Naturally Fractured Reservoirs

Continued on Page 4544 CSEG RECORDER February, 2003

I am convinced significant volumes of hydrocarbons residein naturally fractured reservoirs – particularly in fields aban-doned because of improper testing and evaluation or becausethe wells did not intersect the fractures.1 Rules of thumb andnaturally fractured reservoirs do not mix well. What appears towork in one might fail miserably in the next. Consequently,each naturally fractured reservoir (nfr) exploration play andeach nfr under production must be considered as a researchproject by itself.

Geologic Aspects

Stearns2 defines a natural fracture as a macroscopic planardiscontinuity that results from stresses that exceed the rupturestrength of the rock. These natural fractures can have a positive,neutral, or negative effect on fluid flow.3 In my opinion, virtuallyall reservoirs contain at least some natural fractures. However, ifthe effect of these fractures on fluid flow is negligible, the reser-voir can be treated, from a geologic and reservoir engineeringperspective, as a “conventional” reservoir.

For reservoirs where the fractures have a positive or negativeeffect on fluid flow, it is of paramount importance to have knowl-edge of magnitude and direction of in-situ principal stresses;azimuth, dip, spacing, and aperture of fractures; matrix and frac-ture porosity, matrix and fracture permeability, and matrix andfracture water saturation. These data help in calculations of howthe in-place hydrocarbons are distributed between matrix andfractures, and the flow capacity of the wells.

All naturally fractured reservoirs are not created equal. I amnot sure if I read the previous sentence somewhere, if I heard itfrom somebody, or if I thought about it. Notwithstanding, Ibelieve it is a very accurate statement, which means that we haveto somehow classify and characterize the reservoir. This providesan important link between the geophysical, geological and engi-neering disciplines.

In addition to the fracture and matrix properties mentionedabove, I recommend (1) classifying the reservoir from a geologicpoint of view keeping in mind that the fractures can be tectonic,regional or contractional, (2) evaluating the pore system, (3) quan-tifying the relative hydrocarbon storativity of matrix and frac-tures, and (4) getting a good idea with respect to thematrix/fracture interaction.

Geologic Classification

From a geologic point of view the fractures can be classified asbeing tectonic (fold and/or fault related), regional, contractional(diagenetic), and surface related1-3. Historically most hydrocarbonproduction has been obtained from tectonic fractures, followedby regional fractures and followed by contractional fractures. Ingeneral, surface related fractures are not important from the pointof view of hydrocarbon production. When classifying fractures

determine magnitude and direction of in-situ principal stresses;azimuth, dip, spacing, and if possible aperture of fractures.

Pore Classification

It is possible to make preliminary estimates of productivecharacteristics of common reservoir porosity types following aclassification proposed by Coalson et al.4 In this classification,porosity classes are defined first by the geometry of the pores, andsecond by pore size. Included in the geometry are the followinggeneral pore categories: intergranular, intercrystalline, vuggy, andfracture. The combination of any of them can give origin to dualand even multi-porosity behavior.5

The pore size can be recognized from different techniques,including Winland4 r35 and Aguilera6 rp35 pore throat apertures.Included in the pore size are megaporosity (r35>10 microns),macroporosity (r35 between 2 and 10 microns), mesoporosity (r35

between 0.5 and 2 microns) and microporosity (r35 < 0.5 microns).Martin et al.7 have indicated that megaports are capable offlowing tens of thousands of barrels per day, macroports thou-sands of barrels per day, mesoports hundreds of barrels of oil perday, and microports tens of barrels per day. Figure 1 shows agraph for estimating values of Rp35 for the matrix in naturally frac-tured reservoirs. The graph follows the same format presented byMartin et al.7 using Winland’s equation.

Geologic and Engineering Aspects of Naturally Fractured ReservoirsRoberto Aguilera, Servipetrol Ltd., Calgary, Canada

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Figure 1. Aguilera Rp35 pore throat radii as a funcation of matrix porosity and perme-ability.

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February, 2003 CSEG RECORDER 45

The vast majority of papers and books on this subject discussonly fractures with apertures of a few microns. This is probablybecause of very poor core recovery from reservoirs containing frac-tures with much greater apertures. From laboratory work andexperience it has been found that nut shells and plastic materialscan stop circulation losses in fractures with apertures as large as5000 microns. If in a given naturally fractured reservoir these mate-rials cannot stop circulation losses the conclusion is reached thatthe apertures are bigger than 5000 microns at reservoir depth. Infact, secondary porosity apertures can actually reach cavern-size insome instances. Thus the generalized assumption that fracturescannot provide significant hydrocarbon storage is, in my opinion,not valid.

Storage Classification

From a storage point of view, fractured reservoirs can be classi-fied8,9 as being of Type A, B or C. Many reservoirs that would other-wise be non-productive are commercial thanks to the presence ofnatural fractures.

In reservoirs of Type A the bulk of the hydrocarbon storage is inthe matrix porosity and a small amount of storage is in the frac-tures. The matrix typically has a very low permeability while thenatural fractures tend to have a much larger permeability. But thereare exceptions. For example, the matrix in the giant Saudi ArabianGhawar reservoir has very large porosities and permeabilities.10 Inthis type of reservoir the fractures are a curse rather than a blessingbecause they facilitate unwanted water channeling. In thisinstance, efforts that integrate geologic information, 3D seismicdata, and transient pressure analysis are directed at avoidingrather than intersecting the fractures.

In reservoirs of Type B approximately half the hydrocarbonstorage is in the matrix and half is in the fractures. The matrix istight and the fractures are much more permeable than the matrix.

In reservoirs of Type C all the hydrocarbon storage is in the frac-tures with no contribution from the matrix. Thus in this instancethe fractures provide both the storage and the necessary perme-ability to achieve commercial production.

There are many reservoirs with fractures of tectonic originwhere the primary porosity (matrix) tends to be occluded or hasextremely low permeability and consequently does not contributeany hydrocarbon storage. In these cases, a large number ofmicrofractures might be present that play the role of “matrix”porosity. This is due to the pervasiveness of tectonic fractures thatexist from a macro scale to the grain size scale (they are veryfractal). In this case the combination of micro and macrofracturescan lead to dual porosity behavior.

Matrix/Fracture Interaction

Cores provide an excellent source of direct information fordetermining the kind of interaction that could be anticipated fromfractures and matrix. Consider different possibilities:5

No Secondary Mineralization. Good luck or a teaser? Whenthe natural fractures are open and have a negligible amount of

secondary mineralization the hydrocarbons move from the matrixto the fractures in an unrestricted way.

How quickly the fluids move from matrix to fractures iscontrolled by the amount of pressure drop in the fractures, andmatrix properties such as permeability, porosity and compress-ibility, viscosity of the fluid flowing, and fracture spacing or size ofthe matrix blocks. These kinds of fractures can provide very highinitial fluid rates. The major problem with this type of fractures isthat they might tend to close as the reservoir is depleted dependingon the in-situ stresses, the initial reservoir pressure and the reduc-tion in pressure within the fractures. In these cases, fractures aremuch more compressible than the host rock.

If the reservoir is initially overpressured the fracture closure canbe very significant leading to small hydrocarbon recovery, bigheadaches and major financial losses.

If the reservoir is initially underpressured the fracture closure isnot as significant because most of the closure at reservoir depth hasalready occurred. Ultimate fractional recoveries will be bigger thanin the previous case.

Some Secondary Mineralization. I think good luck! Whennatural fractures have a certain amount of secondarymineralization the fluid flow from matrix to fractures is somewhatrestricted. From the point of view of pressure behavior during welltesting this can be visualized as a natural skin within the reservoir(not to be confused with mechanical skin around the wellboreroutinely calculated). Partial mineralization is a blessing indisguise. In this case, the secondary minerals will act as a naturalproppant agent and fracture closure will be significantly reduced(not completely stopped) even in overpressured reservoirs. This inturn will lead to higher ultimate recoveries. The fracture closurewill be smaller in normally pressured reservoirs, and even smallerin underpressured reservoirs.

Complete Secondary Mineralization. Bad Luck!! Even if thereis a lot of hydrocarbon within the reservoir, the ultimate recoverywill be low. The mineralized fractures will compartmentalize thereservoir leading to very low ultimate recoveries.

Vuggy Fractures. They can have very large porosities that canreach 100% in some intervals and several darcies of permeability.Production can be several thousands of barrels per day if the vugsare connected (touching vugs). Vuggy fractures present theadvantage that they do not close due to their rounded shape. Non-connected vugs provide non-effective porosity and permeability.

Engineering Aspects

Engineering aspects deal primarily with quantitative evalua-tion of naturally fractured reservoirs. This quantification links thegeophysical, geologic and engineering disciplines. Some key goalsare to estimate hydrocarbons-in-place, forecast production rates,and improve ultimate economic recoveries.

Characterization of the naturally fractured reservoir and engi-neering evaluations rely on direct and indirect sources of informa-

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46 CSEG RECORDER February, 2003

tion.9 The determination of flow (or hydraulic) units11 is an impor-tant part of the characterization. Direct sources of informationinclude cores, drill cuttings, downhole photographs and videos ofthe borehole. Indirect sources include outcrops, drilling history,mud log, conventional and specialized well logs, seismic informa-tion (preferentially 3D), well testing, inflatable packers, andproduction history.

Direct Sources of Information

They are very powerful because direct sources permit “seeing”the fractures categorically.

Cores. They represent the most important direct source ofinformation. I recommend to always budget the necessary funds tocore at least a few key wells. The successful study of a naturallyfractured core must start at the well site.12,13 The laboratory must beselected carefully, followed by meetings with laboratory personnel,and an inspection of the facilities where the experiments will beconducted.14 Disruption of the fractured core must be minimizedby using double-tube core barrels, which have successfullyreplaced rubber-sleeve coring methods. Disposable inner linersmade of aluminum or fiberglass can provide good coring resultsbecause of their low friction coefficients and ability to preventjamming.13 In case of some disruption the core must be properlyfitted together and marked with scribe lines to make sure that it iscorrectly laid out in the laboratory for fracture analysis.12 The coreshould be preserved as best as possible, preferentially by wrappingit in plastic and placing it in ziplock bags. This precaution helps toprevent loss of reservoir fluids and/or core dehydration. In myopinion, oriented cores are advisable, although there is a trend inindustry to orient cores with well log images (which are indirectsources of information).

A modern comprehensive analysis should include at least thefollowing evaluations:14

• Fracture types description• Grain density• Petrophysical parameters m an n (m at simulated conditions of

net overburden)• Whole core porosity and permeability (at room conditions and

some samples at simulated net overburden pressure)• Routine core analysis• Capillary pressures and relative permeabilities• Wettability determination in a preserved core• Imbibition recoveries if the rock proves to be water wet• Mechanical testing (Poisson’s ratio, Young’ modulus, stress-

strain analysis, matrix and fracture compressibility)• Thin section analysis• SEM (scanning electron microscopy) analysis• Epoxy impregnation• Spectrometric gamma ray and sonic velocity• Solubility• Non-destructive permeability determinations with a pressure

decay profile permeameter• Core scale pressure transient analysis15 and microsimulation of

the fractured core.16

Drill Cuttings. Many times natural fractures may not bepreserved in cuttings due to breakage along cuttings.

Consequently, the reservoir might be naturally fractured even ifthe cuttings do not show any fractures. However, there areexceptions. Hews17 has indicated that there are instances wherecuttings can provide very useful information with respect tofractures. He indicates, and I had the opportunity to see it, that“with the samples wetted, internal textures including fractures andbrecciation are more apparent. Dry samples are best to see anyporosity that may be associated with a fracture plane.” Under thesecircumstances it is advisable to examine the cuttings thinking interms of natural fractures. Crystals on the face of a fracture can beindicative of very effective fracture porosity. Thin sections fromcuttings can also provide evidence of natural fractures. Cementedmicrofractures in thin sections can be extensions of larger openfractures.

Downhole Borehole Cameras. Photos and video tapes canprovide direct information regarding many features penetrated bythe borehole including natural fractures, faulting, bed boundaries,hole size and hole shape. There are video cameras that have beendeveloped to examine vertical, slanted and horizontal wells. Air-drilled, low pressure reservoirs are prime candidates forapplication of video camera technology.18

Indirect Sources of Information

They include outcrops, drilling history, mud log, conventionaland specialized well logs, seismic information (preferentially 3D),pressure data, inflatable packers, and production history.

Outcrops. There are essentially two schools of thought when itcomes to the evaluation of outcrops. The first one indicates that19

“using outcrop data to characterize the fracture pattern of areservoir is frustrated by the stress release which occurs as rockscome to the surface” and that “outcrop data is unsuitable formodelling reservoir fractures.” The second school of thoughtindicates that outcrops, when properly evaluated, can provide asignificant amount of valuable information in exploration playsand during the development of a reservoir. I strongly recommendyou to adhere to the second school of thought. A properlyconducted outcrop study can provide information on spacing,connectivity and orientation of the fractures relative to thestructure and stratigraphy. If you are going to drill a horizontalwell, for example, the outcrop can help you determine theoptimum orientation of the well to maximize productivity.20

Drilling History. It contributes valuable information regardinghydrocarbon shows, mud losses and penetration rates. Mud lossesmight be associated with natural fractures, vugs, undergroundcaverns or induced fractures. Penetration rates can increasesignificantly while drilling all types of secondary porosity.

Well Logs. Logs are powerful indicators of natural fractures insome reservoirs. However, there is not a single log that is going towork all the time. I have used the following logs in the past, mostlyfrom a qualitative point of view, to determine where the fracturesare located: sonic amplitude, variable intensity, vertical seismicprofiling, caliper, resistivity, Pe, borehole televiewer, dipmeter,spontaneous potential, density correction curve, boreholegravimeter, uranium index, temperature and noise logs. Details on


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these techniques are available in the literature of the variousservice companies.

Quantitative analysis can be conducted from image logs todetermine fracture orientation, dip, spacing, connectivity, fractureaperture and permeability. My experience with images for deter-mining fracture orientation, dip and spacing is good. However, myexperience with calculated apertures and permeabilities is a mixedbag. I recommend assigning value to these parameters only from arelative point of view.

Quantitative analysis can also be conducted for estimating frac-ture porosity21 using dual porosity models, which are based on theobservation that the porosity exponent of the fractures (mf) shouldbe very close to 1.0. This is much smaller than the porosity expo-nent of the matrix (mb). The porosity exponent of the dual porositysystem (matrix + fractures and/or connected vugs), m, variesbetween mf and mb. The smaller the degree of fracturing, thecloser the value of m to mb. The larger the degree of fracturing, thecloser the value of m to mf. In the case of dual porosity systemsmade out of matrix and non-connected (non-touching) vugs, thevalue of m is larger than mb. Care must be exercised when usingdual porosity models, as the incorrect scaling of the matrix porositycan lead to errors in the calculation of water saturation.21

Seismic Information. Significant advances have beenachieved in 3D seismic technology that allow in some casesdetermination of fracture orientation, anisotropy and fracturedensity22 and the type of fluid that could be present in the reservoir.Under favorable conditions, this can be estimated using AVO(amplitude vs. offset) and AVAZ(amplitude vs. azimuth) interpretationtechniques.

Well Testing. This in an area thathas also seen significant advances inthe precision of the tools and theinterpretation software packages.Modern formation testers can providevertical information that cannot bedetected by a standard test. Multipleprobes can show the presence or lack ofvertical interference in a wellbore.Automatic type curve matching ispowerful but dangerous. To avoidfiascos with automatic matching, it isimportant to make sure that theengineer is always on top of theinterpretation. Numerical 2D welltesting models using unstructuredVoronoi grids (PEBI) provide asignificant and necessary extension tothe more conventional Cartesian,semilogarithmic and log-log derivativecrossplots.

A properly designed and super-vised test can provide valuable infor-mation including fracture permeability,fracture porosity, and fracture spacing

in addition to usually estimated parameters such as skin, radius ofinvestigation, extrapolated pressures, etc.

Production History. If from cores the permeability of a formationis 0.1 md, and the well produces 1,000 bopd, it can be inferred thatthe rate is the result of some type of secondary porosity, includingfractures. Premature water or gas breakthrough in secondaryrecovery projects can also indicate the presence and strike of naturalfractures. To avoid these unpleasant surprises, it is advisable toperform pressure interference tests early in the life of the reservoir.

Recovery Factors and Reserves

The optimum way of forecasting performance and recovery isutilizing a reservoir simulator as long as the reservoir characterizationand the quality of the pressure and production data is good. Based onmy experience, it is reasonable to forecast twice the time of availablehistory. For example, if there are two years of good production andpressure data, it is reasonable to forecast four years of production.

Compressibility

If the reservoir is composed by matrix and fractures, thecompressibility of the fractures is bigger than the compressibility ofthe matrix. The relative difference between the two compressibili-ties depends5 on various factors including the amount ofsecondary mineralization within the fractures, the orientation ofthe fractures and in-situ stresses, and if the reservoir is over-pres-sured, normally pressured, or under-pressured.


Figure 2. Chart for estimating fracture compressibility. MINER is the estimated percentage of secondary mineralizationin the fractures. RATIO is fracture porosity divided by the summation of fracture porosity and connected vug porosity.(Source: Aguilera5)



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48 CSEG RECORDER February, 2003

Closing of the fractures once the reservoir goes on productioncan be very significant in over-pressured reservoirs. This can leadto huge declines in production rates. Fracture closure in under-pressured reservoirs is less significant as most of the closure hasalready occurred.

In a dual porosity system made out of macro and microfrac-tures (and without any primary porosity) the macrofractures playthe role of “fractures” and the microfractures play the role of“matrix.” In this case, there are instances in which the microfrac-tures (matrix) can be more compressible than the macrofractures(fractures). In other instances both compressibilities can be of thesame order of magnitude.

Whenever possible, it is advisable to determine compressibili-ties in the laboratory using rocks from our own reservoir. If this isnot available we have to rely on empirical correlations. Figure 2shows a correlation5 that I have used with reasonable success for anumber years.

Ranges of Recovery

Each naturally fractured reservoir should be considered as aresearch project by itself. As such it has to be studied carefully toestimate recoveries. It is wise to remember that naturally fracturedreservoirs and rules of thumb do not mix well. What appears towork in one reservoir might fail miserably in the next.

Tables 1 and 2 show some ranges of recoveries5,23 based on myexperience working with naturally fracture reservoirs worldwidefor about 30 years. These oil and gas recovery estimates arepresented for different recovery mechanisms and different types offractured reservoirs. They are no panaceas. Use them carefully andonly as order of magnitude indicators. There is no substitute for adetailed study.

Reservoir TypeRecovery Mechanism A B C

Depletion Drive 10-20 20-30 30-35Depletion Drive plus Gas Injection 15-25 25-30 30-40Depletion Drive plus Water Injection 20-35 25-40 40-50Depletion Drive plus Water Inj plus Gas Inj 25-40 30-45 45-55Gravity Segregation with Counterflow 40-50 50-60 >60Depletion Drive plus Water Drive 30-40 40-50 50-60Depletion Drive plus Gas cap 15-25 25-35 35-40Depletion Drive Plus Gas cap plus Water Drive 35-45 45-55 55-65

Table 1. Typical oil recoveries from naturally fractured reservoirs as a percent oforiginal oil in place (Source: Aguilera5)

Reservoir TypeRecovery Mechanism A B CWithout Water Drive 70-80 80-90 >90With Moderate Water Drive 50-60 60-70 70-80With Moderate Water Drive & Compression 20-30 30-40 40-50With Water Strong Drive 15-25 25-35 35-45

Table 2. Typical gas recoveries from naturally fractured reservoirs as a percent oforiginal gas in place (Source: Aguilera5)

Although in general, percent hydrocarbon recoveries fromType C reservoirs are larger than for Types A and B, the engineerhas to be careful because usually the amount of hydrocarbon-in-place in Type C reservoirs is smaller.

Reserves

An excellent source24 regarding proved, probable and possibleoil and gas reserves is the Petroleum Society of CIM MonographNo. 1 published in 1994. When it comes to naturally fracturedreservoirs, I recommend using statistical procedures to quantifythe uncertainty associated with hydrocarbons-in-place andreserves.

Most naturally fractured reservoirs I am familiar with are char-acterized by low matrix porosities (less than 10%) and low matrixpermeabilities (less than 1 md). For these reservoir characteristics itis difficult to place a reasonable certainty of volumetric estimates oforiginal hydrocarbons-in-place and reserves. As a consequence, Irecommend placing reserves from volumetric estimates in thepossible category. For matrix porosities larger than 10% and matrixpermeabilities larger than 1 md the reserves can be moved to theprobable category.

Early material balance calculations can provide estimates ofprobable reserves. As the cumulative production increases and withgood quality pressure data (long flow and long shut-in times) thematerial balance reserves can be moved into the proved category.

I place production decline estimates from short history in anunproved category. Long production history leads to reasonableestimates of proved oil reserves. I do not recommend declinecurves for estimating proved reserves of gas reservoirs unless thewells are at a late stage of production where a constant surfacecompression pressure is being utilized.

Beware of water influx in naturally fractured gas reservoirs. Awell might be producing extremely well. But it is not unusual to seethat the gas rate goes to nothing once water reaches the wellbore.

Reservoir simulation, although imperfect, is the tool that in myopinion provides the most reliable source of information for esti-mating recoveries and proved reserves. A significant amount ofhigh quality data is required. The longer the production history themore reliable are the forecasted results.

Early in the life of the reservoir when production history isshort or non-existent, proved reserves can be estimated from welldesigned, well supervised interference tests using high precisionpressure gauges. The larger the number of wells involved in thetest the better. In addition to providing reserves, the test will givevery useful information regarding anisotropy.

If the objective is estimating reserves by investigating bothmatrix and fractures, I do not recommend pulse tests with shortflow and buildup periods. Long continuous flow times during theinterference test are required to properly investigate both matrixand fractures.


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If there is only one well in the naturally fractured reservoir, Irecommend a long flow period following the collection of a goodinitial pressure. An estimate of the radius of investigation leads to avolumetric estimate of hydrocarbons-in-place within the investi-gated area. This requires a reasonable estimate of net pay, matrix andfracture porosity, and matrix and fracture hydrocarbon saturation.

A Review — and a Look Ahead

Since my early days working with naturally fractured reser-voirs in the early seventies, I have seen extraordinary advances inthe geophysical, geological and engineering fields. These advanceshave led to improved estimates of recoveries and reserves. Theseimprovements will continue.

Over the next few years, I anticipate significant improvementsin seismic technology to better characterize anisotropy of naturallyfractured reservoirs.

There will be advances in the evaluation of whole cores and theuncertainty associated with estimates of fracture compressibilitywill be reduced.

Imaging logs will continue improving and this will lead to morereasonable estimates of fracture parameters.

More, better and more realistic well testing and reservoir simu-lation models will be developed. Simulation grids will beimproved. Unstructured Voronoi (PEBI) grids in 3D will becomestandard features of well testing packages. Software “friendliness”will be a big part of these models. Coupled fluid flow and rockmechanics simulators that take into account normal and shearstresses will become functional.

Hydrocarbon recoveries will continue increasing as more devi-ated and horizontal wells are drilled underbalance to properlyintersect (or if desired avoid) vertical and high inclination naturalfractures. R

References1. Aguilera, R.: Geologic Aspects of Naturally Fractured reservoirs, The Leading Edge

(December 1998), pp. 1667-1670.

2. Stearns, D. W.: AAPG Fractured Reservoirs School Notes, Great Falls, Montana (1982-1994).

3. Nelson, R., Geologic Analysis of Naturally Fractured Reservoirs, Contributions inPetroleum geology and engineering, Vol. 1, Gulf Publishing Co., Houston, Texas(1985).

4. Coalson, E. B., Hartmann, D. J., and Thomas, J. B.: Productive Characteristics ofCommon Reservoir Porosity Types, Bulletin of the South Texas Geological Society, v. 15,No. 6 (February 1985), pp. 35-51.

5. Aguilera, Roberto: Recovery Factors and Reserves on Naturally Fractured Reservoirs,Journal of Canadian Petroleum Technology, Distinguished Authors Series (July1999), p. 15-18.

6. Aguilera, R.: Incorporating Capillary Pressure, Pore Throat Aperture Radii, Height AboveFree Water Table, and Winland r35 Values on Pickett Plots, AAPG Bulletin, v. 86, no. 4(April 2002), p. 605-624.

7. Martin, A. J. et al.: Characterization of Petrophysical Flow Units in Carbonate Reservoirs,AAPG Bulletin, v. 83, no. 7 (May 1997), p. 734-759.

8. McNaughton, D. A. and Garb, F. A.: Finding and Evaluating Petroleum Accumulationsin Fractured Reservoir Rock, Exploration and Economics of the Petroleum Industry, v.13, Matthew Bender & Company Inc. (1975).

9. Aguilera, R.: Naturally Fractured Reservoirs, PennWell Books, Tulsa, Oklahoma(1995), 521 p.

10. Al-Thawad F. et al.: Optimizing Horizontal Well Placement in the Faulted Ghawar Fieldby Integrating Pressure Transient and 3D Seismic, SPE 62986 presented at the 2000 SPEAnnual Technical Conference and Exhibition in Dallas, Texas (October 1-4, 2000).

11. Aguilera, Roberto: Determination of Matrix Flow Units in Naturally FracturedReservoirs, paper 2002-157 presented at the Petroleum Society’s CanadianInternational Petroleum Conference held in Calgary, Canada (June 11-13, 2002).

12. Bergosh, J. L. et al.: New Core Analysis Techniques for Naturally Fractured Reservoirs,SPE paper 13653 presented at the California Regional Meeting Held in Bakersfield,California (March 27-29), 1985.

13. Skopec, R. A.: Proper Coring and Wellsite Core Handling Procedures: The First StepTowards Reliable Core Analysis, Journal of Petroleum Technology (April 1994) p. 280.

14. Aguilera, R.: Advances in the Study of Naturally Fractured Reservoirs, The Journal ofCanadian Petroleum Technology (May 1993), vol.32, no. 5, pp. 24-26.

15. Kamath, J. et al.: Characterization of Core-Scale Heterogeneities Using LaboratoryPressure Transients, SPE Formation Evaluation (September 1992), p. 219-227.

16. Au, A. D. and Aguilera, R.: Micro-simulation of Naturally Fractured Cores, PetroleumSociety of CIM paper 94-79 presented at the Annual Technical Conference inCalgary, Canada (June 12-15, 1994).

17. Hews, Peter: Structural Features that can be Identified from Drill Cuttings,Interpretations, Implications and Fracture Evaluation, Hara Consulting Ltd. CourseManual (October 2000).

18. Overby, W. K. et al.: Analysis of Natural Fractures Observed by Borehole Video Camerain a Horizontal Well, SPE 17660 presented at the SPE Gas Technology Symposiumheld in Dallas, Texas (June 13-15, 1988).

19. Akbar, M. et al.: Fractures in the Basement, Schlumberger Middle East EvaluationReview, Number 14 (1993), p. 26.

20. Friedman, M. and McKiernan, D. E.: Extrapolation of Fracture Data from Outcrops ofthe Austin Chalk in Texas to Corresponding Petroleum Reservoirs at Depth, Journal ofCanadian Petroleum Technology (October 1995), p. 43.

21. Aguilera, M. S. and Aguilera, R.: Improved Models for Petrophysical Analysis of DualPorosity Reservoirs, Petrophysics (January-February 2003).

22. Gray, F. D. and Head, K. J.: Using 3D Seismic to Identify Variant Fracture Orientationin the Manderson Field, SPE 60296, Denver, Colorado (March 2000).

23. Cronquist, C.: Estimation and Classification of Reserves of Crude Oil, Natural Gas, andCondensate, SPE, Richardson, Texas (2001), p. 150

24. Determination of Oil and Gas Reserves, Petroleum Society of CIM Monograph No. 1,Calgary, Canada (1994).

Dr. Roberto Aguilera is presidentof Servipetrol Ltd. and an AdjunctProfessor in the Chemical andPetroleum Engineering Departmentat the University of Calgary, where heconcentrates in teaching about thetheoretical and practical aspects ofnaturally fractured reservoirs. He is apetroleum engineering graduate from

the Universidad de America at Bogota, Colombia andholds Masters and Ph.D. degrees in PetroleumEngineering from the Colorado School of Mines. He haspresented his course on Naturally Fractured Reservoirsand has rendered consulting services throughout theworld. He is a Distinguished Author of the Journal ofCanadian Petroleum Technology, a recipient of theOutstanding Service Award from the Petroleum Society ofCIM and a SPE Distinguished Lecturer on the subject ofNaturally Fractured Reservoirs.



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Naturally Fractured Reservoirs