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Fracture study of a horizontal well in a tight reservoir — Kuwait
Journal of Petroleum Science and Engineering 55 (2007) 6 – 17 www.elsevier.com/locate/petrol
Fracture study of a horizontal well in a tight reservoir — Kuwait S.I. Ozkaya a,⁎, H.J. Lewandoswki b , S.B. Coskun a a
Baker Atlas Geoscience, PO Box 15425, Manama, Bahrain b Kuwait Oil Company, Kuwait Received 3 May 2005; accepted 26 April 2006
Abstract An integrated fracture study was conducted to evaluate the fracture flow potential of the low permeability Mishref Formation, using electrical open hole logs, borehole images and production data from a horizontal well, and pressure transient analysis from a vertical well. Image logs show at least three stages of intense faulting and fracturing but the reservoir has only a limited fracture flow potential because (i) the early stage of NW/SE faults and fractures were all cemented. (ii) Although NE/SW fractures generated by recent tectonic episodes and very recent NW/SE fault rejuvenation are open and fluid conductive, faulting created fractures only within the brittle layers, which are a few inches thick and dispersed within thick low porosity and ductile units. Faults have wide fractured zones with flow potential only within a 2–5 ft thick brittle layer close to the reservoir top. The development of fracture permeability in a reservoir requires not only deformation and faulting but also the presence of mechanical layers which are prone to fracturing. A high degree of faulting is not a guarantee for a high degree of fracturing. In this particular reservoir, production from fractures is possible only by targeting the brittle fracture prone layer near the reservoir top of the vicinity of faults. © 2006 Elsevier B.V. All rights reserved. Keywords: Kuwait; Carbonate reservoir; Faults; Fracture corridors; Layer-bound fractures
1. Introduction The Minagish structure in south Kuwait is a multi reservoir field (Fig. 1). One of the potential reservoirs is the argillaceous limestone of the Mishref Formation (Fig. 2). Although porosity ranges between 12–28%, permeability of the Mishref is low (0.1 to 7 mD) due to the fine grain size. The oil within this low permeability reservoir is viscous and has a low GOR, hence producing it will be a challenge. However, since the Minagish structure is highly faulted and fractured and ⁎ Corresponding author. Tel.: +966 50 482 8125; fax: +973 17 710 710. E-mail address: [email protected] (S.I. Ozkaya). 0920-4105/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2006.04.008
significant water drive is absent, a potential development strategy could be based on fracture production. The production history of an early vertical well has been promising with the well test indicating a fracture intersection. The matrix permeability is a few mD only but the system permeability around the vertical well with the conductive fault is above 50 mD. A horizontal well was drilled in order to test if fractures could provide sufficient permeability for economical production. The horizontal well was completed barefoot over the low permeability formation and drilled in an E/W orientation in an attempt to intersect a great number of faults. Unfortunately, the rapid production decline and the extreme low bottom hole pressure have been disappointing.
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Fig. 1. Location map and seismic time slice showing position and orientation of horizontal well and interpreted faults.
An integrated fracture study was initiated in order to understand the well behavior and evaluate fracture flow potential of the low permeability formation. The study was based mainly on openhole logs, and borehole image and production data from the horizontal well, and pressure transient analysis from the vertical well. Additional data included core observation, and the regional structural and stress information. The objectives were to (i) differentiate fracture corridors from layer bound fractures, and (ii) extract fracture parameters for near wellbore dual porosity black oil simulation. The simulation study aimed at fine tuning fracture parameters from image logs, and matrix fracture transfer relationships by history matching. The pressure transient data from the vertical well was reviewed to confirm the earlier conclusion that the well intersects a conductive fault. The
in situ stress direction was determined from the acoustic image log of a nearby vertical well. Data available for this study included core porosity–permeability measurements from several wells with cores, borehole image logs, PVT data, production history from the horizontal well and pressure transient data from the vertical well. The work flow started with the structural interpretation of the borehole image log followed by separation of fracture corridors and layer bound fractures, and the extraction of statistical properties, including orientation and orientation corrected spacing for open and cemented fractures, fracture corridors and fractured layers. The next step was to estimate fracture aperture and calculate a permeability index for fractured layers and fracture corridors. Fracture conductivity is proportional to third power of fracture aperture based on Snow's formula
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Fig. 2. A portion of the Kuwait stratigraphy showing age and stratigraphic position of the Mishref Formation.
(Snow, 1969; Aguilera, 1995). Fracture aperture was estimated from the resistivity image log using the method proposed by Luthi and Souhaitae (1990). Well test interpretation and single well simulation were interactively utilized along with fracture data from borehole image logs to estimate fracture corridor length and to fine tune fracture models. This present paper focuses only on fracture interpretation from the borehole image log. 2. Structural and fracture overview An overview of the structural, stratigraphic and fracture interpretation from the borehole image log of
Fig. 4. Fracture rose diagrams. Conductive fractures have NW/SE and cemented fractures have NW/SE strike. Large conductive fractures have both NW/SE and NE/SW strike.
the horizontal well is presented in this section. The next section provides details of the fracture analysis. 2.1. Structure and reservoir units Seismic maps in the vicinity of the horizontal well indicate NE/SW, NW/SE and N/S faults. Some of the interpreted faults intersect the borehole trajectory (Fig. 1). Open hole and borehole image logs reveal 3 major faults: two in NW/SE (F1 and F3) and one in N/S direction (F2) (Fig. 3). The NW/SE and N/S faults from logs seem to correspond to the seismic faults. The NE/SW fault near the start of the borehole may correspond to the NE/SW
Fig. 3. Schematic near wellbore structural map. The well intersects the top three units of the Mishref reservoir and a fracture corridor (FCR1) three normal faults with NW/SE (F1 and F3) strike and N/S strike (F2). The faults are visible on the seismic.
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fracture corridor. Image logs have no indication of the second NE/SW fault which is expected to intersect the borehole in the middle. This fault is perhaps truncated by a NW/SE fault. If this is indeed the case, one has to conclude that some NW/SE faults are younger than the NE/SW faulting. The data from seismic is not conclusive. Borehole images, cores from offset wells and openhole logs indicate the borehole intersects three major reservoir units corresponding to the top three members of the Mishref Formation (Fig. 3): Unit 1 Very low macro porosity-brittle layer with negligible matrix permeability.
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Unit 2 Medium to high macro porosity with 1–10 mD permeability. This is the only unit with some reservoir properties. Unit 3 Medium to high micro porosity with negligible or no matrix permeability. Open hole and borehole image logs clearly indicate displacement along all three faults F1, F2 and F3 (Fig. 3). The dip angle of the faults and possible sequence of layers suggest that the faults are normal faults, but it is not possible to determine the exact amount of normal or strike slip displacement from the open hole and image log alone. Bedding dips, borehole trajectory and faulting
Fig. 5. The three major faults are clearly evidenced by sharp changes in acoustic log. Fractured layers correspond to low porosity intervals.
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Fig. 6. Most of the fractures are layer bound fractures confined to thin brittle layers. The fractured layers are 2–10 in. thick within Unit 2 and 3. Two of the fracture layers in are 2–3 ft thick. NW/SE and N/S faults that are intersected by this well have only small (few fractures) corridors. One NE/SW corridor intersected in Unit 1 is a major corridor with 20 ft width, several small and large fractures and about one Darcy permeability.
suggest that the borehole trajectory intersected a section of eastward dipping layers of the Mishref at about 6000 ft depth. The borehole started in Unit 1 drilled downward until 6500 m and then up into Unit 2 and 3 (Fig. 4).
2.2. Fracture types and orientation A total of 734 fractures were picked from 3500 ft borehole image log. The fractures are subdivided into cemented and conductive fractures, large conductive
Fig. 7. This cross section view is intended to illustrate the geometry of the borehole intersecting a brittle fractured layer and the resulting borehole image.
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fractures and faults. The dominant fracture orientation is NE/SW with a secondary set of NW/SE striking fractures (Fig. 4). Fracture dip is steep with a mode at 85° suggesting that most fractures are layer-bound or related to strike slip faulting. Conductive fractures have a strong NE/SW trend whereas cemented fractures strike NW/SE. 2.3. Fracture clustering and interpretation A large percentage of fractures in the Mishref reservoir are highly clustered in discrete swarms as is clearly exhibited by a depth vs. layer-bound fracture density plot with a high coefficient of variation close to 2 (Fig. 5). Fracture swarms whose spacing and height depends on the layer thickness, porosity, clay and dolomite volume etc. are grouped as layer-bound fractures. These fractures often have close spacing in thin brittle layers and stop at layer boundaries. One fracture swarm near the heel of the borehole is interpreted as a fracture corridor (FRC1 — Fig. 5). In fact this is the only major fracture corridor identified in the well. A fracture corridor is a cluster of fractures associated with a fault or incipient fault (a small fault with no observable displacement). The low dip angles of fractures within the fracture corridor (55–65 degrees) suggest normal faulting. Interestingly, this fracture
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corridor is not associated with a visible fault. On the other hand, faults with clear displacements: F1, F2 and F3 do not have large fracture corridors, but only a few large fractures nearby. Large conductive fractures with more than 0.3 mm estimated apertures constitute only 4% of the total number of open fractures (Fig. 4) but are regarded to be very significant in determining fracture conductivity. Large conductive fractures occur mainly within the fracture corridor. Fig. 6 is the vertically exaggerated cross section view of fracture interpretation. Yellow bands indicate fractured layers and green stripes are fault related fracture corridors. With the exception of the major fracture corridor near the start (FCR1), most fractures are layer bound fracture clusters within highly fractured brittle thin layers. The fractured layers are 2–5 in. thick within Units 2 and 3. Vertical cores from the reservoir confirm the image log interpretation i.e. the reservoir consists of alternating ductile non-fractured intervals and thin brittle fractured intervals. 3. Layer-bound fractures Bedding is consistently NE/SW with an average dip angle of 3°. The structural section in Fig. 6 is based on the eastward dip of the formations, borehole trajectory
Fig. 8. A fracture corridor is a sub-vertical tabular body of fractures intersecting entire reservoir section. Fracture corridors are often associated with fault or incipient faults. It is assumed that the fracture corridor is wide with many fractures within Unit 1. The same corridor is expected to disappear downward in Unit 3.
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and faulting. Layer spacing and fracture spacing are correlated in order to investigate the relationship between layer thickness and fracture spacing. Although the TVD-density plots suggest fracture density is proportional to layer thickness, the correlation is low (R = 0.21). One explanation is that fracture spacing is not only correlated to layer spacing but also porosity and brittleness of the layers. Image logs suggest fractures are clustered in thin brittle layers. The image example in Fig. 7 shows thin brittle highly fractured layers intersected by the wellbore at an angle. The average conductive layer-bound fracture spacing 4.27 ft and the cemented layer-bound fracture spacing is 24.25 m, but the fracture spacing can be much smaller within thin brittle layers (3 to 5 in.). Although there is no general correlation, fracture spacing and layer thickness seem to be well correlated within the thin brittle layers (Narr, 1996; Bai and Pollard, 2000). 3.1. Layer-bound fracture connectivity and permeability It is possible to estimate fracture connectivity from the frequency of intersecting fractures in borehole image logs (Ozkaya and Mattner, 2003). Even though fracture spacing is very small, intersecting fractures are never observed within the thin, brittle layers of the Mishref Formation thereby raising doubts whether fractures within these thin layers are interconnected. Connectivity can also be determined from length, density and angular scatter of fractures (David et al., 1990; Hestir and Long, 1990). The average fracture spacing is 3.8 ft with an average conductive fracture spacing of 4.5 ft, and cemented fracture spacing of 22.9 ft. Fracture height from relative abundance of partial and full trace fractures is 0.55 ft (16 cm). Fracture length is estimated as 4.26 ft (1.3 m). Layer-bound fractures within the thin brittle layers are found to be below percolation from these fracture density, orientation scatter and length values. The estimated fracture aperture range between 0.02 to 0.03 mm, accordingly, the maximum possible fracture permeability within the thin brittle layers lies between 2 to 10 mD. The total number of brittle layers intersected within 40 ft stratigraphic interval is about 17. With an average thickness of 4 in., these layers enhance matrix permeability from 1 to 2 mD for maximum fracture permeability of 10 mD, and from 1 to 1.2 mD for a minimum fracture permeability of 2 mD. The improvement is not significant and lies within the matrix permeability variation even if fractures are interconnected. Layer bound fractures within the thin brittle layers can play a marginal role at best in the low permeability matrix intervals.
3.2. Highly fractured brittle layers within Unit 1 Most brittle layers with closely spaced fracturing are a few inches thick, however, fractured brittle layers, within Unit 1 are much thicker than in layers 2 and 3. One of the highly fractured layers near the top is 2 ft (0.6 m) thick with a fracture spacing of 0.6 ft (18 cm). This brittle layer (BL1 — Figs. 5 and 6) has two sets of fractures NE/SW and NW/SE. NE/SW fractures are more abundant, but NW/SE fractures have wider apertures. It is difficult to decide whether the fracture swarm represents a fracture corridor or a highly fractured layer. The confinement of fracture swarm to a brittle layer points to layer-bound fractures. It is, however, possible that two sets of fractures appear in this layer because the location is not far from a NW/SE striking fault. Layer bound fracture density increases near faults within brittle layers. If the fault is not parallel to the dominant NE/SW open joints, a second set of layer-bound fractures will appear within the brittle layers, which are parallel to the nearby fault. The frequency of intersecting fractures indicates fractures within the brittle layer in Unit 1 (BL1) are
Fig. 9. Two fracture corridor models are possible: (A) high permeability fracture corridors are generated only in NE direction possibly because NE faults are normal faults. NW and NS faults are strike slip faults with no fracture corridors. (B) Fracture corridors are generated only within the brittle Unit 1, irrespective of the direction of faulting.
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Fig. 10. This diagram shows a NW/SE fault displacing a brittle resistive layer. The fault is a NW/SE striking normal fault. Bedding dip changes suggest fault drag. The change in dip direction of layer-bound fractures within the resistive layer indicates that NE/SW jointing was before NW faulting.
above percolation (Ozkaya and Mattner, 2003). Twenty percent of the fractures intersect other fractures within this layer. It appears that reservoir Unit 1 has thick brittle layers with interconnected fractures and high fracture flow potential. The minimum fracture permeability of this particular layer is 20 mD for an aperture of 0.05 mm and the maximum is 175 mD for an aperture of 0.1 mm. The conductivity of the layer varies between 40– 450 mD ft. Even at the low end of the permeability range this fractured layer has significantly higher permeability than the best matrix producer — Unit 2. At the higher end of the range, such fractured layers may approach fracture corridors in their capacity to conduct fluids. 4. Fracture corridors and faults As noted earlier, only one major fracture corridor was encountered in this well (FCR1 — Figs. 3, 5 and 6). A cluster of fractures within Unit 1 near the top of the open hole interval is interpreted as a fracture corridor. Fracture spacing within the corridor is 1 ft with a fracture height of 1 ft and estimated fracture length of 4 ft. Six of the 20 conductive fractures are large open fractures and 3 are intersecting fractures. The corridor is within sub-percolation range with a high fracture flow potential. The high
resistivity of the wall rock may be attributed to host rock alteration. This fracture corridor FCR1 is 20 ft wide and has several large fractures, unlike the small fracture corridors near the faults. One possible interpretation is shown in Fig. 8. This fracture corridor is wide within the brittle Unit 1 and becomes narrow in Unit 2 and disappear in Unit 3, because Unit 1 is brittle and prone to fracturing, whereas Unit 2 and in particular Unit 3 are ductile and less prone to fracturing. Two of the three faults (F1 and F3) have a few open fractures nearby which have an estimated effective permeability of 250 and 50 mD respectively. The major fracture corridor within Unit 1 has an estimated average effective permeability of 794 mD (for 100 ft wide interval). The absence of fracture corridors along the faults is noteworthy. The three NW/SE faults (F1, F2 and F3) have either no fracture corridors or only a few fractures nearby. This can be explained in two ways: (i) fracture corridors are generated only at the intersection of faults and brittle layers (Fig. 8). In the horizontal well, the faults are intersected within layers 2 and 3, which are not prone to fracturing. (ii) Only NE/SW faults are extensional faults and generate corridors, NW/SE faults are strike slip faults and did not generate opening mode fracture swarms (Fig. 9). Presence of NW/SE large
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SW fracturing and faulting is the latest stage (Fig. 11B). The fractures in Fig. 10 seem to stop at the fault, not because of truncation by the fault, but because the fault is a boundary of the brittle layer in which these fractures were generated long after the fault displacement. Presence of open NW/SE fractures, however, both in the vicinity of the faults and within the main fractured layer at the top of Unit 1 support the first option that there is a second stage of NW/SE faulting following the NE/SW faulting and fracturing episode. The NW/SE set is probably related to the Late Cretaceous NW/SE compression and the NE/SW system belongs to the Late Miocene Zagros tectonics. NE/SW open fractures are parallel to present day maximum horizontal in-situ stress. If option (i) is the right interpretation, it is necessary to think that there was a brief period of NW/SE compression during Pliocene to Pleistocene times. Further investigation of this tectonic even is beyond the scope of this work. 6. Fracture and fracture flow models
Fig. 11. The age of faulting and fracturing cannot be determined from image logs. Most cemented fractures have NW/SE strike, and most open fractures strike NE/SW. The well intersected possible a NW/SE cemented fault. Both N/S and NW/SE faults displace fractured brittle layers with NE/SW joints. This can be interpreted in two ways: A. there are three stages of faulting: early NW/SE followed by NE/SW and a late stage NW/SE faulting again. B. There is only one stage of NW/SE faulting followed by NE/SW faulting and jointing.
A composite fracture model is presented in Fig. 12, which was constructed on the basis of structural and fracture interpretation of borehole image and open hole logs of the horizontal well. The model suggests two types of fractures, (i) layer bound fractures which are confined to thin brittle layers within Unit 2 and 3, but populate 1–2 ft thick brittle layers within Unit 1 such as BL1 and (ii) sub-vertical fracture corridors. One major corridor is located within Unit 1 at 6200 ft (FCR1). This corridor does not seem to be associated with any fault
conductive fractures rule out the second option indicating the degree of fracturing is largely controlled by mechanical layer characteristics. 5. Timing of faults and fractures The clear difference in orientation, cementation suggests an early stage of NW/SE fracturing and a much later stage of NE/SW fracturing (Fig. 4). It appears one of the NW/SE faults seem to truncate fractured layers with NE/SW open fractures (Fig. 10). This can be interpreted in two different ways: (i) there are two stages of NW/SE faulting. The first stage is before and the second stage is after the NE/SW faulting and fracturing (Fig. 11A). (ii) An alternative explanation is that the NE/
Fig. 12. Joints within fractured thin layers are not interconnected. The brittle jointed layers occur as lenses. This model is based on the assumption that fracture corridors are confined to Unit 1. Faults within Unit 2 and 3 do not cause corridors.
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Fig. 13. Fracture flow model 1. In this model, the borehole drains the porous Unit 2 through fractured corridor FCR1 and fractured layer BL1.
displacement. The borehole intersected 3 faults with displacement (F1, F2 and F3). These faults have either no fracture corridor or a small corridor. Possible explanations why the faults are not associated with fracture corridors were discussed before. The 3D schematic fracture model is based on the assumption that fracture corridors are generated at the intersection of faults with Unit 1 and are particularly well developed within brittle layers of layer 1. Fractured thick brittle layers within unit 1such as BL1 and fracture corridors
such as FCR1 may have significant fracture permeability. The NW/SE faults in other ductile units such as F1 F2 and F3 either have no or small fracture flow potential. 6.1. Fracture flow models Oil storage and matrix permeability is provided mainly by Unit 2 which has a relatively high porosity and some matrix permeability. Fractures can provide
Fig. 14. Fracture flow model 2. In this case, borehole intersect FCR1 and drains porous Unit 2 through the fracture corridor. This model represents the most effective drainage geometry.
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sustained production only if they are able to drain Unit 2. There are three possible mechanisms: 1. The borehole intersects fractured layers only such as BL1. Fracture corridors FRC1 join fractured layer BL1. Oil flows from Unit 2 into well via BL1. Oil is transferred into the horizontal fractured layer BL1 by the sub-vertical fracture corridor FCR1 from Unit 2 (Fig. 13). 2. The borehole intersects fracture corridor FCR1 and drains Unit 2 directly through the fracture corridor (Fig. 14). 3. The Borehole intersects fractured layer BL1, which directly drain Unit 2. Fault displacement brings B L1 in direct juxtaposition with the porous Unit 2 (Fig. 15). The most effective configuration is represented by option 2. The best development strategy would be to drill highly deviated wells targeting faults within Unit 1. This study assumes that Unit 1 and 2 have similar very low porosity. The borehole images and openhole logs from a nearby vertical well show that the interval designated as Unit 1 can be highly porous. Both Unit 1 and Unit 2 have brittle fracture prone layers. If these layers are fractured they may directly drain the porous matrix. These different flow models were tested as different single well black oil simulation scenarios using dual
porosity simulator (Kazemi et al., 1976). A history match can be obtained only for the second model for the horizontal well, but models 1 and 3 also have high fracture flow potential and remain as viable production mechanisms. 7. In-situ stress Breakouts from a nearby vertical well show that maximum in-situ stress orientation is about N25E (Hillis and Thomas, 1999). Most of the open fractures in the horizontal well under study strike NE/SW parallel to the present day maximum in-situ stress. A likely interpretation is that the NE/SW fractures were generated in Late Tertiary. It is also possible that some of the NE/SW fractures are drilling enhanced. The NE/SW fractures and faults, being parallel to the maximum in-situ stress, are expected to have a greater fluid flow potential than faults ad fractures in NW/SE and N/S directions. 8. Conclusion The main conclusions of the fracture interpretation of the horizontal well can be summarized as follows: 1. A high degree of structural deformation and faulting does not guarantee abundant fluid conductive
Fig. 15. Fracture flow mode 3. In this scenario, faulting brings fractured layer BL1 in direct contact with porous Unit 2 and the borehole drains the porous unit through BL1.
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fractures, either because fractures are cemented or reservoir units are ductile and not prone to fracturing. 2. This particular Mishref reservoir has at least three stages of intense faulting but the reservoir has only a limited fracture flow potential because (i) The early stage of NW/SE faults and fractures were all cemented. (ii)NE/SW fractures generated by recent tectonic episodes and very recent NW/SE fault rejuvenation are open and fluid conductive. 3. Unfortunately, faulting created fractures only within the brittle layers which are mostly a few inches thick and dispersed within thick low porosity and ductile units. 4. Only the 2–5 ft thick brittle layer within Unit 1 has the potential to generate wide fracture corridors nearby faults. Faults have few associated fracturing in other units. In this particular reservoir, production from fractures is possible only by targeting the brittle fracture prone layer near reservoir top in the vicinity of faults. Acknowledgement The authors would like to thank KOC for funding this project and the Kuwait Oil Ministry for the permission to present and publish it. The authors would also like to thank all the members of KOC southern Kuwait
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development team, in particular petrophysicist Christ Smart for their contribution and guidance. References Aguilera, R., 1995. Naturally Fractured Reservoirs. PennWell Books, Tulsa, Oklahoma. Bai, T., Pollard, D., 2000. Fracture spacing in layered rocks: a new explanation based on the stress transition. J. Struct. Geol. 22, 43–57. David, C., Gueguen, Y., Pampoukis, G., 1990. Effective medium theory and network theory applied to the transport properties of rock. J. Geophys. Res. 95, 6993–7005. Hestir, K., Long, J.C.S., 1990. Analytical expressions for the permeability of random two dimensional Poisson fracture networks based on regular lattice percolation and equivalent media theories. J. Geophys. Res. 95, 517–542. Hillis, R.R., Thomas, S., 1999. Wellbore failure induced by formation testing. Pet. Geosci. 5, 235–239. Kazemi, H., Merrill, L., Porterfield, K., Zeman, P., 1976. Numerical simulation of water-oil flow in naturally fractured reservoirs. Soc. Pet. Eng. J. 317–326 (Dec. 1976). Luthi, S.M., Souhaitae, P., 1990. Fracture apertures from electrical borehole scans. Geophysics 55, 821–833. Narr, W., 1996. Estimating average fracture spacing in subsurface rock. AAPG Bull. 80, 1565–1586. Ozkaya, S.I., Mattner, J., 2003. Fracture connectivity from fracture intersections in borehole image logs. Comput. Geosci. 29, 143–153. Snow, D.T., 1969. Anisotropic permeability of fractured media. Water Resour. Res. 5, 1273–1289.
Fracture study of a horizontal well in a tight reservoir — Kuwait S.I. Ozkaya a,⁎, H.J. Lewandoswki b , S.B. Coskun a a
Baker Atlas Geoscience, PO Box 15425, Manama, Bahrain b Kuwait Oil Company, Kuwait Received 3 May 2005; accepted 26 April 2006
Abstract An integrated fracture study was conducted to evaluate the fracture flow potential of the low permeability Mishref Formation, using electrical open hole logs, borehole images and production data from a horizontal well, and pressure transient analysis from a vertical well. Image logs show at least three stages of intense faulting and fracturing but the reservoir has only a limited fracture flow potential because (i) the early stage of NW/SE faults and fractures were all cemented. (ii) Although NE/SW fractures generated by recent tectonic episodes and very recent NW/SE fault rejuvenation are open and fluid conductive, faulting created fractures only within the brittle layers, which are a few inches thick and dispersed within thick low porosity and ductile units. Faults have wide fractured zones with flow potential only within a 2–5 ft thick brittle layer close to the reservoir top. The development of fracture permeability in a reservoir requires not only deformation and faulting but also the presence of mechanical layers which are prone to fracturing. A high degree of faulting is not a guarantee for a high degree of fracturing. In this particular reservoir, production from fractures is possible only by targeting the brittle fracture prone layer near the reservoir top of the vicinity of faults. © 2006 Elsevier B.V. All rights reserved. Keywords: Kuwait; Carbonate reservoir; Faults; Fracture corridors; Layer-bound fractures
1. Introduction The Minagish structure in south Kuwait is a multi reservoir field (Fig. 1). One of the potential reservoirs is the argillaceous limestone of the Mishref Formation (Fig. 2). Although porosity ranges between 12–28%, permeability of the Mishref is low (0.1 to 7 mD) due to the fine grain size. The oil within this low permeability reservoir is viscous and has a low GOR, hence producing it will be a challenge. However, since the Minagish structure is highly faulted and fractured and ⁎ Corresponding author. Tel.: +966 50 482 8125; fax: +973 17 710 710. E-mail address: [email protected] (S.I. Ozkaya). 0920-4105/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2006.04.008
significant water drive is absent, a potential development strategy could be based on fracture production. The production history of an early vertical well has been promising with the well test indicating a fracture intersection. The matrix permeability is a few mD only but the system permeability around the vertical well with the conductive fault is above 50 mD. A horizontal well was drilled in order to test if fractures could provide sufficient permeability for economical production. The horizontal well was completed barefoot over the low permeability formation and drilled in an E/W orientation in an attempt to intersect a great number of faults. Unfortunately, the rapid production decline and the extreme low bottom hole pressure have been disappointing.
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Fig. 1. Location map and seismic time slice showing position and orientation of horizontal well and interpreted faults.
An integrated fracture study was initiated in order to understand the well behavior and evaluate fracture flow potential of the low permeability formation. The study was based mainly on openhole logs, and borehole image and production data from the horizontal well, and pressure transient analysis from the vertical well. Additional data included core observation, and the regional structural and stress information. The objectives were to (i) differentiate fracture corridors from layer bound fractures, and (ii) extract fracture parameters for near wellbore dual porosity black oil simulation. The simulation study aimed at fine tuning fracture parameters from image logs, and matrix fracture transfer relationships by history matching. The pressure transient data from the vertical well was reviewed to confirm the earlier conclusion that the well intersects a conductive fault. The
in situ stress direction was determined from the acoustic image log of a nearby vertical well. Data available for this study included core porosity–permeability measurements from several wells with cores, borehole image logs, PVT data, production history from the horizontal well and pressure transient data from the vertical well. The work flow started with the structural interpretation of the borehole image log followed by separation of fracture corridors and layer bound fractures, and the extraction of statistical properties, including orientation and orientation corrected spacing for open and cemented fractures, fracture corridors and fractured layers. The next step was to estimate fracture aperture and calculate a permeability index for fractured layers and fracture corridors. Fracture conductivity is proportional to third power of fracture aperture based on Snow's formula
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Fig. 2. A portion of the Kuwait stratigraphy showing age and stratigraphic position of the Mishref Formation.
(Snow, 1969; Aguilera, 1995). Fracture aperture was estimated from the resistivity image log using the method proposed by Luthi and Souhaitae (1990). Well test interpretation and single well simulation were interactively utilized along with fracture data from borehole image logs to estimate fracture corridor length and to fine tune fracture models. This present paper focuses only on fracture interpretation from the borehole image log. 2. Structural and fracture overview An overview of the structural, stratigraphic and fracture interpretation from the borehole image log of
Fig. 4. Fracture rose diagrams. Conductive fractures have NW/SE and cemented fractures have NW/SE strike. Large conductive fractures have both NW/SE and NE/SW strike.
the horizontal well is presented in this section. The next section provides details of the fracture analysis. 2.1. Structure and reservoir units Seismic maps in the vicinity of the horizontal well indicate NE/SW, NW/SE and N/S faults. Some of the interpreted faults intersect the borehole trajectory (Fig. 1). Open hole and borehole image logs reveal 3 major faults: two in NW/SE (F1 and F3) and one in N/S direction (F2) (Fig. 3). The NW/SE and N/S faults from logs seem to correspond to the seismic faults. The NE/SW fault near the start of the borehole may correspond to the NE/SW
Fig. 3. Schematic near wellbore structural map. The well intersects the top three units of the Mishref reservoir and a fracture corridor (FCR1) three normal faults with NW/SE (F1 and F3) strike and N/S strike (F2). The faults are visible on the seismic.
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fracture corridor. Image logs have no indication of the second NE/SW fault which is expected to intersect the borehole in the middle. This fault is perhaps truncated by a NW/SE fault. If this is indeed the case, one has to conclude that some NW/SE faults are younger than the NE/SW faulting. The data from seismic is not conclusive. Borehole images, cores from offset wells and openhole logs indicate the borehole intersects three major reservoir units corresponding to the top three members of the Mishref Formation (Fig. 3): Unit 1 Very low macro porosity-brittle layer with negligible matrix permeability.
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Unit 2 Medium to high macro porosity with 1–10 mD permeability. This is the only unit with some reservoir properties. Unit 3 Medium to high micro porosity with negligible or no matrix permeability. Open hole and borehole image logs clearly indicate displacement along all three faults F1, F2 and F3 (Fig. 3). The dip angle of the faults and possible sequence of layers suggest that the faults are normal faults, but it is not possible to determine the exact amount of normal or strike slip displacement from the open hole and image log alone. Bedding dips, borehole trajectory and faulting
Fig. 5. The three major faults are clearly evidenced by sharp changes in acoustic log. Fractured layers correspond to low porosity intervals.
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Fig. 6. Most of the fractures are layer bound fractures confined to thin brittle layers. The fractured layers are 2–10 in. thick within Unit 2 and 3. Two of the fracture layers in are 2–3 ft thick. NW/SE and N/S faults that are intersected by this well have only small (few fractures) corridors. One NE/SW corridor intersected in Unit 1 is a major corridor with 20 ft width, several small and large fractures and about one Darcy permeability.
suggest that the borehole trajectory intersected a section of eastward dipping layers of the Mishref at about 6000 ft depth. The borehole started in Unit 1 drilled downward until 6500 m and then up into Unit 2 and 3 (Fig. 4).
2.2. Fracture types and orientation A total of 734 fractures were picked from 3500 ft borehole image log. The fractures are subdivided into cemented and conductive fractures, large conductive
Fig. 7. This cross section view is intended to illustrate the geometry of the borehole intersecting a brittle fractured layer and the resulting borehole image.
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fractures and faults. The dominant fracture orientation is NE/SW with a secondary set of NW/SE striking fractures (Fig. 4). Fracture dip is steep with a mode at 85° suggesting that most fractures are layer-bound or related to strike slip faulting. Conductive fractures have a strong NE/SW trend whereas cemented fractures strike NW/SE. 2.3. Fracture clustering and interpretation A large percentage of fractures in the Mishref reservoir are highly clustered in discrete swarms as is clearly exhibited by a depth vs. layer-bound fracture density plot with a high coefficient of variation close to 2 (Fig. 5). Fracture swarms whose spacing and height depends on the layer thickness, porosity, clay and dolomite volume etc. are grouped as layer-bound fractures. These fractures often have close spacing in thin brittle layers and stop at layer boundaries. One fracture swarm near the heel of the borehole is interpreted as a fracture corridor (FRC1 — Fig. 5). In fact this is the only major fracture corridor identified in the well. A fracture corridor is a cluster of fractures associated with a fault or incipient fault (a small fault with no observable displacement). The low dip angles of fractures within the fracture corridor (55–65 degrees) suggest normal faulting. Interestingly, this fracture
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corridor is not associated with a visible fault. On the other hand, faults with clear displacements: F1, F2 and F3 do not have large fracture corridors, but only a few large fractures nearby. Large conductive fractures with more than 0.3 mm estimated apertures constitute only 4% of the total number of open fractures (Fig. 4) but are regarded to be very significant in determining fracture conductivity. Large conductive fractures occur mainly within the fracture corridor. Fig. 6 is the vertically exaggerated cross section view of fracture interpretation. Yellow bands indicate fractured layers and green stripes are fault related fracture corridors. With the exception of the major fracture corridor near the start (FCR1), most fractures are layer bound fracture clusters within highly fractured brittle thin layers. The fractured layers are 2–5 in. thick within Units 2 and 3. Vertical cores from the reservoir confirm the image log interpretation i.e. the reservoir consists of alternating ductile non-fractured intervals and thin brittle fractured intervals. 3. Layer-bound fractures Bedding is consistently NE/SW with an average dip angle of 3°. The structural section in Fig. 6 is based on the eastward dip of the formations, borehole trajectory
Fig. 8. A fracture corridor is a sub-vertical tabular body of fractures intersecting entire reservoir section. Fracture corridors are often associated with fault or incipient faults. It is assumed that the fracture corridor is wide with many fractures within Unit 1. The same corridor is expected to disappear downward in Unit 3.
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and faulting. Layer spacing and fracture spacing are correlated in order to investigate the relationship between layer thickness and fracture spacing. Although the TVD-density plots suggest fracture density is proportional to layer thickness, the correlation is low (R = 0.21). One explanation is that fracture spacing is not only correlated to layer spacing but also porosity and brittleness of the layers. Image logs suggest fractures are clustered in thin brittle layers. The image example in Fig. 7 shows thin brittle highly fractured layers intersected by the wellbore at an angle. The average conductive layer-bound fracture spacing 4.27 ft and the cemented layer-bound fracture spacing is 24.25 m, but the fracture spacing can be much smaller within thin brittle layers (3 to 5 in.). Although there is no general correlation, fracture spacing and layer thickness seem to be well correlated within the thin brittle layers (Narr, 1996; Bai and Pollard, 2000). 3.1. Layer-bound fracture connectivity and permeability It is possible to estimate fracture connectivity from the frequency of intersecting fractures in borehole image logs (Ozkaya and Mattner, 2003). Even though fracture spacing is very small, intersecting fractures are never observed within the thin, brittle layers of the Mishref Formation thereby raising doubts whether fractures within these thin layers are interconnected. Connectivity can also be determined from length, density and angular scatter of fractures (David et al., 1990; Hestir and Long, 1990). The average fracture spacing is 3.8 ft with an average conductive fracture spacing of 4.5 ft, and cemented fracture spacing of 22.9 ft. Fracture height from relative abundance of partial and full trace fractures is 0.55 ft (16 cm). Fracture length is estimated as 4.26 ft (1.3 m). Layer-bound fractures within the thin brittle layers are found to be below percolation from these fracture density, orientation scatter and length values. The estimated fracture aperture range between 0.02 to 0.03 mm, accordingly, the maximum possible fracture permeability within the thin brittle layers lies between 2 to 10 mD. The total number of brittle layers intersected within 40 ft stratigraphic interval is about 17. With an average thickness of 4 in., these layers enhance matrix permeability from 1 to 2 mD for maximum fracture permeability of 10 mD, and from 1 to 1.2 mD for a minimum fracture permeability of 2 mD. The improvement is not significant and lies within the matrix permeability variation even if fractures are interconnected. Layer bound fractures within the thin brittle layers can play a marginal role at best in the low permeability matrix intervals.
3.2. Highly fractured brittle layers within Unit 1 Most brittle layers with closely spaced fracturing are a few inches thick, however, fractured brittle layers, within Unit 1 are much thicker than in layers 2 and 3. One of the highly fractured layers near the top is 2 ft (0.6 m) thick with a fracture spacing of 0.6 ft (18 cm). This brittle layer (BL1 — Figs. 5 and 6) has two sets of fractures NE/SW and NW/SE. NE/SW fractures are more abundant, but NW/SE fractures have wider apertures. It is difficult to decide whether the fracture swarm represents a fracture corridor or a highly fractured layer. The confinement of fracture swarm to a brittle layer points to layer-bound fractures. It is, however, possible that two sets of fractures appear in this layer because the location is not far from a NW/SE striking fault. Layer bound fracture density increases near faults within brittle layers. If the fault is not parallel to the dominant NE/SW open joints, a second set of layer-bound fractures will appear within the brittle layers, which are parallel to the nearby fault. The frequency of intersecting fractures indicates fractures within the brittle layer in Unit 1 (BL1) are
Fig. 9. Two fracture corridor models are possible: (A) high permeability fracture corridors are generated only in NE direction possibly because NE faults are normal faults. NW and NS faults are strike slip faults with no fracture corridors. (B) Fracture corridors are generated only within the brittle Unit 1, irrespective of the direction of faulting.
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Fig. 10. This diagram shows a NW/SE fault displacing a brittle resistive layer. The fault is a NW/SE striking normal fault. Bedding dip changes suggest fault drag. The change in dip direction of layer-bound fractures within the resistive layer indicates that NE/SW jointing was before NW faulting.
above percolation (Ozkaya and Mattner, 2003). Twenty percent of the fractures intersect other fractures within this layer. It appears that reservoir Unit 1 has thick brittle layers with interconnected fractures and high fracture flow potential. The minimum fracture permeability of this particular layer is 20 mD for an aperture of 0.05 mm and the maximum is 175 mD for an aperture of 0.1 mm. The conductivity of the layer varies between 40– 450 mD ft. Even at the low end of the permeability range this fractured layer has significantly higher permeability than the best matrix producer — Unit 2. At the higher end of the range, such fractured layers may approach fracture corridors in their capacity to conduct fluids. 4. Fracture corridors and faults As noted earlier, only one major fracture corridor was encountered in this well (FCR1 — Figs. 3, 5 and 6). A cluster of fractures within Unit 1 near the top of the open hole interval is interpreted as a fracture corridor. Fracture spacing within the corridor is 1 ft with a fracture height of 1 ft and estimated fracture length of 4 ft. Six of the 20 conductive fractures are large open fractures and 3 are intersecting fractures. The corridor is within sub-percolation range with a high fracture flow potential. The high
resistivity of the wall rock may be attributed to host rock alteration. This fracture corridor FCR1 is 20 ft wide and has several large fractures, unlike the small fracture corridors near the faults. One possible interpretation is shown in Fig. 8. This fracture corridor is wide within the brittle Unit 1 and becomes narrow in Unit 2 and disappear in Unit 3, because Unit 1 is brittle and prone to fracturing, whereas Unit 2 and in particular Unit 3 are ductile and less prone to fracturing. Two of the three faults (F1 and F3) have a few open fractures nearby which have an estimated effective permeability of 250 and 50 mD respectively. The major fracture corridor within Unit 1 has an estimated average effective permeability of 794 mD (for 100 ft wide interval). The absence of fracture corridors along the faults is noteworthy. The three NW/SE faults (F1, F2 and F3) have either no fracture corridors or only a few fractures nearby. This can be explained in two ways: (i) fracture corridors are generated only at the intersection of faults and brittle layers (Fig. 8). In the horizontal well, the faults are intersected within layers 2 and 3, which are not prone to fracturing. (ii) Only NE/SW faults are extensional faults and generate corridors, NW/SE faults are strike slip faults and did not generate opening mode fracture swarms (Fig. 9). Presence of NW/SE large
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SW fracturing and faulting is the latest stage (Fig. 11B). The fractures in Fig. 10 seem to stop at the fault, not because of truncation by the fault, but because the fault is a boundary of the brittle layer in which these fractures were generated long after the fault displacement. Presence of open NW/SE fractures, however, both in the vicinity of the faults and within the main fractured layer at the top of Unit 1 support the first option that there is a second stage of NW/SE faulting following the NE/SW faulting and fracturing episode. The NW/SE set is probably related to the Late Cretaceous NW/SE compression and the NE/SW system belongs to the Late Miocene Zagros tectonics. NE/SW open fractures are parallel to present day maximum horizontal in-situ stress. If option (i) is the right interpretation, it is necessary to think that there was a brief period of NW/SE compression during Pliocene to Pleistocene times. Further investigation of this tectonic even is beyond the scope of this work. 6. Fracture and fracture flow models
Fig. 11. The age of faulting and fracturing cannot be determined from image logs. Most cemented fractures have NW/SE strike, and most open fractures strike NE/SW. The well intersected possible a NW/SE cemented fault. Both N/S and NW/SE faults displace fractured brittle layers with NE/SW joints. This can be interpreted in two ways: A. there are three stages of faulting: early NW/SE followed by NE/SW and a late stage NW/SE faulting again. B. There is only one stage of NW/SE faulting followed by NE/SW faulting and jointing.
A composite fracture model is presented in Fig. 12, which was constructed on the basis of structural and fracture interpretation of borehole image and open hole logs of the horizontal well. The model suggests two types of fractures, (i) layer bound fractures which are confined to thin brittle layers within Unit 2 and 3, but populate 1–2 ft thick brittle layers within Unit 1 such as BL1 and (ii) sub-vertical fracture corridors. One major corridor is located within Unit 1 at 6200 ft (FCR1). This corridor does not seem to be associated with any fault
conductive fractures rule out the second option indicating the degree of fracturing is largely controlled by mechanical layer characteristics. 5. Timing of faults and fractures The clear difference in orientation, cementation suggests an early stage of NW/SE fracturing and a much later stage of NE/SW fracturing (Fig. 4). It appears one of the NW/SE faults seem to truncate fractured layers with NE/SW open fractures (Fig. 10). This can be interpreted in two different ways: (i) there are two stages of NW/SE faulting. The first stage is before and the second stage is after the NE/SW faulting and fracturing (Fig. 11A). (ii) An alternative explanation is that the NE/
Fig. 12. Joints within fractured thin layers are not interconnected. The brittle jointed layers occur as lenses. This model is based on the assumption that fracture corridors are confined to Unit 1. Faults within Unit 2 and 3 do not cause corridors.
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Fig. 13. Fracture flow model 1. In this model, the borehole drains the porous Unit 2 through fractured corridor FCR1 and fractured layer BL1.
displacement. The borehole intersected 3 faults with displacement (F1, F2 and F3). These faults have either no fracture corridor or a small corridor. Possible explanations why the faults are not associated with fracture corridors were discussed before. The 3D schematic fracture model is based on the assumption that fracture corridors are generated at the intersection of faults with Unit 1 and are particularly well developed within brittle layers of layer 1. Fractured thick brittle layers within unit 1such as BL1 and fracture corridors
such as FCR1 may have significant fracture permeability. The NW/SE faults in other ductile units such as F1 F2 and F3 either have no or small fracture flow potential. 6.1. Fracture flow models Oil storage and matrix permeability is provided mainly by Unit 2 which has a relatively high porosity and some matrix permeability. Fractures can provide
Fig. 14. Fracture flow model 2. In this case, borehole intersect FCR1 and drains porous Unit 2 through the fracture corridor. This model represents the most effective drainage geometry.
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sustained production only if they are able to drain Unit 2. There are three possible mechanisms: 1. The borehole intersects fractured layers only such as BL1. Fracture corridors FRC1 join fractured layer BL1. Oil flows from Unit 2 into well via BL1. Oil is transferred into the horizontal fractured layer BL1 by the sub-vertical fracture corridor FCR1 from Unit 2 (Fig. 13). 2. The borehole intersects fracture corridor FCR1 and drains Unit 2 directly through the fracture corridor (Fig. 14). 3. The Borehole intersects fractured layer BL1, which directly drain Unit 2. Fault displacement brings B L1 in direct juxtaposition with the porous Unit 2 (Fig. 15). The most effective configuration is represented by option 2. The best development strategy would be to drill highly deviated wells targeting faults within Unit 1. This study assumes that Unit 1 and 2 have similar very low porosity. The borehole images and openhole logs from a nearby vertical well show that the interval designated as Unit 1 can be highly porous. Both Unit 1 and Unit 2 have brittle fracture prone layers. If these layers are fractured they may directly drain the porous matrix. These different flow models were tested as different single well black oil simulation scenarios using dual
porosity simulator (Kazemi et al., 1976). A history match can be obtained only for the second model for the horizontal well, but models 1 and 3 also have high fracture flow potential and remain as viable production mechanisms. 7. In-situ stress Breakouts from a nearby vertical well show that maximum in-situ stress orientation is about N25E (Hillis and Thomas, 1999). Most of the open fractures in the horizontal well under study strike NE/SW parallel to the present day maximum in-situ stress. A likely interpretation is that the NE/SW fractures were generated in Late Tertiary. It is also possible that some of the NE/SW fractures are drilling enhanced. The NE/SW fractures and faults, being parallel to the maximum in-situ stress, are expected to have a greater fluid flow potential than faults ad fractures in NW/SE and N/S directions. 8. Conclusion The main conclusions of the fracture interpretation of the horizontal well can be summarized as follows: 1. A high degree of structural deformation and faulting does not guarantee abundant fluid conductive
Fig. 15. Fracture flow mode 3. In this scenario, faulting brings fractured layer BL1 in direct contact with porous Unit 2 and the borehole drains the porous unit through BL1.
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fractures, either because fractures are cemented or reservoir units are ductile and not prone to fracturing. 2. This particular Mishref reservoir has at least three stages of intense faulting but the reservoir has only a limited fracture flow potential because (i) The early stage of NW/SE faults and fractures were all cemented. (ii)NE/SW fractures generated by recent tectonic episodes and very recent NW/SE fault rejuvenation are open and fluid conductive. 3. Unfortunately, faulting created fractures only within the brittle layers which are mostly a few inches thick and dispersed within thick low porosity and ductile units. 4. Only the 2–5 ft thick brittle layer within Unit 1 has the potential to generate wide fracture corridors nearby faults. Faults have few associated fracturing in other units. In this particular reservoir, production from fractures is possible only by targeting the brittle fracture prone layer near reservoir top in the vicinity of faults. Acknowledgement The authors would like to thank KOC for funding this project and the Kuwait Oil Ministry for the permission to present and publish it. The authors would also like to thank all the members of KOC southern Kuwait
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development team, in particular petrophysicist Christ Smart for their contribution and guidance. References Aguilera, R., 1995. Naturally Fractured Reservoirs. PennWell Books, Tulsa, Oklahoma. Bai, T., Pollard, D., 2000. Fracture spacing in layered rocks: a new explanation based on the stress transition. J. Struct. Geol. 22, 43–57. David, C., Gueguen, Y., Pampoukis, G., 1990. Effective medium theory and network theory applied to the transport properties of rock. J. Geophys. Res. 95, 6993–7005. Hestir, K., Long, J.C.S., 1990. Analytical expressions for the permeability of random two dimensional Poisson fracture networks based on regular lattice percolation and equivalent media theories. J. Geophys. Res. 95, 517–542. Hillis, R.R., Thomas, S., 1999. Wellbore failure induced by formation testing. Pet. Geosci. 5, 235–239. Kazemi, H., Merrill, L., Porterfield, K., Zeman, P., 1976. Numerical simulation of water-oil flow in naturally fractured reservoirs. Soc. Pet. Eng. J. 317–326 (Dec. 1976). Luthi, S.M., Souhaitae, P., 1990. Fracture apertures from electrical borehole scans. Geophysics 55, 821–833. Narr, W., 1996. Estimating average fracture spacing in subsurface rock. AAPG Bull. 80, 1565–1586. Ozkaya, S.I., Mattner, J., 2003. Fracture connectivity from fracture intersections in borehole image logs. Comput. Geosci. 29, 143–153. Snow, D.T., 1969. Anisotropic permeability of fractured media. Water Resour. Res. 5, 1273–1289.