Energy Fuels 2010, 24, 3020–3027 Published on Web 04/20/2010
: DOI:10.1021/ef1000453
Wettability Impacts on Oil Displacement in Large Fractured Carbonate Blocks A˚smund Haugen,* Martin A. Fernø, Øyvind Bull, and Arne Graue Department of Physics and Technology, University of Bergen, All egaten 55, 5007 Bergen, Norway Received January 14, 2010. Revised Manuscript Received April 1, 2010
Two-dimensional imaging of water and oil saturations during waterfloods in fractured carbonate rock models was obtained using nuclear tracer imaging and magnetic resonance imaging. Large outcrop chalk and limestone blocks were aged in crude oil to obtain wetting conditions from strongly water-wet to weakly oil-wet. The change in the oil recovery mechanism as the wettability shifted was investigated with and without the presence of fractures. Visualization of local, in situ fluid saturations during waterfloods improved the interpretation of the displacement process and oil recovery mechanisms. Experimental results demonstrate how fractures determine the displacement pattern differently depending on the matrix wettability conditions during waterfloods. At strongly water-wet conditions, the fractures had a minor impact on the ultimate recovery but significantly changed the progression of the water front compared to the unfractured case. At less water-wet or oil-wet conditions, capillary imbibition of water from the fracture to the matrix was reduced and fractures had a major impact on the ultimate recovery and water breakthrough time. In addition to matrix wettability, the initial water saturation (IWS) may greatly influence the oil recovery and the rate of recovery during capillary imbibition. The relationship between IWS and the production rates is not straightforward because the production rates were observed to increase with IWS in sandstone, whereas they decreased in chalk. The ultimate recovery decreased with increasing IWS in chalk.10 Waterflooding strongly water-wet (SWW) fractured chalk models shows slightly reduced recovery with increased IWS, while a significant increase in recovery may occur at WWW conditions with IWS.11 The same observations were recently made in slightly water-wet limestone, where both the recovery and the rate of recovery increased with IWS.12 Although countercurrent flow conditions apply to most imbibition experiments,13,14 it has been suggested that cocurrent imbibition may be the dominant process in oil recovery from fractured reservoirs.14,15 Cocurrent imbibition prevails when the matrix block surfaces are partly exposed to water, like in gravity-segregated fractures. Oil will then preferentially flow toward the boundary in contact with the oil. Cocurrent imbibition is faster and has a higher displacement efficiency than countercurrent imbibition.14,16,17 Co- and countercurrent imbibition may coexist during waterfloods in fractured reservoirs,18 depending on the fracture flow.19,20 Low fracture
Introduction Large oil reserves are located in naturally fractured reservoirs, but fractures generally only constitute a small fraction of the total pore volume and oil in place (OIP) of the reservoir, often less than 1%. In type 2 reservoirs,1 fluid flow is focused in the fractures, and most of the oil is stored in the rock matrix. The oil may be displaced from the matrix to the fracture network by capillary imbibition of water. The large surface area open to imbibition of water in highly fractured reservoirs may provide economical production rates even in low-permeability matrix reservoirs. The efficiency of capillary imbibition in fractured reservoirs is also strongly influenced by the wettability of the system.2 The majority of carbonate reservoirs are oil-wet or less water-wet, and capillary imbibition of water will be suppressed or absent. In such reservoirs, water will mainly flow through the fracture network rather than imbibing into the matrix, resulting in early water breakthrough and low hydrocarbon recovery. The wettability state at which maximum recovery occurs during viscous flooding in nonfractured reservoirs is found at weakly water-wet (WWW) conditions and depends on the crude oil/brine/rock system; in Berea sandstone, it occurs at the Amott index to water Iw = 0.2 at very high pore-volume throughputs of water,3 and Iw = 0.4 for Rørdal chalk at very high differential pressures.4 No single wetting state for maximum recovery by viscous flooding has yet been agreed upon.5-9
(10) Viksund, B. G.; Morrow, N. R.; Ma, S.; Graue, A. International Symposium of Society of Core Analysts, The Hague, The Netherlands, 1998. (11) Tang, G.; Firoozabadi, A. SPE Reservoir Eval. Eng. 2001, 516– 524. (12) Karimaie, H.; Torseter, O. J. Pet. Sci. Eng. 2007, 58, 293–308. (13) Morrow, N. R.; Mason, G. Curr. Opin. Colloid Interface Sci. 2001, 6 (4), 321–337. (14) Pooladi-Darvish, M.; Firoozabadi, A. SPE J. 2000, 5 (1), 3–11. (15) Firoozabadi, A. J. Can. Pet. Tech. 2000, 39 (11), 13–17. (16) Bourbiaux, B. J.; Kalaydjian, F. J. SPE Reservoir Eval. Eng. 1990, 5, 361–368. (17) Unsal, E.; Mason, G.; Morrow, N. R.; Ruth, D. J. Colloid Interface Sci. 2006, 306, 105–117. (18) Karpyn, Z. T.; Halleck, P. M.; Grader, A. S. J. Pet. Sci. Eng. 2009, 67, 48–65. (19) Rangel-German, E. R.; Kovscek, A. R. J. Pet. Sci. Eng. 2002, 36 (1-2), 45–60. (20) Rangel-German, E. R.; Kovscek, A. R. Water Resour. Res. 2006, 42.
*To whom correspondence should be addressed. Telephone: þ47 55 58 84 19. E-mail:
[email protected]. (1) Nelson, R. 2nd ed.; Gulf Professional Publishers: Boston, 2001. (2) Zhou, X.; Morrow, N. R.; Ma, S. SPE J. 2000, 5 (2), 199–207. (3) Jadhunandan, P. P.; Morrow, N. R. SPE Reservoir Eng. 1995, 10 (1), 40–46. (4) Johannesen, E. B.; Graue, A. SPE Europe Offshore, Sept 4-7, 2007. (5) Kennedy, H. T.; Burja, E. O. J. Phys. Chem. 1955, 59, 867. (6) Amott, E. Trans. AIME 1959, 216, 156–162. (7) Morrow, N. R.; Mungan, N. Petroleum Recovery Research Institute: Calgary, Canada, 1971. (8) Rathmell, J. J.; Braun, P. H. JPT 1973, 175–85. (9) Lorentz, P. B.; Donaldson, E. C.; Thomas, R. R. U.S. Bureau of Mines, Bartlesville Energy Technology Center: Bartlesville, OK, 1974. r 2010 American Chemical Society
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flow compared to fracture matrix transfer (filling fracture regime) occurs by either a low injection rate, wide fractures, or a high imbibition rate into the matrix and promotes cocurrent imbibition. In the instantly filling regime, fractures rapidly fill with water because of low fracture-matrix transfer, a high injection rate, or narrow fracture and imbibition is predominantly countercurrent. In addition to spontaneous imbibition, capillary continuity between matrix blocks may be an important contributor to increased oil recovery in fractured reservoirs. Capillary continuity provides fluid communication between partially or completely isolated matrix blocks, increasing the recovery by gravity drainage or viscous displacement.21-23 Firoozabadi and Markeset24 observed that the mechanism of oil displacement was in some cases the formation and breakdown of liquid droplets across an open fracture during gravity drainage. Magnetic resonance imaging (MRI) was used to observe that liquid bridges establish capillary continuity across open fractures of up to 2.3 mm aperture at less water-wet conditions.25-27 Complementary imaging by nuclear tracer imaging (NTI) and MRI was successfully used to investigate the significance of wettability and fractures during waterfloods in chalk at different water-wet states by Graue et al.25,28-30 They found that capillary continuity across fractures at less waterwet conditions may provide an additional viscous component across the individual matrix blocks. The viscous component may compensate for the loss in oil recovery by the reduced capillary imbibition and may be an important recovery mechanism at less water-wet conditions. Using the same imaging techniques, we extend the range in wettabilities to oil-wet conditions and include a more heterogeneous outcrop limestone rock.
Figure 1. Schematics of the experimental setup for waterfloods. Top: 3D MRI with a spatial resolution of approximately 1 mm3. Bottom: 2D NTI with an areal resolution of approximately 1 cm2. Table 1. Fluid Properties fluid
Experimental Section Two imaging techniques were used to study the flow in fractured rocks. The size of the rock samples, the operation, and the spatial resolution vary greatly for the two techniques, and are described individually below. Figure 1 illustrates the experimental setup used for each imaging technique with nominal spatial resolution. NTI. NTI utilizes the emitted γ energy from a nuclear tracer (22Naþ) added to the water phase to measure local, in situ water saturations. A moveable germanium detector scans the block in two dimensions, providing two-dimensional (2D) in situ fluid saturations with a resolution of approximately 1 cm2. MRI. MRI relies on the spin properties of hydrogen nuclei in the presence of a strong magnetic field. Quantitative threedimensional (3D) imaging with a resolution of about 1 mm3 was
density [g/cm3]
viscosity [cP] at 20 °C (80 °C)
brine
1.05
1.09
D2O brine
1.16
1.09
n-decane North Sea crude oil
0.73 0.85
composition 5.0 wt % NaCl 3.8 wt % CaCl2 0.1 wt % NaN3 5.0 wt % NaCl 3.8 wt % CaCl2
0.92 14.3 (2.7)
obtained by applying gradients to the magnetic field to determine the number of protons present within a restricted volume at a given position. Deuterium oxide (D2O) was used as the aqueous phase because oil and regular brine may be difficult to distinguish in the MRI because of similar hydrogen densities. More details on both MRI and NTI can be found in ref 31. Fluids. The properties of the fluids are listed in Table 1. Core Material. Two chalk and two limestone blocks of outcrop rock were used in this work. The dimensions of the rock samples were larger than those normally used in special core analysis tests. The rock properties, waterflood injection rates and capillary numbers are listed in Table 2. Chalk. The chalk blocks were obtained from the Portland Cement Factory in Aalborg, Denmark. The rock formation was of Maastrichtian age and consisted mainly of coccolith deposits, and the composition was mainly calcite (99%) with some quartz (1%). This rock is considered homogeneous with respect to the pore-size distribution. The brine permeability and porosity ranged from 1 to 4 mD and from 45 to 48%. More details about the rock may be found in refs 32 and 33. Limestone. The Edwards limestone was from northeastern parts of New Mexico. Trimodial pore sizes, vugs, and microporosities have been identified using thin section images, mercury injection, and NMR T2 relaxation experiments. The brine
(21) Horie, T.; Firoozabadi, A.; Ishimoto, K. SPE Reservoir Eng. 1990, 5 (3), 353–360. (22) Labastie, A. SPE ATCE, New Orleans, LA, Sept 23-28, 1990. (23) Stones, E. J.; Zimmerman, S. A.; Chien, C. V.; Marsden, S. S. SPE ATCE, Washington, DC, Oct 4-7, 1992; pp 643-657. (24) Firoozabadi, A.; Markeset, T. SPE Reservoir Eng. 1994, 9 (3), 201–207. (25) Graue, A.; Aspenes, E.; Moe, R. W.; Baldwin, B. A.; Moradi, A.; Stevens, J.; Tobola, D. SPE ATCE, New Orleans, LA, Sept 30-Oct 3, 2001. (26) Aspenes, E.; Graue, A.; Baldwin, B. A.; Moradi, A.; Stevens, J.; Tobola, D. P. SPE ATCE, San Antonio, TX, Sept 29-Oct 3, 2002. (27) Aspenes, E.; Ersland, G.; Graue, A.; Stevens, J.; Baldwin, B. A. Transport in Porous Media, 2007, online first. (28) Graue, A.; Baldwin, B. A.; Aspenes, E.; Stevens, J.; Tobola, D. P.; Zornes, D. R. International Symposium of the Society of Core Analysts, Pau, France, 2000. (29) Graue, A.; Moe, R. W.; Baldwin, B. A. SPE International Petroleum Conference and Exhibition in Mexico, Villahermosa, Mexico, Feb 1-3, 2000. (30) Graue, A.; Bognø, T.; Baldwin, B. A.; Spinler, E. A. SPE Reservoir Eval. Eng. 2001, 4 (6), 455–466.
(31) Ersland, G.; Fernø, M. A.; Graue, A.; Baldwin, B. A.; Stevens, J. Chem. Eng. J. 2008. (32) Ekdale, A. A.; Bromley, R. G. Bull. Geol. Soc. Denmark 1993, 31, 107–119. (33) Hjuler, M. L. Technical University of Denmark: Copenhagen, Denmark, 2007.
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represent an actual snapshot of the saturation distribution because there is a certain scanning time required for each image. To avoid significant saturation changes during the acquisition of each image, the water injection rates were kept low. This corresponds to low capillary numbers (10-9-10-10), translating to a capillary-dominated flow regime, as seen in Table 2.
Table 2. Rock Properties, Water Injection Rates, and Capillary Numbers CHP1 rock type
CHP2
Portland chalk length [cm] 16.0 width [cm] 5.1 height [cm] 10.0 3 pore volume [cm ] 383 porosity 0.47 permeability [mD] 4.9 Amott-Harvey 0.18a index imaging technique NTI WF injection rate 2.0 [mL/h] capillary number 2.3 10-9
EDW1
EDW2
Portland chalk 13.2 2.4 8.4 127 0.48 3.2 1
Edwards limestone 14.9 4.9 8.5 150 0.24 16.7 1
Edwards limestone 15.9 2.5 8.0 75 0.24 23.4 -0.2b
MRI 2.0
NTI 0.5
MRI 2.0
Results Oil recovery as a function of the pore volume injected for all waterfloods is shown in Figure 3. Residual oil saturation, PVs injected at water breakthrough and final recoveries are listed in Table 3. SWW Conditions. The waterflood oil recovery (OIP) for the SWW block EDW1 without fractures (RF = 40% OIP) was similar to that of the fractured case (RF = 44% OIP), with a clean water breakthrough and no transient production. The slight difference in oil recovery may be attributed to lower IWS and increased pore volume in the fractured case. The in situ fluid saturation development with fractures was monitored by NTI and is shown in Figure 4. The water displaced oil from the isolated matrix blocks sequentially: first the inlet matrix block was fully imbibed by water, and then the outlet matrix block imbibed water. Water did not exit the inlet block until the end point for spontaneous imbibition was reached at the outlet end. This is further discussed below. The isolated matrix block in the center was not displaced during the waterflood. The OIP for the SWW block CHP2 without fractures (RF = 46% OIP) was similar to that of the fractured case (RF = 42% OIP), with a clean water breakthrough and no transient production. The fractures was in direct contact with the outlet production end face, whereas the inlet end face was not connected to the fracture network, see Figure 2. Figure 5 shows the in situ fluid saturation development imaged by MRI at selected times during the waterflood of the fractured block. The 3D data are projected to 2D for better illustration. The visualization shows that the water contacted each matrix separately and displaced oil cocurrently from one isolated block at a time. WWW Conditions. Chalk block CHP1 was aged to WWW conditions, with an average Amott-Harvey index of IA-H = 0.18, see Table 2. The recovery without fractures was RF = 63% OIP, with water breakthrough observed at 0.47PV injected, followed by transient production until 1.5PV had been injected. Both the inlet and outlet end faces had direct contact with the fracture network (see Figure 2). The recovery when fractured was RF = 22% OIP, with water breakthrough observed at 0.1PV injected. Transient production was observed until approximately 1.4PV injected. Figure 6 shows the NTI in situ fluid saturation development during the waterflood with fractures. Water advanced through the fracture system relatively fast, and water imbibed uniformly and countercurrently from all of the fracture surfaces into the matrix at the same time. The large open fracture close to the outlet is clearly visible from the saturation scans. Weakly oil-wet (WOW) Conditions. Limestone block EDW2 was aged to WOW conditions with an Amott index of approximately IA-H = -0.2. The recovery for the whole block was RF = 65% OIP, with water breakthrough observed after 0.47PV injected. Transient production was observed until approximately 1.5PV injected, producing an additional 5% OIP after breakthrough. The outline of the fracture network was similar to that of CHP2 (see Figure 2).
5.9 10-9 7.0 10-10 5.9 10-9
a Average value based on three core plugs drilled from CHP1. The Amott-Harvey index for each core plug was 0.08, 0.10, and 0.36. Spontaneous imbibition of oil was not observed. bBased on the measured wettability on a twin sample. Spontaneous imbibition of water was not observed.
permeability and porosity ranged from 3 to 28 mD and from 16 to 24%. Experimental Procedure. The blocks were dried at 80°C for several days, coated with epoxy resin, and equipped with end pieces for fluid injection and production. Aluminum end pieces were used for the NTI experiments, whereas nonmagnetic Teflon end pieces were used in the MRI experiments. The blocks were then saturated with brine under vacuum, and the porosity was determined by weight measurements. Absolute permeability to brine was calculated by Darcy’s law, using constant injection rates and measuring the differential pressure across the block. At least 5PV of brine was injected prior to any permeability measurement to ensure that the brine was in equilibrium with the rock mineral surface. The regular brine was miscibly replaced with D2O brine for blocks imaged by MRI and with brine containing radioactive Na22Cl for blocks using the NTI method. Fluid properties are listed in Table 1. Two blocks (CHP1 and EDW2) were aged in crude oil by the technique described in ref 34. The obtained wettability alteration has been shown to be stable by Fernø et al.;35 this is important in order to isolate the effect from fractures at given wettabilities. All blocks were oilflooded to irreducible water saturation (IWS) at constant differential pressure (200 kPa/cm) using decane. Baseline waterfloods were performed without fractures at constant injection rates (see Table 2). The blocks were oilflooded back to IWS, cut by band saw to the desired fracture network, reassembled, and coated with a new layer of epoxy. Imaging was used to verify that no significant fluid redistribution occurred during cutting and reassembly. The established fracture network for each sample is shown in Figure 2. A second waterflood with the same water injection rate, with the fracture network present, was then performed. The capillary number (NC), which is the ratio between the viscous and capillary forces, was calculated for each waterflood by36 NC ¼
vμ σ
ð1Þ
where v is Darcy’s velocity, μ is the viscosity of the injected fluid, and σ is interfacial tension. All waterfloods were imaged by either MRI or NTI, see Table 2. Saturation images do not (34) Graue, A.; Viksund, B. G.; Eilertsen, T.; Moe, R. J. Pet. Sci. Eng. 1999, 24 (2-4), 85–97. (35) Fernø, M. A.; Ersland, G.; Haugen, A˚.; Johannesen, E.; Graue, A.; Stevens, J.; Howard, J. J. International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, June 27-30, 2007. (36) Saffman, P. G.; Taylor, G. Proc. R. Soc. London 1958, 245 (1242), 312–329.
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Figure 2. Schematics of the four blocks in the x and z directions. Red lines indicate the position and outline of the fracture networks. The arrow above indicates the direction of flow during waterfloods.
Figure 3. Oil recovery in a fraction of [OIP], water saturation increase, and development in an average water saturation as a function of the pore volume injected for all waterflooded blocks at whole and fractured states.
The recovery at the fractured state was RF = 15% OIP, with water breakthrough at 0.1PV injected, followed by transient production until 0.33PV injected. Figure 7 shows the in situ
fluid saturation development during the waterflood of the fractured block monitored by MRI. Displacement of oil was only observed in the unfractured inlet block until water entered 3023
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Table 3. Waterflood Data for All Rock Samples IWS
ROS
OIP [%]
PV injected at water breakthrough
block name
whole
fractured
whole
fractured
whole
fractured
whole
fractured
CHP1 CHP2 EDW1 EDW2
0.24 0.30 0.11 0.28
0.24 0.30 0.09 0.31
0.27 0.38 0.52 0.24
0.59 0.38 0.51 0.59
63 45 40 65
22 42 44 15a
0.47 0.37 0.36 0.47
0.10 0.32 0.40 0.13
a
Recovery can be attributed to an unfractured inlet piece.
Figure 4. In situ fluid saturation development by NTI during the waterflood of EDW1 with fractures. Oil was displaced sequentially matrix block by matrix block in a cocurrent manner.
the fracture network. Water rapidly filled the fractures, first the lower horizontal fracture and then the remaining fracture network, before it reached the outlet. No capillary imbibition of water from the fractures was observed.
from viscous displacement, even at low capillary numbers (NC = 2.3 10-9-5.9 10-9). Consequently, higher oil recoveries and longer transient production after water breakthrough during waterflood were observed for the WWW and WOW cases. The highest oil recovery was measured at an Amott wettability index of -0.2. Wettability and Fractures. After waterfloods at the whole state, the blocks were oilflooded back to IWS, cut into smaller pieces with a band saw, and reassembled according to Figure 2. The fractured systems were then waterflooded to study the effect of wettability and the presence of fractures on the recovery, flow dynamics, and displacement processes. For the SWW samples, the presence of fractures showed only a minor impact on the average oil recovery (OIP), changing the recovery by less than 4% OIP. This was in accordance with the high capillary pressure at SWW conditions and that the water injection was performed in a capillary-dominated flow regime. As the wettability changed to WWW, the recovery (OIP) was dramatically reduced from 63% at the whole state to 22% with the presence of fractures. For the WOW conditions, the recovery (OIP) was reduced from 65% to 15%, illustrating the increased influence of fractures on the recovery by water injection at wettabilities other than SWW. In combination with volumetric production data, the in situ fluid saturation data provided information
Discussion Wettability. A relationship between the waterflood residual oil saturation (ROS) and the wettability of the porous medium is well-known,5-9 but one single correlation has not been established. It appears that there exists no universal trend, and each crude oil/rock/brine system shows unique correlations. In this work, the ROSs during waterfloods of whole blocks were lower for WWW (chalk: ROS=0.27) and WOW (limestone: ROS = 0.24) than those at SWW conditions (chalk, ROS = 0.38; limestone, ROS = 0.52). The difference in the ROSs at SWW conditions was believed to be related to differences in the pore geometries between chalk and limestone. The absence of transient production and low capillary number (NC = 5.9 10-9-7.0 10-10) at SWW conditions indicated capillary-dominated recovery, where significant oil was trapped by capillary forces. WWW and WOW conditions were less dominated by the capillary forces. This resulted in larger mobile pore volumes and stronger contributions 3024
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Figure 5. In situ fluid saturation development by MRI during waterflood of the SWW block CHP2 at a fractured state, block-by-block displacement where water displaced oil in a cocurrent manner.
Figure 6. In situ fluid saturation development obtained by NTI during the waterflood of the WWW CHP1 when fractured. Fractures fill rapidly, followed by countercurrent imbibition of brine from fractures into the matrixes.
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Figure 7. In situ fluid saturation development obtained by MRI during the waterflood of the WOW fractured block, EDW2. The fractures appear in the images as water displaces the oil in the fractures.
about the flow pattern with the presence of fractures to better understand the recovery mechanisms. At SWW conditions, the fractures were capillary barriers for the injected water. Water displaced oil sequentially in a block by block manner, as seen for EDW1 and CHP2 in Figures 4 and 5, respectively. This behavior was attributed to the capillary-dominated flow regime (NC < 10-6), combined with the discontinuity in the capillary pressure at the fracture/ matrix interface. The fractures have a low capillary pressure, whereas the oil-saturated matrix has a high positive capillary pressure. Water will only exit downstream from a matrix block when the capillary pressure in the fracture and matrix are equal. At SWW conditions, the matrix capillary pressure becomes zero at ROS, and water will therefore only enter adjacent fractures when the matrix saturation is close to ROS at the end point for spontaneous brine imbibition. Once water enters the fracture, it may imbibe into the adjacent downstream matrix block. Consequently, the fluid flow was strongly influenced by the presence of fractures at SWW conditions, but ROS and recovery were less influenced. The displacement pattern was in most cases determined by the location of the water in the fractures, and the lower blocks closer to the inlet imbibe water first due to gravity segregation. This is clearly demonstrated by in situ fluid saturation data of block CHP2 in Figure 5. The combination of high capillary imbibition and the low water injection rate led to the filling regime19 and cocurrent imbibition. The in situ data confirm this. Cocurrent imbibition of water is faster because of less resistance of oil produced as a result of a higher relative permeability to oil downstream. Recovery mechanisms changed as the water wetness decreased toward WWW in the fractured CHP1 block. The injected water rapidly filled the entire fracture network and imbibed from fracture into the matrix. Early water breakthrough (0.1PV) was a result of a higher water injection rate than the
rate of water uptake from the fracture to the matrix, and water breakthrough was determined by the fracture volume. After breakthrough, a long period of two-phase production followed. Oil was recovered by countercurrent capillary imbibition of water from the fractures to the matrixes only as negligible differential pressure was established; see Figure 6. The combination of high permeability fractures and low capillary number conditions reduced the displacement of oil by viscous forces. The reduction in the matrix/fracture transfer rate at WWW conditions increases the likelihood of an instantly filled fracture regime,19 with countercurrent imbibition of water. This was supported by observations from the in situ data for the WWW block CHP1. The shape of the fracture network led to rapidly (almost instantly) water-filled fractures and countercurrent imbibition. The countercurrent imbibition oil recovery was linear with the square root of time. At WOW conditions in fractured block EDW2, the viscous and gravity forces governed the oil recovery in the absence of positive capillary forces and spontaneous imbibition of water. Gravity forces were negligible compared to viscous forces and will not be discussed. The shape of the fracture network promoted both viscous and capillary oil displacement. The viscous displacement took place in the inlet part of the block (see Figure 2), while production in other parts of the fractured rock relied upon capillary imbibition. Figure 7 shows that water only displaced oil from the unfractured inlet matrix part, and when the injected water reached the fracture network, only oil in the fractures was recovered. The lack of capillary forces to drive the water from the fracture network to the matrix blocks demonstrated the impact from wettability on spontaneous imbibition in fractured reservoirs. The viscous contribution was negligible with the presence of high permeability fractures combined with low flow rates and low capillary numbers. With an interconnected fracture network as in CHP1, only oil from the fractures would have 3026
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been recovered during water injection, and oil recovery would have been even lower. There was no transport of fluids from the fractures to the matrix in the WOW case. Capillary Continuity across Fractures. The general assumption in fractured systems is that fractures have zero capillary pressure, and the relative permeability curves are linear functions of saturation. These assumptions are often used as input in reservoir simulations of dual-porosity systems. Several authors including Firoozabadi and Hauge,37 de la Porte et al.,38 and Rangel-German et al.39 studied the capillary pressure in fractures. The observed displacement pattern in the SWW block EDW1 suggested the presence of continuity across the upper part of the fracture system (Figure 4). This capillary continuity influenced the local recovery because no detectable saturation change in the isolated matrix block was observed (see Figure 4). The expected displacement pattern was a fully imbibed matrix block behind the advancing water front.40 Contrasts in the capillary contact between the different matrix blocks will impact the fluid flow. A stronger capillary contact between the inlet and outlet matrix blocks than between the inlet and isolated block contributed to the unexpected local recovery. The difference in capillary contact because of stronger physical contact at some matrix-fracture interfaces limited water imbibition into the isolated block during waterflood. A high relative permeability to water in the waterflooded zones and a low relative permeability for oil after the capillary continuity was established inhibited recovery from the isolated block. A conventional numerical simulator used to investigate the impact from the capillary contact in the SWW limestone41 supported this argument.
2
3
4
5
6
than at SWW conditions. This was attributed to a higher mobile pore volume and increased contribution from viscous forces because of the reduced capillarity at wettabilities other than SWW. At SWW conditions, the oil recovery was capillarydominated in both whole and fractured blocks, with similar recoveries in both cases. At WWW conditions, the oil recovery was governed by both viscous and capillary forces. In fractured blocks, the viscous displacement was significantly reduced. The oil recovery in the matrixes was determined by the potential for spontaneous brine imbibition because of insignificant differential pressures across the matrix blocks, in the presence of highly permeable fractures. At WOW conditions, the oil recovery was determined by viscous forces only because of the lack of spontaneous brine imbibition. In the fractured blocks, no water transport from the fractures to matrix blocks was observed during waterfloods. Oil recovery was significantly reduced compared to that of waterfloods without fractures. The filling fracture regime was observed at SWW conditions because of rapid water uptake from the fracture. The instantly fracture filling regime was observed at WWW conditions because of decreased imbibition rates. Capillary continuity was interpreted at physical contact points at SWW conditions for the embedded fracture network, and it was confirmed to influence the sweep efficiency and ultimate oil recovery.
Acknowledgment. Two of the authors thank the Norwegian Research Council for financial support. Thanks go to ConocoPhillips Bartlesville Technology Center for the use of laboratory facilities and permission to publish. Special thanks go to James J. Howard, Jim Stevens, David Zornes, and Jim Johnson at ConocoPhillips Bartlesville Technology Center.
Conclusions Waterfloods at different wettabilities, ranging from SWW (IA-H = 1.0) to WOW (IA-H = -0.2), were performed on whole and fractured, larger sized blocks of carbonate rocks. The development of in situ fluid saturations was obtained by NTI and MRI during waterfloods and contributed to an improved understanding of the recovery mechanisms during fluid flow in fractured blocks at different wettabilities. The NTI and MRI were equally good at capturing the development of in situ matrix water and oil saturations during waterfloods. The MRI method provides 3D spatial fluid saturation and increased resolution to capture the water advancement inside the fracture. 1 Without fractures, in these fairly homogeneous rocks, the oil recovery was higher at WWW and WOW conditions
Appendix Nomenclature Iw = Amott water index IA-H = Amott-Harvey index IWS = irreducible water saturation MRI = magnetic resonance imaging NTI = nuclear tracer imaging OIP = oil in place PV = pore volume ROS = residual oil saturation SWW = strongly water-wet WOW = weakly oil-wet WWW = weakly water-wet NC = capillary number μ = viscosity of the injected fluid σ = interfacial tension v = Darcy’s velocity
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