tured reservoirs (NFRs) are reviewed, along withfactors that affect NFR behavior. We describemethods used over a range of scales to identifyand characterize natural fractures and to modelthe influence of fracture systems on production.Case studies from around the world highlightvarious approaches.

Natural Fractures in Field Development The investigation of natural fractures should startduring the exploration stage. Relevant surfaceoutcrops of the reservoir section or reservoiranalogs can form the basis of a lithological,structural and stratigraphic foundation fromwhich geologists build conceptual models. Thesemodels often begin with knowledge of theregional stresses (next page).2 The stress state isimportant in NFRs because the stress state

58732schD04R1.qxp:58732schD04R1 10/10/06 9:44 PM Page 4

Summer 2006 5

largely dictates whether fractures are open toconduct reservoir fluids. In addition, themagnitude and direction of horizontal stressesplay critical roles in hydraulic fracture design,the primary stimulation method for NFRs.

Multicomponent (3C) seismic surveys acquiredearly in field development yield important data fordetermination of azimuthal anisotropy, which isessential to characterize natural fractures and toplace wells effectively.3 For example, knowing thegeneral orientation of fracture systems duringwell planning dramatically improves the chancethat a well will intersect fractures.

New wells present an opportunity to collectappropriate geological, geophysical and mechan -ical data from many sources, including infor -mation from logging tools, borehole seismic

surveys, sampling devices and fullbore cores.Other valuable sources of information that canbe acquired during the early stages of fielddevelopment include drillstem tests, initial flowtests, and buildup and drawdown tests. Properlyassessing the role of natural fractures can resultin early field-development successes and can laythe groundwork for later development stages,including secondary-recovery projects.

Information about natural fractures is alsoimportant during the well-construction stage.During overbalanced drilling and cementingoperations, open natural fractures can cause lostcirculation problems, loss of expensive drillingfluids and the potential loss of wells. A lessobvious cost may be associated with the reducedproductivity that results when drilling fluids and

cement seal fractures that were once open andpotentially productive.4 Employing underbalanceddrilling techniques and using less damaging

1. Nelson RA: “Evaluating Fractured Reservoirs:Introduction,” Geologic Analysis of Naturally FracturedReservoirs, 2nd ed. Woburn, Massachusetts, USA: Gulf Professional Publishing (2001): 1–2.

2. For more on world stress data: http://www-wsm.physik.uni-karlsruhe.de/pub/introduction/introduction_frame.html (accessed May 18, 2006).

3. Kristiansen P, Gaiser J and Horne S: “HowMulticomponent Seismic Can Be Used to ManageFractured Carbonate Reservoirs,” paper SPE 93762,presented at the 14th SPE Middle East Oil & Gas Showand Conference, Bahrain, March 12–15, 2005.

4. Ehlig-Economides CA, Taha M, Marin HD, Novoa E andSanchez O: “Drilling and Completion Strategies inNaturally Fractured Reservoirs,” paper SPE 59057,presented at the SPE International PetroleumConference and Exhibition, Villahermosa, Mexico,February 1–3, 2000.

>World stress map showing stress data compiled from various sources. In oil and gas regions, borehole measurements are an important source ofpresent-day in-situ stress information. This basic information is used in modeling to help understand fracture networks in fields worldwide. (From theWorld Stress Map Project, http://www-wsm.physik.uni-karlsruhe.de/pub/casmo/content_frames/stress_maps_frame.html, used with permission.)

Regime

Thrust fault

Normal faultStrike slip

Unknown

MethodFocal mechanismsBreakoutsDrilling-induced fracturesBorehole slotterOvercoringHydraulic fracturesGeological indicators

58732schD04R1:58732schD04R1 8/14/06 7:29 PM Page 5

drilling or cementing fluids are possible ways toreduce lost circulation and its associateddamage. However, in many cases, drillers’ optionsare more limited.

When drilling weakened and depleted NFRssurrounded by low-permeability shales oroverpressured zones, drillers must maintain acertain mud weight to support the shale orprevent a blowout from the overpressured zone.Through the years, innovative techniques havebeen developed to limit the risk, cost and damagecaused by lost circulation problems. These includeheating the drilling fluid to alter the stress statearound the borehole; treating the mud withspecialized lost circulation material—such asfibers—when losses start to occur; pretreatingthe drilling fluid with particulate material; andstrategically changing the stresses around thewellbore—for example, by creating fractures.5

In some cases, natural fractures are so largethat drastic measures are required. For example,in some carbonate NFRs in central Asia, drilling-fluid losses have reached 80,000 barrels[12,712 m3] in long intervals of highly fracturedand porous rock. The keys to addressing seriousand recurring lost circulation problems areplanning for losses, defining the target andhaving the required equipment and materialsavailable when problems occur.6 A detailedknowledge of the fracture system is essential to mitigation.

Today, MWD tools can monitor critical drillingparameters in real time, allowing drillingengineers to mitigate lost circulation problems.In addition, LWD technology, such as thegeoVISION imaging-while-drilling service andthe RAB Resistivity-at-the-Bit tool, help identifynatural fractures immediately after drilling pastthem.7 Incorporating natural-fracture informationand rock mechanical properties into cement-jobdesigns reduces the risk of opening up naturalfractures or accidentally fracturing the forma -tion, both of which could cause lost circulation.

Once well construction and evaluation arefinished, the focus moves to designing acompletion and stimulation program to undo thedamage caused by drilling and cementing. Someform of stimulation is required for most NFRswith a low-permeability matrix. Pumping reactivefluids—acidizing, using various formulations ofhydrochloric acid [HCl] or chelants—intonatural fractures is most common in carbonatereservoirs to remove near-wellbore damage,enhance connectivity and improve the conduc -tivity of the system.8 During carbonate-rockstimulation using reactive fluids, zones with the

highest permeabilities commonly take most ofthe treatment fluid, leaving the zones with lowerpermeabilities untreated. Consequently, diver -sion, leakoff and reaction-rate control are keys tosuccess when acidizing carbonates.9

Conventional approaches to diversion includeparticulate- and viscosity-based-diversion methods.Particulate diversion uses solids to bridge andrestrict flow to highly permeable or fracturedzones. For example, rock salt or benzoic acid flakesare pumped to divert in the formation at the losszone, and ball sealers are used to mechanicallydivert from inside tubulars at the perforations.Viscosity-based diversion uses foams, and acids orfluids gelled with viscoelastic surfactants orpolymers to divert treatment and provide fluid-losscontrol within the formation. However, polymershave damaged reservoirs, prompting servicecompanies to develop new surfactant-base fluids.For example, the VDA Viscoelastic Diverting Acidsystem has been used to successfully stimulatefractured carbonate reservoirs all over the world,including Kuwait, Saudi Arabia, Mexico andKazakhstan.10 In addition, a new technique thatuses both technologies—fibrous particulate andviscosity diversion—has been developed foracidizing NFRs.

Natural fractures in siliciclastic reservoirsare also occasionally acidized, typically using acombination of HCl and hydrofluoric acid [HF].Alternatively, hydraulic fracture stimulation ofNFRs requires that the main fracture path bekept open and conductive with proppant.Controlling the leakoff rate and effectiveproppant placement, while minimizing damageto the natural-fracture network, are critical toachieve optimal stimulation and production.

Natural fractures can significantly limit theability to place large volumes of proppant withina hydraulically created fracture. Varioustechniques are used to limit natural-fracturedilation and the corresponding fluid lossesduring hydraulic fracturing. These includereducing fracture net pressure by rate-control orlow-viscosity fluids, and incorporating properlygraded particulates to dynamically bridgedilating fissures, thereby reducing total leakoffvolume. Additionally, conductivity damage withinthe created hydraulic fracture and natural-fracture system can be reduced by lowering thetotal volume of polymer used—for example, byusing low-polymer crosslinked frac gels, increas -ing breaker-to-polymer ratios through the use ofencapsulated breakers, or by replacing thepolymeric fracture fluid with nondamagingviscoelastic surfactant fluid systems such asClearFRAC polymer-free frac fluid.11

The volume occupied by typical fractures—open or mineral-filled—within a vast matrix isusually relatively minuscule, yet the ability offractures to significantly impact fluid-flowbehavior in hydrocarbon reservoirs is enormous.It is not surprising that one of the greatestchallenges facing reservoir experts is how toadequately simulate the effects of fractures onreservoir behavior. Understanding thesereservoirs requires the acquisition and analysisof vast amounts of data, and usually begins withdetailed, foot-by-foot characterization of thefracture and matrix systems. It is the interactionbetween these two systems that must beunderstood while reservoir properties changewith continued production or injection. As fielddevelopment continues, other information—forexample, well-test data, production data, andpassive and time-lapse seismic data—helpsvalidate and improve reservoir models.

The strategy a company uses to achieve field-production and recovery potential is intertwinedwith, and increasingly directed according to, anever-improving NFR model and simulation.During the primary-production stage, changes inreservoir pressure, and consequently effectivestress, alter the fluid flow within fracturenetworks.12 Water or gas breakthrough is themost common negative implication of conductivefractures during the primary-production stage.Besides adding water production and disposalcosts, producing high-mobility water leavesbehind substantial volumes of low-mobility oil.Moreover, premature gas production can drain areservoir of its energy, damage downhole pumpsand complicate surface treatment of producedreservoir fluids.

Secondary-recovery techniques using fluidinjection also change field pressure and effectivestress dynamics, and therefore change fractureconductivity to fluid flow. At this stage in fielddevelopment, asset teams should be familiarwith the role natural fractures play in large-scalefluid movement. Ideally, production andsecondary-recovery strategies—well patternsand spacings, and selection of injection andproduction zones—should reflect the level ofinfluence that natural fractures have onhydrocarbon sweep as determined by simulation.

6 Oilfield Review


Summer 2006 7

Classifying Fractures When developing and modeling fracturedreservoirs, the ability to understand and predictthe characteristics of fracture and fault systemsis essential.13 The complexity of natural-fracturesystems is captured in the descriptive, geneticand geometric methods that geoscientistsemploy to classify natural fractures. Knowingfracture types enhances the simulation of fluidflow through fractures, because various types offractures conduct fluid differently.

To appreciate common classification schemes,a basic understanding of how natural fracturesdevelop is needed. However, achieving thisunderstanding requires more than extensivefield observation of natural fractures; it requireslinking those observations with data fromcontrolled laboratory experiments.14 In thelaboratory, fracture types are divided into twogroups related to their mode of formation: shear fractures that form with shearing parallelto the created fracture, and tension fractures that form with tension perpendicular to thecreated fracture.

In the laboratory, shear and tension fracturesform in consistent orientation with respect to the three principal stress directions, namely the maximum compressive principal stress, σ1, the minimum compressive principal stress, σ3, and the intermediate stress, σ2 (left). Shearfractures are created under high differentialstress and in conjugate pairs, forming an acute angle with σ1. Tension fractures, a termsometimes used interchangeably with extensionfractures, form perpendicular to σ3 and atrelatively low differential stresses, when thevalue of σ3, after adjustment for pore pressure—the local effective stress—is likely tensile. In thelaboratory, it is common to observe the creationof tension fractures during compressionexperiments at low confining pressures and inassociation with shear fracturing.15

Shear and tension fractures described fromlaboratory experiments have clear counterpartsthat occur naturally; shear fractures correspondto faults, whereas tension fractures corre spondto joints.16 This mechanically based distinction

provides a useful way to classify fractures. Mostfaulting occurs during significant tectonic eventswhen the differential stress is high. Tectonicfaults typically occur over a broad range ofscales, with displacements that range frommillimeters to kilometers. Seismic imagesgenerally allow the detection of the larger faults,while borehole data are required to identify andcharacterize smaller faults. Tectonic faultstypically cut unimpeded through stratigraphyand are therefore termed non-stratabound.

Joints, or fractures having no visible displace -ment, form perpendicular to bedding. Joints canbe either stratabound or non-strata bound.Stratabound joints stop at bedding surfaces andoften develop a regular spacing and form well-organized connected networks in plan view.Commonly, there is a long and continuous set ofjoints, termed systematic joints, which are joinedby a perpendicular array of cross joints that abut the systematic joints.17 Non-strataboundjoints occur on a wide range of scales and arespatially clustered.18

5. Aston MS, Alberty MW, McLean MR, de Jong HJ andArmagost K: “Drilling Fluids for Wellbore Strengthening,”paper IADC/SPE 87130, presented at the IADC/SPEDrilling Conference, Dallas, March 2–4, 2004.Morita N, Black AD and Guh G-F: “Theory of LostCirculation Pressure,” paper SPE 20409, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September 23–26, 1990.

6. Ivan C, Burton J and Bloys B: “How Can We BestManage Lost Circulation?” paper AADE-03-NTCE-38,presented at the AADE National Technology Conference“Practical Solutions for Drilling Challenges,” Houston,April 1–3, 2003.

7. Inaba M, McCormick D, Mikalsen T, Nishi M, Rasmus J,Rohler H and Tribe I: “Wellbore Imaging Goes Live,”Oilfield Review 15, no. 1 (Spring 2003): 24–37.Cheung P, Hayman A, Laronga R, Cook G, Flournoy G,Goetz P, Marshall M, Hansen S, Lamb M, Li B, Larsen M,Orgren M and Redden J: “A Clear Picture in Oil-BaseMuds,” Oilfield Review 13, no. 4 (Winter 2001/2002): 2–27.Bargach S, Falconer I, Maeso C, Rasmus J,Bornemann T, Plumb R, Codazzi D, Hodenfield K, Ford G,Hartner J, Grether B and Rohler H: “Real-Time LWD:Logging for Drilling,” Oilfield Review 12, no. 3 (Autumn 2000): 58–78.

8. Al-Anzi E, Al-Mutawa A, Nasr-El-Din H, Alvarado O,Brady M, Davies S, Fredd C, Fu D, Lungwitz B, Chang F,Huidobro E, Jemmali M, Samuel M and Sandhu D:“Positive Reactions in Carbonate Reservoir Stimulation,”Oilfield Review 15, no. 4 (Winter 2003/2004): 28–45.

9. Diversion is a technique used in injection treatments toensure uniform distribution of treatment fluid across thetreatment interval. Injected fluids tend to follow the pathof least resistance, such as an open natural fracture,possibly resulting in the least permeable areas receivinginadequate treatment. By using some means of diversion,the treatment can focus on the areas requiring the mosttreatment. To be effective, the diversion effect should betemporary to allow full restoration of well productivitywhen the treatment is complete.

10. Al-Anzi et al, reference 8.Albuquerque MAP, Ledergerber AG, Smith CL andSaxon A: “Use of Novel Acid System Improves ZonalCoverage of Stimulation Treatments in Tengiz Field,”paper SPE 98221, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, USA, February 15–17, 2006.

11. Samuel M, Polson D, Graham D, Kordziel W, Waite T,Waters G, Vinod PS, Fu D and Downey R: “ViscoelasticSurfactant Fracturing Fluids: Applications in Low-Permeability Reservoirs,” paper SPE 60322, presented atthe SPE Rocky Mountain Regional Low PermeabilityReservoirs Symposium and Exhibition, Denver,March 12–15, 2000.Samuel M, Card RJ, Nelson EB, Brown JE, Vinod PS,Temple HL, Qu Q and Fu DK: “Polymer-Free Fluid forHydraulic Fracturing,” paper SPE 38622, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 5–8, 1997.Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20–33.

12. Lorenz JC: “Stress-Sensitive Reservoirs,” paper SPE 50977, Journal of Petroleum Technology 51, no. 1(January 1999): 61–63.

13. http://www.naturalfractures.com/ (accessed April 20, 2006).14. Stearns DW and Friedman M: “Reservoirs in Fractured

Rock,” in King RE (ed): Stratigraphic Oil and Gas Fields—Classification, Exploration Methods and Case Histories,American Association of Petroleum Geologists,Memoir 16. Tulsa: AAPG (1972): 82–106.

15. Engelder T: Stress Regimes in the Lithosphere. Princeton, New Jersey, USA: Princeton University Press (1993): 24–25.

16. Pollard DD and Aydin AA: “Progress in UnderstandingJointing over the Past Century,” Geological Society ofAmerica Bulletin 100, no. 8 (1988): 1181–1204.

17. Gross MR: “The Origin and Spacing of Cross Joints:Examples from the Monterrey Formation, Santa BarbaraCoastline, California, Journal of Structural Geology 15,no. 6 (June 1993): 737–751.

18. Odling NE, Gillespie P, Bourgnie B, Castaing C, Chilés J-P,Christensen NP, Fillion E, Genter A, Olsen C, Thrane L,Trice R, Aarseth E, Walsh JJ and Watterson J:“Variations in Fracture System Geometry and TheirImplications for Fluid Flow in Fractured HydrocarbonReservoirs,” Petroleum Geoscientist 5, no. 4(November 1999): 373–384.

> Principal stresses and the creation offractures. The diagram shows the directions of the three principal stresses—maximumcompressive principal stress, σ1, the minimumcompressive principal stress, σ3, and theintermediate stress, σ2. The resultant fracturingis also indicated. Tension fractures (green) formparallel to σ1 and σ2. The acute angle that formsbetween two shear fractures (red) is called theconjugate angle. The angle that forms betweenthe shear fracture and σ1 is called the dihedralangle. An obtuse angle forms between the shearfracture and σ3, while the shear fractures areparallel to σ2.


The origin of joints is often difficult todetermine, but it is known from rock mechanicsthat they occur at low effective σ3. Truly tensilestress occurs at shallow depths, so some jointsform close to the surface. However, at reservoirdepths, joints can probably form only under highfluid pressure, a process similar to hydraulicfracturing during well stimulation.

As joints do not involve displacement thatoffsets bedding, they cannot be directly observedon seismic images, but can be located andcharacterized by well-log data and boreholeimages (above). While it is relatively simple for ageologist to distinguish faults and joints at anoutcrop, the distinction is often less clear usingsubsurface data, as stratigraphic offsets may notbe resolvable. Geologists may therefore have torely on a number of criteria, such as fracture fill,orientation and spatial distribution, to deter mine

whether fractures of a given set are likely to befaults or joints. It may be necessary in such casesto develop a pragmatic classification systembased on observed properties of the fractures.

Other types of fractures are created byvolume-reduction mechanisms within the rockand not from external forces. These includedesiccation cracks, syneresis fractures, thermalcontraction fractures and mineral phase-changefractures. Of these, syneresis, or chicken-wirefractures, and mineral phase-change fractures incarbonates have the greatest importance in oiland gas production. Syneresis fractures areformed by a chemical process that causesdewatering and associated volume reduction.

Carbonate rocks are easily dissolved infreshwater or aggressive fluids and thedissolution is often concentrated to form caves or

vugs. The resulting porosity is termed karst andis important in many fractured carbonatereservoirs. Maps of karst often show that theporosity is most strongly enhanced along theplanes of preexisting fractures and so clarifyingthe underlying fracture system can often help inunderstanding karst systems.

Because carbonates dissolve relatively easilyunder pressure, they have a tendency to formstylolites—uneven surfaces of insoluble residue—that form perpendicular to σ1. Stylolites may causelocal permeability reduc tion, or alternatively theymay facilitate subse quent dissolution and perme -ability increase. Tension gashes, or fracturingassociated with stylolites, are common (next page,top).19 While tension gashes may contribute topermeability measured in core, their subsurfaceimpact on reservoir producibility is thought to be minimal.

A genetic classification system examines howfractures relate to the formation and thestructure in which they are located. The creationof endogenetic fractures relates to the stressesduring sedimentation, for example cleating incoals. Exogenetic fractures are formed aftersedimentation and lithification, usually fromtectonic stresses caused by folding and faulting.Once natural-fracture systems have beenclassified in both geologic and engineeringterms, the next step is to investigate their impacton the reservoir.

Classifying Fractured ReservoirsMost, if not all, reservoirs contain fractures. It isthe degree to which fractures influence fluid flowthrough a reservoir that should dictate the levelof resources needed to identify, characterize andmodel fractures. The effects of fractures canchange throughout the productive life of thereservoir as pressures and fluid types changeduring primary- and secondary-recovery stages.Moreover, fractures don’t always conduct fluid;they are often barriers to flow. Fracturedreservoirs are classified based on the interactionbetween the relative porosity and permeabilitycontributions from both the fracture and matrixsystems (next page, bottom).20

In Type 1 reservoirs, fractures provide boththe porosity and permeability elements. Type 2reservoirs have low porosity and low permeabilityin the matrix, and fractures provide the essentialpermeability for productivity. Type 3 reservoirshave high porosity and may produce withoutfractures, so fractures in these reservoirs provideadded permeability. Type M reservoirs have highmatrix porosity and permeability, so openfractures can enhance permeability, but natural

8 Oilfield Review

> Example of low-angle nonsystematic fractures in shales. FMI Fullbore Formation MicroImagerimages clearly show both fracturing (blue sinusoids in Track 3 and tadpoles in Track 4) and formationbedding (green sinusoids and tadpoles). Track 1 displays caliper, borehole orientation and gamma raydata. Tracks 2 and 3 show the FMI static and dynamic images, respectively. Dip tadpoles arepresented in Track 4.

X70.2

X70.4

X70.6

X70.8

X71.0

X71.2

X71.4

X71.6

X71.8

X72.0

0 120 240 360

FMI Static ImageResistive Conductive

Orientation North0 120 240 360

FMI Dynamic ImageResistive Conductive

Orientation North

gAPI0 200

Gamma Ray

Bit Size

Caliper 2

mm125 375

mm125 375

mm125 375

Caliper 1

deg0 90

Bedding True Dip

deg0 90

Fracture True Dip

deg0 90

Borehole Drift

Dept

h, ft


Summer 2006 9

fractures often complicate fluid flow in thesereservoirs by forming barriers. Fractures add nosignificant additional porosity and permeabilityto Type 4 reservoirs, but instead are usuallybarriers to flow. Another reservoir class, Type G,has been created for unconventional fracturedgas reservoirs, such as CBM, and fractured gas-condensate reservoirs. Most Type G reservoirs fallwithin or near the Type 2 reservoir classification.

Before NFR classification can be done in anymeaningful way, both natural-fracture andmatrix systems within a reservoir must beunderstood, along with the complex flowinteraction between those systems. Many factorsaffect fluid flow within a NFR, including present-day stress orientation, natural-fracturedirections, whether the fractures are mineral-filled or open, reservoir fluid properties andphases, and the production and injection historyof the field. While many of these factors cannotbe controlled, some problems can be mitigated.Field-development strategies can therefore betailored to the natural-fracture systems tooptimize production and recovery. The soonerthis knowledge is acquired, the more preparedasset teams will be to make important field-management decisions early in field development.

Evaluating Fractures and FieldsThere are many different ways to characterizenatural fractures and to evaluate their role inreservoir exploitation. Dynamic methods seek tocharacterize the effects of fractures bymeasuring or directly describing the movementof fluids through fractures and matrix. Thesedynamic methods include medium-scale interval,pressure-transient testing, which providesinformation on fractures and fracture-relatedflow, and estimates of fracture conductivity.21

These tests can be obtained with the MDTModular Formation Dynamics Tester. Anothermedium- to large-scale dynamic method usesinjected tracers and water-composition analysisto determine direct communication attributed tofractures between zones and between wells.

19. Stylolites are wave-like or tooth-like, serrated, interlockingsurfaces, most commonly seen in carbonate and quartz-rich rocks, that contain concentrated insoluble residuesuch as clay minerals and iron oxides. Stylolites arethought to form by pressure solution, a dissolutionprocess that reduces pore space under pressure during diagenesis.For more on stylolites: Nelson, reference 1: 163–185.

20. Nelson, reference 1: 101–124.21. Jackson RR, Xian C, Carnegie A, Gauthier P and

Brooks AD: “Application of Interval Pressure TransientTesting with Downhole Fluid Analysis for CharacterisingPermeability Distributions, In-Situ Flow Fractions andWater Cut,” paper SPE 92208, presented at the SPEInternational Petroleum Conference, Puebla, Mexico,November 7–9, 2004.

> Cross section of a stylolite. Stylolites are diagenetic features commonlyfound in low-permeability carbonate rocks. They form as irregular surfacesbetween two layers and are generally thought to be the result of pressuresolution under a state of differential stress. Stylolites normally inhibitsubsurface fluid flow, but are often associated with small fractures calledtension gashes, which sometimes appear permeable on core tests.

inch0

0 1

1

cm

> Naturally fractured reservoir classification system. Type 1 reservoirs,with fractures providing both primary porosity and primary permeability,typically have large drainage areas per well, and require fewer wells fordevelopment. These reservoirs show high initial production rates. They arealso subject to rapid production decline, early water breakthrough anddifficulties in determining reserves. Type 2 reservoirs can have surprisinglygood initial production rates for a low-permeability matrix but can havedifficulties during secondary recovery if the communication between thefracture and the matrix is poor. Type 3 reservoirs are typically morecontinuous and have good sustained production rates but can havecomplex directional permeability relationships, leading to difficulties duringthe secondary-recovery phase. Type M reservoirs have impressive matrixqualities but are sometimes compartmentalized, causing them tounderperform compared with early producibility estimates, and makingsecondary-recovery effectiveness variable within the same field. Type 4reservoirs would plot near the origin because the fracture contribution topermeability in Type 4 reservoirs is negative. (Adapted from Nelson,reference 1: 102.)

Tota

l per

mea

bilit

y, %

Total porosity, %

Increasing natural-fracture influence(decreasing matrix influence)

100% matrixpermeability

100% fracturepermeability

100% matrixporosity

100% fractureporosity

Type 3

Type M(matrixonly)

Type 2Type

Type 4

1Type G


Geometric methods measure specific attri -butes to identify and characterize naturalfractures and assess their potential impact onproduction or injection. While traditional loggingmeasurements, such as caliper and microresis -tivity logs, can allude to the presence of naturalfractures, they are generally not quantitative.Today, various technologies have been developed

to address NFRs. The most common small-scale,log-based fracture-evaluation techniques useultrasonic and resistivity borehole imagingtechnologies that can be deployed by wireline orLWD methods.

While the resolution of wireline-conveyedelectrical borehole imaging tools is exceptional,the most detailed way to assess NFRs is by

acquiring fullbore cores across intervals ofinterest.22 Having access to fullbore core allowsgeologists and petrophysicists to examine specificproperties that influence a fracture’s ability toconduct fluids—for example, the presence of in-filling minerals. Another extremely valuable useof core data is to provide a “ground truth” fromwhich to calibrate other fracture-analysismethods. However, fullbore coring can beexpensive and poor core recovery can be aproblem in highly fractured rock. Also, coring-induced fractures can be difficult to distinguishfrom unmineralized natural fractures.23 Despitethe difficulties, there are now innovative ways tocharacterize NFRs using advanced technologiesand processing techniques.

The fractured granite basement rocks of theCuu Long basin, offshore Vietnam, are mostlyType 1 reservoirs—both porosity and perme abilityin the basement rock are provided by naturalfractures (left).24 However, in the fractured zonessurrounding faults, secondary porosity has beendocumented because hydrothermal fluids dissolvefeldspars in the matrix. The result is a hybrid Type 2/Type 1 NFR.

Since first production in the early 1990s,common methods for measuring permeability—the most daunting property to ascertain in thesefractured basement reservoirs—were performingwell tests or acquiring and testing core. Well-testanalysis of fractured reservoirs requiresnumerous assumptions that can lead to errors,while core analysis is typically pessimisticbecause the most highly fractured reservoirintervals often are not recovered and analyzed.

Even though Cuu Long reservoirs rely solelyon fractures to produce, their productivity canbe astonishing—some individual wells canproduce more than 20,000 bbl/d [3,180 m3/d] ofoil. A series of geologic episodes, including anextensional phase during rifting, which createdthe basin, followed by two major phases ofcompression, has led to a complex but prolificnatural-fracture network that can be dividedinto three fracture classes—solution-enhancedand unenhanced bounding fractures, straight-walled fractures and discrete fractures (nextpage, left).25

When not filled with clays, calcite andzeolites, the bounding network of fractures formsthe main conduits for fluid transmission andprovides important storage volume for thebasement reservoirs.26 Some of the boundingfractures are enormous, measuring more than 1.5m [4.9 ft] in fracture width. On the other hand,

10 Oilfield Review

25. Bounding fractures are defined as fractures on whichother fractures terminate.

26. Zeolites are microporous crystalline solids with well-defined structures. Generally, they contain silicon,aluminum and oxygen in their framework, and cations,and water or other molecules within their pores. Fromhttp://www.bza.org/zeolites.html (accessed April 30, 2006).

27. To compute fracture apertures, shallow-resistivity dataare needed to calibrate, or scale, the FMI or FormationMicroScanner tool response. For more on the technique:Luthi SM and Souhaite P: “Fracture Aperture fromElectrical Borehole Scans,” Geophysics 55, no. 7 (1992):821–833.

22. Lorenz JC and Hill R: “Measurement and Analysis ofFractures in Core,” in Schmoker JW, Coalson EB andBrown CA (eds): Geophysical Studies Relevant toHorizontal Drilling: Examples from North America.Denver: Rocky Mountain Association of Geologists(1994): 47–57.

23. Lorenz JC, Warpinski NR and Teufel LW: “NaturalFracture Characteristics and Effects,” The LeadingEdge 15, no. 8 (August 1996): 909–911.

24. Li B, Guttormsen J, Hoi TV and Duc NV: “CharacterizingPermeability for the Fractured Basement Reservoirs,”paper SPE 88478, presented at the SPE Asia Pacific Oiland Gas Conference and Exhibition, Perth, Australia,October 18–20, 2004.

> Location of the Cuu Long basin, offshore Vietnam. Fracture swarms in a granite outcrop along LongHai Beach, Vietnam, are an offshore analog of the field (photograph). Fracture swarms run parallel tothe beach for 300 to 400 m [984 to 1,312 ft]. The relative lack of published stress data makes it evenmore important to acquire usable stress data when possible (bottom right). (Stress map insert is fromthe World Stress Map Project, http://www-wsm.physik.uni-karlsruhe.de/pub/casmo/content_frames/stress_maps_frame.html, used with permission.)

2000 miles

0 200km

Hanoi

Da Nang

Ho ChiMinh City

Cuu Long Basin

V I E T N A M

Vietnam

S o u th

Ch i

n a S

ea


Summer 2006 11

the majority of discrete fractures are relativelyshort, terminate at the bounding fractures,contribute the majority of the storage capacity tothe bounding networks, and maintain aperturesthat mostly range from 0.01 to 0.1 mm [0.0004 to0.004 in.].

In the fields of the Cuu Long basin, perme -ability is the driving factor for well productivity.Using FMI image data, geoscientists fromSchlumberger, Cuu Long Joint OperatingCompany (JOC) and VietSovPetro developed amethod to consistently calculate reservoirpermeability and calibrate it to core analysis, well-testing results and production-log data. First,fracture interconnectivity is assessed using theimage data and the BorTex texture classificationtool in the Schlumberger GeoFrame integrated

reservoir characterization system platform. Thisprocessing essentially maps out the conductiveanomalies within the resistive granite matrix onthe borehole image and computes a relativepermeability indicator (RPI).

In another processing step, fractureapertures and fracture density are calculated forhand-picked fractures on the FMI resistivityimages.27 These outputs, along with a calibrationconstant, are used to calculate fracturepermeability (Kf). In Type 1 reservoirs, Kf shouldequal reservoir permeability (Kr) for the sameinvestigated volume. The RPI can then be scaledto Kr to provide a continuous assessment ofpermeability. The limited amount of core takenin a zone of relatively low permeability was usedto calibrate Kr (above right).

This image-based interpretation techniquehas been successful on numerous wells acrossthe Cuu Long basin. For example, on one well,300 m [984 ft] of the granite basement rock waspenetrated at a top depth of around 3,900 m[12,800 ft]. A standard openhole-logging suitewas acquired along with FMI images and only 3 m[9.8 ft] of fullbore core. After initial production,dynamic fracture-characterization methods wereemployed on two occasions—shortly after thewell was completed and again after 17 months ofproduction—and included well testing andproduction logging.

> Fracture-classification system used in the Cuu Long basin. The FMI image (left) shows thetwo main fracture types. The fracture flow system relationships for each type are described forthe discrete fracture system (top right) and the solution-enhanced system (bottom right).

X,Y84

Fracture Flow-System Relationships

Discrete Fracture System (Secondary)•Tectonic only•Low permeability•Short length•Short height

stress•Fine aperture—subject to principal

•Highly tortuous flow paths•Secondary production conduits (behave like a matrix-porosity system)

X,Y85

X,Y86

X,Y87

X,Y88

Solution-Enhanced System (Primary)•Tectonic modified by hydrothermal and meteoric processes•High permeability•Long length•Tall height•Large aperture•Linear to radial flow paths•Primary production conduits

0 120 240 360Orientation NorthDe

pth,

mResistive Conductive

FMI Image

> Calibration and validation of reservoirpermeability (Kr) using 3 m of core data(left). The computed permeability log sectionon the right shows the high-permeabilityzones (yellow) that contributed to flowduring production logging and well testing.These zones had an average permeabilityfrom well testing of 69 mD. The continuouscomputed Kr across the same intervalsaveraged 92 mD.

0.1 1,000mD

Core Permeability

Permeability

0.1 1,000mD

Core Permeability

0.1 1,000mD

0.1 1,000mD

1 m Estim

ated

ave

rage

per

mea

bilit

y fo

r the

con

tribu

ting

zone

s is

69

mD.

Permeability

Permeability

FracturePermeability


A correlation between the calculated perme -abilities and actual reservoir performance was verygood (below). Initially, oil flowed from three zonesas demonstrated by the production log, but therewere several high-permeability zones that did notcontribute. Experts at Cuu Long JOC andVietSovPetro suspected that the lack ofcontribution was caused by partial formationdamage, since mud losses were recorded duringdrilling, for example from X,090 to X,100 m.Reassuringly, after 17 months of production, otherzones began to contribute to production. Over

time, the damaged zones cleaned up withassistance from the pressure drop in the wellbore.In addition, the water cut had increased since thestart of production.

This technique has helped to minimize thecomplicating effects that resistive fracture-fillingminerals have on fracture characterization in thefields of the Cuu Long basin. However, conductiveminerals in the fractures, found mainly inweathered zones at the top of the granite, stillpose a dilemma because resistivity-based imagingtools cannot differentiate between conductiveminerals and conductive drilling fluid. In these

zones, special attention is paid to corroborativedata—mud-loss records, gas shows and log datafrom the MDT or CMR Combinable MagneticResonance tools. Importantly, this fracture-characterization technique provides a detailed,depth-continuous permeability output that canhelp asset teams with individual well stimulationand completion and injection designs, and can be upscaled to reservoir models across an entire field.

12 Oilfield Review

> Integrated fracture permeability analysis showing a comparison of computed permeability to production logging and well-testing results. Standardopenhole-log data are displayed in Tracks 1 and 2, FMI images are shown in Track 3, fracture apertures calculated from the FMI data are presented inTrack 4, Kf and RPI are shown in Track 5, and Kr with core-calibration points is displayed in Track 6. The yellow box in the Depth Track indicates thelocation of significant mud losses during drilling. Tracks 7 and 8 include the interpreted production-log results in the first well-testing job shortly after thewell was drilled. Track 9 presents the interpreted production-log rate, showing zones that contributed water (blue) and oil (red) from the second well-testing job, performed after the well had been on production for 17 months.

0 120 240 360

FMI DynamicImage

Res. Cond.

Orientation North

0.45 -0.15 2 20,000m3 3/m ohm.m

Neutron Porosity

Dept

h, m

X,000

X,100

1.95 2.95 2 20,000ohm.m

Bulk Density Shallow Laterolog

g/cm3

0.1 1,000mD

Core Permeability

Permeability

0.009 0.5

RelativePermeability

Indicator

1 10,000mD

FracturePermeability

0.00001 0.1

Fracture Aperture

cm

Flow Rate

0 4,000bbl/d

Oil Rate, bbl/d WaterRate,bbl/d

OilRate,bbl/d

1,058

784

169

483

132

232

860

452

119

301

106

854

276

Deep Laterolog

6 16

Caliper

in.

0 200

Gamma Ray

gAPIPermeability

0.1 1,000mD


Summer 2006 13

Fractures in the Rocky MountainsHydrocarbon production from low-porosity, low-permeability, hard-rock reservoirs depends onsuccessfully connecting open fracture networksto the wellbore. Because the matrix quality isgenerally low, the surface area exposed to thewellbore along fracture planes often must beincreased for required production volumes. Thisis accomplished by performing hydraulic fracturestimulation. Open natural fractures contribute toproduction but can also cause problems duringdrilling, cementing, completion and stimulationoperations. Therefore, it is essential to identifyfractured intervals for cement- and stimulation-staging considerations.

A powerful combination of high-resolutionborehole imaging and innovative acousticmeasurements from the Sonic Scanner acousticscanning platform adds dynamic elements todetailed fracture analysis from wireline tools.28

Schlumberger geoscientists and petrophysicistsin the Rocky Mountain region, USA, use Stoneleyand dipole flexural-wave data from the SonicScanner tool and FMI image data to clearlyidentify formation bedding, sedimentary featuresand fractures.29 The improved low-frequencyStoneley response—down to 300 Hz—of theSonic Scanner tool enables the detection of high-angle to vertical fractures. Also, using anattenuation technique called normalizeddifferential energies (NDE) makes it possible todifferentiate natural fractures from drilling-induced fractures, even when they are orientedin the same direction—usually parallel to thepresent-day maximum horizontal-stress direction.However, when the stress-related anisotropydirection differs only slightly from the fracture-induced anisotropy direction, the new tool is still able to differentiate the two because of the improved ability to resolve small amountsof anisotropy—now 2%, versus 5% with theprevious technology.

Frequency-content and signal-strengthvariations occur in naturally fractured intervals.Another processing technique called slowness-frequency analysis (SFA) allows the interpre -tation of dipole flexural-wave frequency andamplitude data and shows the quality of theestimation of shear slowness from flexural-wavedispersion analysis up to several feet into theformation from the wellbore.

In the Type 2 reservoirs in the RockyMountains, porosities range from 3 to 7% andmatrix permeabilities are in the microdarcies.The FMI tool enables the calculation of fractureaperture, fracture porosity, fracture density andfracture trace length at the wellbore.30

Combining independent fracture-characterizationmethods from the Sonic Scanner Stoneley-waveand shear-wave analysis with FMI imageinterpretation shows an unambiguous assessmentof fracturing across the interval (above). Armedwith this log-based characterization of thefractures, the asset team can better judge theoptimal way to cement, complete and stimulatethis potentially productive interval.

Experts in the Rocky Mountain region havedeveloped a hard-rock completion solution thatcombines Sonic Scanner data with FMI data tooptimize hydraulic fracture design. The solutionincorporates natural-fracture characterization—including the determination of fracture aperture,fracture permeability and fracture extent—and

the analysis of maximum and minimum hori -zontal stresses. All this information is capturedin the mechanical earth model that is used bystimulation designers to optimize hydraulicfracture design.

28. Arroyo Franco JL, Mercado Ortiz MA, De GS, Renlie Land Williams S: “Sonic Investigations In and Around theBorehole,” Oilfield Review 18, no. 1 (Spring 2006): 14–33.

29. Donald A and Bratton T: “Advancements in AcousticTechnique for Evaluating Open Natural Fractures,”Transactions of the SPWLA 47th Annual LoggingSymposium, Veracruz, Mexico, June 4–7, 2006, paper QQ.

30. Hornby B and Luthi S: “An Integrated Interpretation ofFracture Apertures Computed from Electrical BoreholeScans and Reflected Stoneley Waves,” in Hurst A,Griffiths C and Worthington P (eds): GeologicalApplications of Wireline Logs II, Geological SocietySpecial Publication 65. London: The Geological Society(1992): 185–198.

> Fracture characterization using Sonic Scanner and FMI data. Borehole anisotropy analysis includesthe slowness-frequency analysis (SFA) and slowness-time-coherence (STC) projections for the fastinline and slow inline waveforms. In Track 2, the anisotropy magnitude and direction vary with depth,ranging from more than 16% (red) to less than 2% (blue). The high-anisotropy zones correspond tozones with fractures visible on the FMI image in Track 7. Minimum and maximum offline energydifferences are displayed in the Depth Track from the shear-wave anisotropy analysis. Largedifferences between measured Stoneley slowness and slowness modeled for an elastic, impermeableformation are observed in Track 3. Fracture-aperture computations from the Sonic Scanner reflectionand attenuation analysis in Track 4 are compared with fracture apertures calculated on hand-pickedfractures in Track 5 from the FMI image in Track 7. Track 6 displays the Stoneley Variable Density log.

300 µs/ft 0

∆T-Based Fast Shear

X,100

X,200

X,300

X,400

0 100

0 100

MaximumEnergy

MinimumEnergy

Dept

h, ft

Modeled Stoneleyµs/ft250 150

S-Se

Washout

Caliperin.4 14

Bit Sizein.4 14

∆T Stoneley

µs/ft250 150

Stoneley Aperture

Fracture Widthin.0 0.5

Stoneley Permeability

Fracture Trace Length1/ft10 0

Fracture Porosityft3/ft30.1 0

Fracture PermeabilitymD100,000 1010

µs0 20,440

Stoneley VariableDensity Log

0 120 240 360

Resistive ConductiveFMI Image

OfflineEnergy

Orientation North-90 90deg

Fast ShearAzimuth

2 4 6 160

Anisotropy Flag, %

Shear Difference

300 µs/ft 0

∆T-Based Slow Shear

200 %

%

Time-Based Anisotropy0

300 µs/ft 0

Compressional ∆T

300 µs/ft 0

Stoneley ∆T0

∆T-Based Anisotropy200

AzimuthUncertainty


Coalbed Methane ReservoirsThere may be no other NFR as difficult to stimulate as a coalbed methane (CBM)reservoir, an unconventional but growing sourceof methane. Beginning with its deposition aspeat, coal is a unique reservoir rock. To beproductive, coalbed reservoirs require naturalfractures. Vertical natural fractures in coal arecalled cleats, and these form during coalifi -cation. Systematic coal cleats are classifiedgeometrically with the primary, more continuous

fracture set called face cleats and thesecondary, less continuous fracture set calledbutt cleats (below).

Coal fractures can also be classifiedgenetically. Endogenetic fractures, or classiccleats, are created under tension as the coalmatrix shrinks because of dewatering anddevolatilization during coalification. These cleatsets are orthogonal and nearly always perpen -dicular to bedding. In contrast, exogeneticfractures form due to tectonism, and regional

stress fields dictate their orientation. Shearfractures also are observed in some coals. Cleatsare the primary permeability mechanism invirtually all CBM reservoirs, so understandingcleating and natural fracturing in coals is criticalduring all facets of CBM reservoir development.

Methane is stored in coal by adsorption, aprocess by which the individual gas moleculesare bound by weak electrical forces to the solidorganic molecules that make up the coal. Coal’s ability to store methane largely reduces

14 Oilfield Review

> Examples of Canadian coals on FMI images and outcrops. The FMI image (top left) and a photograph from a representativeoutcrop (bottom left) of the Alberta Plains coal show both face and butt cleats. Shear fractures, face cleats and butt cleats areshown on both the FMI image (top right) and the outcrop photograph (bottom right) of the Alberta Foothills coal. Interestingly,shear fractures usually degrade coal permeability.

Alberta Foothills Coal

gAPI0 150

GammaRay

mm125 375

Bit Size

Calipermm125 375

0 90

0 120 240 360

deg

Bedding True Dip

Face Cleat

deg0 90


Orientation North

Mea

sure

d de

pth,

m

Face cleat

Shearfractures

X,X20

X,X21

X,X22

Face cleatButt cleat

Shear fractureBedding

Foothills Coal

Alberta Plains Coal

gAPI0 150

GammaRay

mm 375Bit Size

Caliper

mm 375

deg0 90

Bedding True Dip

Face Cleat

0 120 240 360 deg0 90

Mea

sure

d de

pth,

m

Orientation North


X,X59

X,X60

125

125

Face cleat

Butt cleat

Plains Coal


Summer 2006 15

the need for conventional reservoir-trappingmechanisms, making coal’s gas content—whichincreases with increasing coal rank—and thedegree of cleating or natural fracturing theoverriding considera tions when assessing anarea for CBM production potential.31

This storing ability gives coals unique early-time production behavior that is related todesorption, not pressure depletion. Coals maycontain water or gas, or both, in the cleat andnatural-fracture systems, in addition to gassorbed onto the internal surface of the coalmatrix. Any water present in the cleat systemmust be produced to reduce the reservoirpressure in the cleat system before significantvolumes of gas can be produced. Dewateringincreases the permeability to gas within thecleats and fractures, and causes the gas in thematrix to desorb, diffuse through the matrix andmove into the cleat system, resulting in CBMproduction profiles that are unique bycomparison with other fractured reservoirs.

In most CBM reservoirs, water production isinitially high. As the water moves out of the cleatsand fractures, gas saturation and productionincrease and water production decreases. Thespeed at which the reservoir dewaters depends onseveral factors, including original gas and watersaturations, cleat porosity, relative and absolutepermeability of the coal, and well spacing. Whenpermeability to gas eventually stabilizes, the coalis considered dewatered and gas productionpeaks. From this point, both water and gasproduction slowly decline, with gas being thedominant produced fluid.

In just a few years of development, CBM gasproduction in Alberta, Canada, has surpassed300 million ft3/d [8.50 million m3/d]. Most of thisproduction comes from the Horseshoe Canyon andMannville coal zones, and a small percentage—less than 1%—comes from the Ardley coals in theUpper Cretaceous Scollard formation (above).The less-exploited Ardley coals, however, are asignificant potential CBM resource, exceeding40 trillion ft3 [1.13 trillion m3].

Burlington Resources, now ConocoPhillips,has investigated the Ardley coals using the FMItool.32 In two wells, the borehole images haveallowed geoscientists at ConocoPhillips andSchlumberger to determine the present-daystress regime from drilling-induced fractures,which are oriented northeast to southwest, in the direction of maximum horizontal stress. This direction is consistent with previousassessments.33 The FMI images have alsoprovided insight into the nature and direction of

> Maps showing the distribution of Alberta coals (left), thickness of the Ardley coal (top right) andpublished stress data (bottom right). The map on the left shows the area of the Ardley coal play (red)where the Ardley coal thickness is greater than 12 m [39.4 ft]. (Stress map insert is from the WorldStress Map Project, http://www-wsm.physik.uni-karlsruhe.de/pub/casmo/content_frames/stress_maps_frame.html, used with permission.)

Alberta

Alberta

Calgary

Edmonton

km

miles0

0 200

200

Edmonton

km

miles0

0 100

100

Ardley coal thickness0 to 6 m

6 to 12 m

>18 m

12 to 18 m

31. Anderson J, Simpson M, Basinski P, Beaton A, Boyer C,Bulat D, Ray S, Reinheimer D, Schlachter G, Colson L,Olsen T, John Z, Khan R, Low N, Ryan B andSchoderbek D: “Producing Natural Gas from Coal,”Oilfield Review 15, no. 3 (Autumn 2003): 8–31.

32. Schoderbek D and Ray S: “Reservoir Characterization of Ardley Coals, Scollard Formation, Alberta: BoreholeImage Interpretation,” presented at the AAPG AnnualMeeting, Calgary, June 16–19, 2005.

33. Bell JS, Price PR and McLellan PJ: “In-Situ Stress in theWestern Canada Sedimentary Basin,” in Mossop GD andShetson I (compilers): Geological Atlas of the WesternCanada Sedimentary Basin. Calgary: Canadian Societyof Petroleum Geologists and Alberta Research Council(1994): 439–446.


cleating within the Ardley coals—the Val D’Or,the Arbour, the Silkstone and the Mynheer zones(above). Interpretation of FMI images suggestedthat within the Scollard formation, the Silkstonecoal had the most productive potential and theArbour coal had some potential.

ConocoPhillips integrated public andproprietary cleat-orientation information frommines and outcrops. In addition, geoscientists

performed a detailed examination of sixunoriented conventional cores that were cutfrom the Ardley coals five to ten years earlier. Tosupplement the regional study of Ardley coalcleating, these cores had to be oriented after thefact, years after their acquisition. To accomplishthis, ConocoPhillips utilized a techniquedeveloped by Applied Paleomagnetics calledpaleomagnetic core orientation, which requires

that whole cores be reassembled and that plugscut from the core be selectively demagnetized.34

The cores are oriented using the secondarymagnetization of magnetite found in nearly allrocks. This magnetization points to present-daygeographical north and represents the averagegeomagnetic field over the past 780,000 years,which is the time since the last geomagneticpolarity reversal. Once the north direction on the

16 Oilfield Review

34. Bleakly DC, Van Alstine DR and Packer DR: “CoreOrientation 1: Controlling Errors Minimizes Risk and Cost in Core Orientation,” Oil and Gas Journal 83, no. 48(December 2, 1985): 103–109.Bleakly DC, Van Alstine DR and Packer DR: “CoreOrientation 2: How to Evaluate Orientation Data, QualityControl,” Oil and Gas Journal 83, no. 49 (December 9,1985): 46–54.

Hamilton WD, Van Alstine DR and Butterworth JE: “A Fracture-Orientation Comparison Between Core-Based and Borehole-Imaging Techniques:Paleomagnetic, Electronic Multishot, and FMI,”presented at the AAPG Annual Convention, San Diego,California, May 19–22, 1996.

35. Barkved O, Bartman B, Compani B, Gaiser J, Van Dok R, Kristiansen P, Probert T and Thompson M:

> Images of Ardley coals. The FMI tool successfully identifies cleating, or lack of cleating, in the four Ardley coal zones.The FMI static image of the Val D’Or coal appears very bright (top left), indicating a high degree of mineralization. TheArbour coal image (top right) indicates no large cleats, while the Silkstone coal image (bottom left) shows abundantface cleats, mostly striking northeast to southwest. The Mynheer coal is dominated by shale interbeds (bottom right).

MineralizedVal D’Or

X52.0

X52.5

X53.0

Well-cleatedSilkstone

Y12.5

Y13.0

Y13.5

Y14.0

Small-scalecleating Arbour

X86.5

X87.0

X87.5

ShalyMynheer

Y31.5

Y32.5

Y32.0

gAPI0 200

Gamma Raymm 375125

mm 375125

mm 375125

mm 375125

mm 375125

mm 375125

Bit Size

Caliper 2

Caliper 1

deg0 90

BoreholeDrift

0 360

deg0 90

Bedding True Dip

deg0 90

Fracture True Dip

Dept

h, m 0 120 240 360


Orientation North

FMI StaticImage

Res. Cond.

OrientationNorth

gAPI0 200

Gamma Ray

Bit Size

Caliper 2

Caliper 1

deg0 90

BoreholeDrift

0 360

deg0 90

Bedding True Dip

deg0 90

Fracture True Dip

Dept

h, m 0 120 240 360


Orientation North

FMI StaticImage

Res. Cond.

OrientationNorth

“The Many Facets of Multicomponent Seismic Data,”Oilfield Review 16, no. 2 (Summer 2004): 42–56.Caldwell J, Christie P, Engelmark F, McHugo S,Özdemir H, Kristiansen P and MacLeod M: “ShearWaves Shine Brightly,” Oilfield Review 11, no. 1 (Spring 1999): 2–15.

36. Fracture intensity is a qualitative description of thedegree of natural fracturing that is usually derived fromseismic traveltime attributes.


Summer 2006 17

reassembled core is determined, the results fromthe detailed analysis can then be oriented,yielding orientation data comparable to outcropand mine studies and FMI image analyses (right).

All sources of data indicated that a dominantnortheast-to-southwest face-cleat system mightbe open because of its favorable alignment withthe present-day maximum horizontal stress. Thebutt-cleat system in the Ardley coals is much lesspersistent and is aligned less favorably withrespect to present-day stresses. The lack of buttcleats in Ardley coals is in contrast to HorseshoeCanyon and Mannville coals.

Horizontal wells drilled perpendicular to theface-cleat system may require hydraulicfracturing of multiple intervals within thehorizontal section to effectively stimulate thecoals and optimize production potential. A moreeffective stimulation promotes the dewatering ofthe cleat systems and speeds up gas desorption.The challenging permeability scenario will alsoinfluence well-design considerations, such asdrilling updip to maximize drainage.

Exploration for coalbed methane in theArdley coals of the Scollard formation is in itsinfancy. ConocoPhillips plans to integrate theresults of this cleat study with hydrogeologicaland structural interpretations to develop itsfuture exploration strategy.

A Seismic Net to Capture FracturesThe ability to characterize fracture systems inthe early field-development stage reduceseconomic risk because it enables asset teams todetermine optimal horizontal well directions tomaximize production and recovery. So far, mostof the discussion on fracture characterizationhas dealt with the investigation of fractures usingrelatively high-resolution techniques ascompared to seismic methods, which usewavelengths up to 100 m [328 ft] to detect thepresence of natural fractures using azimuthalanisotropy analysis.35 These techniques do notdetect individual faults or fractures, but ratherexploit the average response across a largevolume of rock. For example, measuringtraveltime differences between the fast and slowshear waves, together with the polarizationdirection of the fast shear wave, helps to inferthe fracture intensity and fracture orientation,respectively.36 Seismic fracture-characterizationmethods include velocity anisotropy determina -tion, azimuthal amplitude variation with offset,and normal moveout (NMO) variation withazimuth (right).

> Determining major cleat directions in the Ardley coals. Paleomagnetic core orientation was used tosupplement the ConocoPhillips Ardley coal database. Rose diagrams showing the cleat strike datafrom the rotated core analysis are displayed on the left side of the map, while the rose diagrams fromthe FMI interpretation are shown to the right of the map. Overall, the data support a northeast tosouthwest face-cleat strike.

Coal cleatsNatural extension fractureNatural shear fractureHigh-angle induced fractureLow-angle induced fractureCleats from FMI tool

Rose Diagram Symbols

Well 6

Well 1 Well 3

Well 4

Well 2

Well 5

FMI cleats

030

60

90

120

150180

210

240

270

300

330

5%

10%

15%

5% 10% 15% 20%

20%Ardley coal thickness

6 to 12 m

>18 m

12 to 18 m

5

2

4

36

1

030

60

90

120

150180

210

240

270

300

330

2%

4%

6%

8%

10%

2% 4% 6% 8% 10%

> Seismic azimuthal anisotropy methods. The diagrams show land and marine seismic acquisitionmethods used to detect fracture-induced anisotropy. The fracture diagram (top left) shows verticalfractures striking north-south in the example, causing shear-wave splitting that helps determine thefast-shear direction (north-south red polarization vectors) and the slow-shear direction (east-west blue polarization vectors). The sinusoid shows how anisotropy can be determined from compressionaland shear velocity variations with azimuth (top right). The land seismic diagram (bottom left) shows therays for common midpoint gathers from two source-receiver directions. The seabed seismic diagram(bottom right) demonstrates the effects of seismic anisotropy by showing two rays: a south-going fastray from a source position to the north of the seabed receiver cable; and a west-going slow ray from an east source position above the seabed receiver cable. In 3D surveys, all azimuth directionsare interrogated.

Velo

city

North South

East West

Azimuth

NESW

Fast shear, NS

Slow shear, WE

Fast

Fast N

S

SlowE

W

Fast NS

Naturalfractures

Naturalfractures

Seabedreceivercable

Slow

SlowE

W


Seismic investigations of NFRs include thosefrom multioffset, multiazimuth vertical seismicprofiles (VSPs). Walkaway- and walkaround-VSPtechniques permit velocity anisotropy andamplitude variation with offset and azimuth(AVOA) analyses at higher resolutions than withsurface seismic methods and can be used tocalibrate surface seismic results. Integrating allavailable data to optimize the VSP configurationis important for extracting high-qualityanisotropy information. This information canthen be used to design 3D surface seismicsurveys to cover areas remote from well control.37

Through the years, geophysicists have notedthat compressional- (P-) wave velocities exhibitedazimuthal variations when processing some 3Dseismic surveys, especially those in areas of hightectonic stress.38 The fast P-wave direction alignswith the maximum compressional stressdirection, parallel to natural fractures resultingfrom the stress. In this simple scenario, the slowP-wave direction would be aligned perpendicularto the fracture strike, and the fracture-fillingfluid would affect the velocity. Azimuthalvariations in other seismic attributes, such asreflection amplitudes, have also been observedand exploited to determine fracture azimuth.

The advantage of examining amplitudevariations is that it detects local azimuthalvariations in contrast to velocity-basedtechniques, which respond to the accumulatingeffects of overlying strata.39 Consequently, AVOAanalysis is a higher vertical resolution depictionof a NFR than that obtained with velocity-basedmethods. Reflection amplitude, or reflectivity,depends on the effective elastic properties of thefractured rock at the seismic scale. Because bothP- and shear (S-) velocities change with azimuthin a fractured medium, an AVO response will beinfluenced by fracture properties, includingfracture azimuth. While AVOA processing andinterpretation are fairly simple where there is asingle alignment in an otherwise homogeneousmedium, multiple fracture directions—for example near faults—and additional sourcesof anisotropy may significantly complicate the analysis.40

Another approach examines the azimuthalvariation of P-wave normal moveout (NMO)velocity.41 A minimum of three azimuthal measure-ments is required to construct an ellipse in thehorizontal plane that shows NMO velocities in allazimuthal directions. Although most seismicfracture-analysis methods assume a simplegeometry—horizontal beds and verticalfractures—the NMO technique allows somefurther assessment where beds are dipping and

where natural fractures may not be vertical.However, this technique also suffers from velocity-related degradation of vertical resolution.

A carbonate reservoir study in a field insouthwest Venezuela compared seismic-basedfracture-orientation results with fractureorientations based on FMI images.42 Differentseismic data types were used in the study,including 2D three-component (3C) P- and S-wave data, and 3D P-wave data. The studyfound that most of the results from the rotationanalysis of the converted-wave 2D-3C data, andthe AVOA and NMO analyses of the 2D and 3D P-wave data determined the general direction ofthe regional maximum horizontal stress.However, results varied between the differentmethods because of local structural variations.With the 3D P-wave data, the AVOA techniqueappeared more robust than the NMO analysis.The Venezuelan study also found that there werequantifiable advantages to acquiring land 3Cdata, including the ability to estimate fractureorientation and fracture density, or intensity.

Acquiring multicomponent seismic data in amarine setting requires sophisticated four-component (4C) seabed acquisition equipment.43

Marine seismic studies have been successful inidentifying anisotropy direction and magnitudeat the specific target horizon by effectivelyremoving the influence of the overburden in alayer-stripping approach.44

Passive seismic methods that detect thereservoir response to production or injection canalso be thought of as dynamic fracture- and fault-characterization techniques. Natural fracturesand faults emit microseismic events—mostlydue to shear readjustments—in response tochanges in effective stress following fieldproduction and injection, and especially duringhydraulic fracture stimulation operations.45

Sensitive seismic sensors positioned in nearbywellbores detect these acoustic emissions, whichin this method serve as the seismic source(above). Special processing methods estimateevent locations, producing a continuous time-based record of production- or injection-inducedactivity. Seismic methods represent medium- tolarge-scale fracture detection and character-ization methods, and therefore have implicationsin the effort to model the interwell volume ofthese complex reservoirs.

18 Oilfield Review

> Tracking acoustic emissions induced by fluid production or injection.Producing from or injecting into rocks in the subsurface changes net stressin fractures and faults, inducing small shear events that emit acousticsignals (red stars). These emissions can be recorded in nearby monitoringwells that contain sensitive multicomponent seismic recording equipment.Special localization processing creates a record of the events in space andtime. These acoustic emissions are located in 3D space and help identifyfracture and fault directions.

Monitoringwell

Naturalfractures

Production orinjection well

Production orinjection well


Summer 2006 19

Regardless of the technique, informationcultivated from seismic data contributes toreservoir modeling that guides primary- andsecondary-recovery planning. However, in manyfields, wells from which to draw detailed fractureinformation are too few and too widely spaced topopulate the model volume. Geologists gatherdetailed fracture data—orientation and possiblyspacing—from analog outcrops. However, thisprocess rarely captures a comprehensive descrip -tion of the fracture network for modeling purposesand sometimes overestimates fracture intensity.

Geoscientists at Hydro and Schlumberger inNorway have developed a way to capture thedetailed quantitative information needed to makeNFR models from outcrop analogs. This methoduses a combination of high-resolution opticalphotography, radar technologies and an automaticsurface-extraction technique now widely used formapping faults in 3D seismic datasets.46 Hydro andSchlumberger experts have tested this newtechnique using a well-studied NFR outcrop analogin the Guadalupe Mountains, New Mexico, USA.

For several years, Hydro, together with theUniversity of Texas at Dallas, has been usingdetailed 3D photorealistic models for high-resolution mapping of outcrop analogs.47

Photorealistic models are derived from themapping of high-resolution 2D photographs onto3D outcrop scans using light detection andranging (LIDAR) technology.48 LIDAR equipmenttransmits laser light—visible electromagneticradiation—to a target and receives back thereflected signal for analysis to determine certainproperties of the target. The most common typeof LIDAR is used for precise range finding—accurate to 2 mm [0.08 in.]—and the returnedradiation intensity can help define othercharacteristics of the target.

Digitizing sufficient detail of sedimentaryarchitecture from photorealistic models for thebuilding of reservoir models is a straightforwardprocess. However, manual digitizing and analysisof fractures from these datasets are impractical,because several hundred thousand to millions offractures are commonly present. The newautomated approach to outcrop mapping isorganized to take advantage of the 3D directionalinformation inherent in LIDAR data and coupleit with the detailed information within high-resolution 2D image data.

To achieve this, the LIDAR and photographicdata are first analyzed separately. Because theoutcrops naturally weather along fractures, faultplanes and bedding, the major fracture sets and bedboundaries are captured by vector analysis of theLIDAR data (above left). The orientations of target

37. Peralta S, Barrientos C and Arroyo JL: “The SpecializedUse of the VSP to Define Fracture Orientation and toHelp in a Multicomponent Survey Design,” Transactionsof the SPWLA 47th Annual Logging Symposium,Veracruz, Mexico, June 4–7, 2006, paper SS.Leaney WS, Sayers CM and Miller DE: “Analysis ofMultiazimuthal VSP Data for Anisotropy and AVO,”Geophysics 64, no. 4 (July-August 1999): 1172–1180.

38. Corrigan D, Withers R, Darnall J and Skopinski T:“Fracture Mapping from Azimuthal Velocity AnalysisUsing 3D Surface Seismic Data,” Expanded Abstracts,SEG International Exposition and 66th Annual Meeting,Denver (November 10–15, 1996): 1834–1837.

39. Hall SA and Kendall JM: “Constraining the Interpretationof AVOA for Fracture Characterization,” in Ikelle L andGangi A (eds): Anisotropy 2000: Fractures, ConvertedWaves and Case Studies. Tulsa: The Society ofExploration Geophysicists (2000): 107–144.

40. Sayers CM: “Misalignment of the Orientation ofFractures and the Principal Axes for P and S Waves in Rocks Containing Non-Orthogonal Fracture Sets,”Geophysical Journal International 133, no. 2 (May 1998):459–466.Sayers CM and Dean S: “Azimuth-Dependent AVO inReservoirs Containing Non-Orthogonal Fracture Sets,”Geophysical Prospecting 49, no.1 (January 2001): 101–106.Williams M and Jenner E: “Interpreting Seismic Data inthe Presence of Azimuthal Anisotropy; or AzimuthalAnisotropy in the Presence of the Seismic Interpretation,”The Leading Edge 21, no. 8 (August 2002): 771–774.

41. Grechka V and Tsvankin I: “3-D Description of NormalMoveout in Anisotropic Inhomogeneous Media,”Geophysics 63, no. 3 (May–June 1998): 1079–1092.

For more on normal moveout (NMO): http://www.searchanddiscovery.com/documents/geophysical/liner/images/liner.pdf (accessed May 7, 2006).

42. Perez MA, Grechka V and Michelena RJ: “FractureDetection in a Carbonate Reservoir Using a Variety of Seismic Methods,” Geophysics 64, no. 4 (July–August 1999): 1266–1276.

43. 4C marine seismic data are typically acquired usingthree orthogonally oriented geophones and ahydrophone within an ocean-bottom sensor. Providedthe system is in contact with the seabed, the 3Cgeophones measure shear waves. The hydrophonemeasures compressional waves.

44. Gaiser J, Loinger E, Lynn H and Vetri L: “BirefringenceAnalysis at the Emilio Field for FractureCharacterization,” First Break 20, no. 8 (August 2002):505–514.

45. Bennet L, La Calvez J, Sarver DR, Tanner K, Birk WS,Water G, Drew J, Michaud G, Primiero P, Eisner L,Jones R, Leslie D Williams MJ, Govenlock J, Klem RCand Tezuka K: “The Source for Hydraulic FractureCharacterization,” Oilfield Review 17, no. 4 (Winter2005/2006): 42–57.

46. Pedersen SI, Randen T, Sønneland L and Steen Ø:“Automatic 3D Fault Interpretation by Artificial Ants,”paper Z-99, presented at the 64th EAGE Conference andExhibition, Florence, Italy, May 27–30, 2002.

47. http://www.aapg.org/explorer/2004/06jun/lasers.cfm(accessed July 3, 2006).

48. For more on photorealistic models: http://www.utdallas.edu/~aiken/LASERCLASS/TSPSphotoFINAL.pdf(accessed June 30, 2006).

> Using 3D data from light detection and ranging (LIDAR) technology to mapmajor fracture sets. The digital photograph is photorealistically mappedonto a surface derived from the LIDAR data (top). The major fracturepatterns are apparent from both image (center) and vector analysis. The Y-component of the surface normal vector (bottom) shows vertical featuresthat are mostly fractures. The height of the vertical outcrop face rangesfrom about 20 to 25 ft [6.1 to 7.6 m].

ZX

Y


surfaces are described using the three directionalcomponents of the normal vector. Radiationintensity is then corrected for both the distance tothe LIDAR apparatus and the angle of the outcropsurface. A 3D LIDAR model grid is created andpopulated with the directional and intensity data.The corrected LIDAR intensity and directional-component data can then be partitioned into valueranges for mapping and analysis.

Although there is good detail in the LIDARdata, an even higher level of information iscontained in the photographs (above). However,

before an automated structural interpretation ofthe photographic data is accomplished, the digitalimage must be filtered for noise—anything in theimage that does not represent part of the rockexposure, such as vegetation or scree.

Next, an attribute or combination ofattributes is selected and the AutomatedStructural Interpretation process, adapted fromwhat is now used in Petrel software, can beginenhancing surfaces. The process uses anadaptation of the technique developed for faultinterpretation in 3D seismic volumes. At first, a

fault or fracture may appear only as a trendwithin the data, but as signal-to-noise character -istics are improved along the surfaces, a moredefined plane is mapped by “agents” using theprinciples of “swarm intelligence” (next page). Alarge number of process agents are deployed inthe data volume, making decisions based onprecoded behavior. Like ants, the agents traversethe various surfaces emitting an “electronicpheromone” along the trail, from which anestimate of the surface orientation is made andstored; in this case fractures and bedding are

20 Oilfield Review

49. Ali AHA, Brown T, Delgado R, Lee D, Plumb D, Smirnov N,Marsden R, Prado-Velarde E, Ramsey L, Spooner D,Stone T and Stouffer T: “Watching Rocks Change—Mechanical Earth Modeling,” Oilfield Review 15, no. 2(Summer 2003): 22-39.

50. Will R, Archer R and Dershowitz B: “Integration ofSeismic Anisotropy and Reservoir-Performance Data forCharacterization of Naturally Fractured Reservoirs UsingDiscrete-Feature-Network Models,” paper SPE 84412,presented at the SPE Annual Technical Conference andExhibition, Denver, October 5–8, 2003.

51. Rawnsley K and Wei L: “Evaluation of a New Method toBuild Geological Models of Fractured ReservoirsCalibrated to Production Data,” Petroleum Geoscience 7,no. 1 (February 2001): 23–33.

> Using components of a photorealistic model, photography and innovative software to mapbedding, fractures and faults. A high-resolution digital photograph of an analog outcrop in theGuadalupe Mountains (top) is processed. The software detects and enhances the discontinuitieson the photograph (middle). The white coding indicates a high level of discontinuity, and the blackcoding represents a low level of discontinuity. Both bedding (green) and fracture faces (red)are mapped (bottom). The height of the vertical outcrop face ranges from about 20 to 25 ft [6.1 to 7.6 m].


Summer 2006 21

picked. The result is a 2D map of linear outcropfeatures—mostly fractures and bedding—but ata higher resolution than that extracted from theLIDAR data.

Once the innovative processing is made onthe high-resolution digital photographs andLIDAR data, the results are recombined into the3D photorealistic model for manual verificationand analysis. At this stage, the 2D maps derivedfrom the photos are transformed into 3D data asthey are projected onto the photorealisticoutcrop model as a series of planes andattributes. The results of the photographic and LIDAR analysis are displayed as attributes in an editing window, and compared to thephotorealistic model by the interpreter forquality control.

Following editing of the data, the structuralgeologist is able to begin the process of quanti -tative fracture interpretation. Because beddingis automatically mapped as a part of the process,the interpreter is able to perform quantitativeanalysis of fracture extent, density and orienta -tion on a layer-by-layer basis, thus estab lishing amechanical stratigraphy. The analyzed jointplanes and their relationship to bedding andfaults can then be used as the basis for a discretefracture network model. Such models can beanalyzed in terms of representative fracturevolumes and flow heterogeneity related to thefracture systems.

Modeling the Effects of FracturesThere are perhaps no other simulation tasks aschallenging in today’s oil and gas fields asconstructing valid NFR models to simulatereservoir fluid flow with a reasonable degree of certainty. The challenges span multiple

disciplines and multiple scales, and must alwaysbe addressed with limited information. Theultimate aim in reservoir simulation is toestimate and predict the distribution and flow offluids within the reservoir in response toproduction or injection. Natural fractures makeachieving this aim considerably more difficult.

Some experts simplify the challenges of NFRfluid-flow simulation into three categories. First,a model must resolve the fluid pathways bydetermining fracture connectivity. Connectivitydepends on fracture length, orientation andintensity, which come from subsurface data andoutcrop analogs. Second, knowledge of fracture-system permeabilities, permeability variationacross the field, and the interaction betweenfractures and the matrix is essential. Third, thefluid pressure, or capillary pressure, and therelative permeabilities in the reservoir must becaptured. Additionally, a good understanding ofthe in-situ stress regime is needed for credibleNFR simulation. This information comes from avariety of sources—including logging measure -ments, borehole breakout and leakoff tests—andis used in mechanical earth models.49

The complexity of NFRs represents a realchallenge in reservoir simulation. The mostgeologically realistic models are discretefracture network (DFN) models. In these models,each fracture is represented as a plane in thereservoir with attached properties such asaperture and permeability. DFNs are able torepresent the geometric complexity of fracturedreservoirs with a high level of detail. Fluid flowcan be simulated through DFNs using finite-element methods, and the effects of matrix flowcan also be incorporated.

Creating a plausible model, however, placesgreat demands on geoscientists, and the fracturesystem must be parameterized in all its detail.This model is typically built from high-qualitydata near wellbores—for example, boreholeimage data, core analysis and pressure-transientdata—and is expanded to the interwell regionusing geostatistical techniques. DFN models canalso be guided by seismic anisotropy fracture-characterization results and production data.50

Well and seismic data are generally not sufficientto provide information about fracture extent andconnectivity and so outcrop analogs becomecrucial sources of information.

Today, the generation of DFNs still haslimitations. DFNs are computationally intensive,so it is not possible to model all of the fractureswithin a reservoir in this way. While a DFN couldbe used for an individual well test history-match,commercially available DFNs can handle onlysingle-phase flow and thus cannot modelsecondary-recovery mechanisms.51 It is possibleto represent only the largest fractures geometri -cally in cellular models, while smaller fractureshave to be represented as modified cellproperties. However, the physics of flow betweenfractures and matrix in cellular models can berepresented using the finite-difference methodand using dual-porosity and dual-porosity/dual-permeability techniques.

It is difficult to provide a link between thegeologist’s view of a fractured reservoir and acellular representation. One method for dealingwith this problem is to create small-scale DFNmodels that represent the details of thefracturing and to upscale them to cellular gridblocks using either static or dynamic methods.For example, a joint system was mapped from a

> Automatic fracture and fault delineation. One or several attributes are selected for the generation of Cube B from the seismic Cube A. Conditioning bythe Petrel Automated Structural Interpretation module is applied to Cube B using “swarm intelligence,” which enhances the fracture and fault features toproduce the resulting Cube C. The fault surfaces are then extracted as separate objects as shown on Cube D. These surfaces can then be incorporatedinto geologic models.

A B C D


helicopter photograph of a field outcrop (left).Joints were picked on the photograph using what is now the Petrel Automated StructuralInterpretation technique. The results were usedto build a DFN, capturing the entire complexityof the network. With an assumed aperture, theupscaled permeabilities in three differentdirections were determined using a pressuresolver and input to a cellular simulation model.52

Flow simulation in cellular models isperformed in two ways: by finite-difference andby streamline simulation.53 Finite-differencesimulators typically offer a wide range offunctionalities and are preferred in long-term,mature project environments. Also, finite-difference simulators have been more suited forsimulating fluid flow not dominated by reservoirheterogeneities in models with fewer uncertain -ties. Streamline simulators, such as the three-phase ECLIPSE FrontSim module, are better foraccessing dynamic reservoir behavior in large,multimillion-cell models. Streamline simulatorsare faster to run and allow asset teams to quicklyvalidate upscaled reservoir models with dynamicdata (below left).

Armed with a suitable flow simulator, assetteams can now examine connectivity across thereservoir and consider strategies to maximizehydrocarbon recovery. As more data come intothe model, each portion of the reservoir modelcan be fine-tuned. This may involve improvingstructural and mechanical earth models, matrixand fracture models, and matrix-fractureexchange models (next page).

22 Oilfield Review

> Streamline simulation. Streamline simulators, such as the ECLIPSEFrontSim software, allow reservoir engineers and geoscientists to quicklysimulate fluid flow in heterogeneous reservoirs. These simulators areespecially useful when simulating the effects of fractures or other high-permeability conduits on waterflooding for secondary recovery. In thisexample, the streamlines and reservoir layers are color-coded according to water saturation, Sw.

G03

G05

G11G09

G04 G14G12

G13

G01 34-5

G07

G06G02

1.0

0.1

Sw

> Example of an automatically generated fracture pattern from an outcrop in a 50-m by 50-m [164-ft by164-ft] area (top left) incorporated into a discrete fracture network (DFN) model. A constant aperturewas assigned to the fractures, and the permeability was upscaled using a pressure solver. The upscaledpermeability in the X-direction, Block Kxx, is scaled according to the color bar (left). Histograms (bottom)show Block Kxx and the fracture porosity for each 10-m by 10-m [32.8-ft by 32.8-ft] cell. The rosediagram (top right) shows the orientation of 1,669 fractures interpreted by what is now the PetrelAutomated Structural Interpretation process.

10 m

Length-weighted orientationof 1,669 fractures

1009080706050403020100

Perm

eabi

lity

(Kx),

mD

10

2.5

7.5

12.5

17.5

22.5

27.5

32.5

37.5

42.5

47.5

52.5

9876543

Permeability (Kx), mD

Permeability, X direction

210

Freq

uenc

y, nu

mbe

r of b

lock

s

3

2

1

0.01

700.

0174

0.01

780.

0182

0.01

860.

0190

0.01

940.

0198

0.02

020.

0206

0.02

100.

0214

0.02

18

Fracture porosity, %

Fracture Porosity

0

Freq

uenc

y, nu

mbe

r of b

lock

s

Y (N)

X (E)Z

52. A pressure solver is a tool in modeling software thatenables the calculation of pressure at every point ina model.

53. Afilaka JO, Bahamaish J, Bowen G, Bratvedt K,Holmes JA, Miller T, Fjerstad P, Grinestaff G, Jalali Y,Lucas C, Jimenez Z, Lolomari T, May E and Randall E:“Improving the Virtual Reservoir,” Oilfield Review 13,no. 1 (Spring 2001): 26–47.

54. Ahr WM, Allen D, Boyd A, Bachman HN, Smithson T,Clerke EA, Gzara KBM, Hassall JK, Murty CRK, Zubari Hand Ramamoorthy R: “Confronting the CarbonateConundrum,” Oilfield Review 17, no. 1 (Spring 2005): 18–29.Akbar M, Vissapragada B, Alghamdi AH, Allen D,Herron M, Carnegie A, Dutta D, Olesen J-R,Chourasiya RD, Logan D, Stief D, Netherwood R,Russell SD and Saxena K: “A Snapshot of CarbonateReservoir Evaluation,” Oilfield Review 12, no. 4(Winter 2000/2001): 20–41.

55. Kossack CA and Gurpinar O: “A Methodology forSimulation of Vuggy and Fractured Reservoirs,” paperSPE 66366, presented at the SPE Reservoir SimulationSymposium, Houston, February 11–14, 2001.Gurpinar O, Kalbus J and List DF: “Numerical Modelingof a Large, Naturally Fractured Oil Complex,” paperSPE 59061, presented at the SPE International PetroleumConference and Exhibition, Villahermosa, Mexico,February 1–3, 2000.Gurpinar O, Kalbus J and List DF: “Numerical Modelingof a Triple Porosity Reservoir,” paper SPE 57277,presented at the SPE Asia Pacific Improved Oil RecoveryConference, Kuala Lumpur, October 25–26, 1999.


Summer 2006 23

Typically, models are tested and calibratedusing historical pressure and production data—history-matching—and must be updated andfine-tuned with new information. An asset team’sability to quickly update reservoir models andrun multiple simulations has been enhanced,and continues to improve, with the availability ofincreased computing power.

Fracture BreakthroughsSome of the largest hydrocarbon reservoirs in theworld are naturally fractured carbonatereservoirs in the Middle East, Mexico andKazakhstan.54 In many cases, these reservoirshave three porosity systems: fracture, matrix andvuggy—both connected and isolated—andinvolve multiphase fluid flow, adding to themodeling difficulties. The challenges facingoperators in these fields are daunting. Declining

hydrocarbon productivity, increasing waterproduction and significant volumes of unsweptoil are the most obvious reasons for concern.Closer examination has revealed inherentdifficulties in modeling heterogeneous, dual- andtriple-porosity reservoirs with multiphase fluidflow. In these cases, it has been useful to developspecial relationships for relative permeabilitiesand capillary pressure that take the complexitiesinto account.55

On March 25, 2006, Schlumberger, in analliance with King Fahd University of Petroleumand Minerals, officially opened the SchlumbergerDhahran Center for Carbonate Research (SDCR)to engage in collaborative projects focusing oncarbonate reservoirs, the majority of which areNFRs. Scientists at this state-of-the-art researchcenter will focus on the development oftechnologies that address the challenges ofexploiting these complex reservoirs, including

research in land seismic technologies, geology,rock physics and fluid dynamics.

In the past, available static and dynamic datahave dictated an asset team’s approach to NFRcharacterization, modeling and simulation. Today,a better understanding of NFR complexities,improved measurements and interpretationtechniques across a wider range of scales, fasterand vastly improved modeling capabilities andexciting new research will make the industry’sprogress in fractured reservoirs natural. —MGG

> Modeling naturally fractured reservoirs. A workflow example describes the major elements involved in NFR modeling during the project startup (greenbackground), model creation (yellow background) and model fine-tuning (blue background) phases. The numbers at the bottom indicate where in theworkflow that model fine-tuning should take place, in order of preference.

EngineeringEvaluation

GeologicalEvaluation

FractureIndicators

Log-Derived Properties

Reservoir and DynamicData for Flow Modeling

DataCollection,Verification

andValidation

•Pressure•Production•Injection analysis•Well summaries•Pressure- treatment analysi

permeability (Kr)

s•Reservoir

•Capillary pressure (Pc)•Single-well models

ProjectObjectivesStatus ofthe FieldStatus ofDataProjectTime/$$

•Well location•Unique identifier•Directional survey•Well completion•Production•Wellbore facilities•Pressure•Well test•PVT•Core analysis•Relative permeability•Logs•Image logs•Dipmeter logs•Sedimentology•Seismic data•Seismic navigation•Velocity control•Drilling records•Reports•Previous studies

•Cores•Sedimentology•Facies model•Stratigraphy•Correlations•Synthetics•Seismic interpretation•Faults and horizons•Structure modeling•Dipmeter interpretation•Petrophysical evaluation

•Regional structural setting•Structural framework•Curvature•Lithology•Drilling events•Well tests•Production behavior•Image logs•Sonic logs

Total and matrix petrophysicsModel layering influenceModel grid influence

FaultModel

FractureIndex

FlowSimulation

Grid

DiscreteFracture

DFNVerification

3DProperty

Distribution

Reservoir-Management

Model

PredictiveReservoir

Model

Kr , Pc

Two-phase

Three-phase

FlowModel

Yes

No

DualSystem

124 3

NFR Modeling

PVT, production, pressure,well completion, injection,test database, Kr c, P ,prediction objectives

FractureModel

MatrixModel

StreamlineSimulator

ConnectivityReview

StructuralFramework

FractureIntensityDirection

Multiphase

ReproduceHistoricalBehavior


Model

the nature of naturally fractured reservoirs

Documents