Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

Transcription

1 Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs A. Graue, SPE, and T. Bognø, SPE, U. of Bergen; B.A. Baldwin, SPE, Green Country Petrophysics; and E.A. Spinler, SPE, Phillips Petroleum Co. Summary Iterative comparison between experimental work and numerical simulations has been used to predict oil-recovery mechanisms in fractured chalk as a function of wettability. Selective and reproducible alteration of wettability by aging in crude oil at an elevated temperature produced chalk blocks that were strongly water-wet and moderately water-wet, but with identical mineralogy and pore geometry. Large scale, nuclear-tracer, 2D-imaging experiments monitored the waterflooding of these blocks of chalk, first whole, then fractured. This data provided in-situ fluid saturations for validating numerical simulations and evaluating capillary pressureand relative permeability-input data used in the simulations. Capillary pressure and relative permeabilities at each wettability condition were measured experimentally and used as input for the simulations. Optimization of either P c-data or k r-curves gave indications of the validity of these input data. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations than matching production profiles only. Introduction Laboratory waterflood experiments, with larger blocks of fractured chalk where the advancing waterfront has been imaged by a nuclear tracer technique, showed that changing the wettability conditions from strongly water-wet to moderately water-wet had minor impact on the the oil-production profiles. 3 The in-situ saturation development, however, was significantly different, indicating differences in oil-recovery mechanisms. The main objective for the current experiments was to determine the oil-recovery mechanisms at different wettability conditions. We have reported earlier on a technique that reproducibly alters wettability in outcrop chalk by aging the rock material in stock-tank crude oil at an elevated temperature for a selected period of time. After applying this aging technique to several blocks of chalk, we imaged waterfloods on blocks of outcrop chalk at different wettability conditions, first as a whole block, then when the blocks were fractured and reassembled. Earlier work reported experiments using an embedded fracture network,,, while this work also studied an interconnected fracture network. A secondary objective of these experiments was to validate a full-field numerical simulator for prediction of the oil production and the in-situ saturation dynamics for the waterfloods. In this process, the validity of the experimentally measured capillary pressure and relative permeability data, used as input for the simulator, has been tested at strongly water-wet and moderately water-wet conditions. Optimization of either P c data or k r curves for the chalk matrix in the numerical simulations of the whole blocks at different wettabilities gave indications of the data s validity. History matching both the production profile and the in-situ saturation distribution development gave higher confidence in the simulations of the fractured blocks, in which only the fracture representation was a variable. Copyright 2 Society of Petroleum Engineers This paper (SPE 33) was revised for publication from paper SPE 2, first presented at the SPE Annual Technical Conference and Exhibition, Houston, 3- October. Original manuscript received for review 3 December. Revised manuscript received 2 May 2. Paper peer approved 2 August 2. Experimental Rock Material and Preparation. Two chalk blocks, CHP and CHP, approximately 2 2 cm thick, were obtained from large pieces of Rørdal outcrop chalk from the Portland quarry near Ålborg, Denmark. The blocks were cut to size with a band saw and used without cleaning. Local air permeability was measured at each intersection of a -cm grid on both sides of the blocks with a minipermeameter. The measurements indicated homogeneous blocks on a centimeter scale. This chalk material had never been contacted by oil and was strongly water-wet. The blocks were dried in a C oven for 3 days. End pieces were mounted on each block, and the whole assembly was epoxy coated. Each end piece contained three fittings so that entering and exiting fluids were evenly distributed with respect to height. The blocks were vacuum evacuated and saturated with brine containing wt% NaCl 3. wt% CaCl 2. Fluid data are found in Table. Porosity was determined from weight measurements, and the permeability was measured across the epoxy-coated blocks, at 2 3 µm 2 and 3 µm 2, for CHP and CHP, respectively (see block data in Table 2). Immobile water saturations of 2 to 3% pore volume (PV) were established for both blocks by oilflooding. To obtain uniform initial water saturation, i, oil was injected alternately at both ends. Oilfloods of the epoxy-coated block, CHP, were carried out with stock-tank crude oil in a heated pressure vessel at C with a maximum differential pressure of 3 kpa/cm. CHP was oilflooded with decane at room temperature. Wettability Alteration. Selective and reproducible alteration of wettability, by aging in crude oil at elevated temperatures, produced a moderately water-wet chalk block, CHP, with similar mineralogy and pore geometry to the untreated strongly water-wet chalk block CHP. Block CHP was aged in crude oil at C for 3 days at an immobile water saturation of 2% PV. A North Sea crude oil, filtered at C through a chalk core, was used to oilflood the block and to determine the aging process. Two twin samples drilled from the same chunk of chalk as the cut block were treated similar to the block. An Amott-Harvey test was performed on these samples to indicate the wettability conditions after aging. After the waterfloods were terminated, four core plugs were drilled out of each block, and wettability measurements were conducted with the Amott-Harvey test. Because of possible wax problems with the North Sea crude oil used for aging, decane was used as the oil phase during the waterfloods, which were performed at room temperature. After the aging was completed for CHP, the crude oil was flushed out with decahydronaphthalene (decalin), which again was flushed out with n-decane, all at C. Decalin was used as a buffer between the decane and the crude oil to avoid asphalthene precipitation, which may occur when decane contacts the crude oil. Creating the Fractures. The fractures were created after the first waterflood, when the whole block had been driven back to i, by cutting the block with a band saw. The fracture orientation and location and a diagram of the arrangement of the individual pieces of the designed fracture network, after the individual cut blocks were reassembled, are shown in Fig.. The x-y coordinates are used for location. For reference, the individual blocks are identified as Blocks A and A2, the inlet blocks; Block B, the central block, which was surrounded by fractures; and Blocks C and C2, December 2 SPE Reservoir Evaluation & Engineering

2 TABLE FLUID PROPERTIES Density Viscosity Viscosity Fluid (g/cm 3 ) (cp) at 2 o C (cp) at o C Composition Brine.. wt% NaCl + 3. wt% CaCl 2 n-decane 3 2 Decahydronaphtalene Crude oil.3 2. the outlet blocks. Both an open fracture, with no possible capillary contact, and several closed fractures, with contact between the adjacent matrix blocks, were formed. The closed fractures were intended to provide at least some capillary continuity of both fluid phases across the fracture. The open vertical fracture at 3 cm was created by sliding Block B to the left as far as possible, producing an open fracture with the width of one saw cut, approximately 2 mm. The other fractures were closed (i.e., the pieces were placed butt to butt when reassembling the block, and an axial force was applied during the reassembly). When reassembling the blocks, TABLE 2 EXPERIMENTAL DATA FOR CHALK BLOCKS Block CHP CHP Outcrop Portland Portland Location Ålborg Ålborg Length (cm).. Height (cm) Thickness (cm). Abs. Permeability (md) Porosity (%).. Pore volume (ml) Misc. Flood Number: Flow rate (ml/hr) Oilflood Number: 2 3 Oil viscosity (cp) i (%PV) 2 (%PV) f (%PV) Maximum pressure (bar) Endpoint efficient permeability (md) 3 c.3 a /.3 b. a /2 b 3.3 a / b Aging: YES NO Aging temperature (ºC) Aging time (days) 3 Amott index after aging (measured on samples) Oil flooding before imbibition: Decaline (PV) n-decane (PV) Endpoint efficient permeability (md) 2. Waterflood Number: Block Condition Whole Fractured Fractured Fractured Fractured Cutting XX Band Saw Band Saw Band Saw Band Saw Oil viscosity (cp) i (%PV) (%PV) 3 f (%PV) 3 2 Maximum pressure (bar) XX XX XX XX XX Endpoint efficient permeability (md) b 2 Oil recovery (%OIP) Flow rate (ml/hr) 2 a) Whole block b) Fractured block c) Endpoint relative permeability tends to be higher than absolute permeability. December 2 SPE Reservoir Evaluation & Engineering

3 INLET Block 3 2 A2 A B OPEN FRACTURE C2 C OUTLET Block Fig. Interconnected fractured network with hydraulic contact from inlet to outlet. tape was placed over the fractures to prevent the epoxy, which is used to reseal the core, from entering the fractures. A 2-mm strip of Teflon was placed at the outer lower edge of the open fracture to ensure a well-defined open volume. A pressure of kpa was applied across the fractures to mechanically hold the different parts of the block in position while the epoxy cured. After reassembly, the fracture network was filled with decane with a syringe. For all the fractured blocks, the first vertical fracture was at cm from the inlet end, the second vertical fracture was at 3 cm from the inlet end, and a horizontal fracture was created at the center line of the block, connecting the vertical fractures. This fracture network is denoted as the embedded fracture network. For the interconnected fracture network, two horizontal fractures were added at the inlet and outlet ends to provide continuous hydraulic contact from inlet to outlet (i.e., from injector to producer ; see Fig. ). The blocks were positioned vertically for both the oilfloods and the subseqent waterfloods; thus, the gravity was aligned with the vertical fractures. Saturation Determination. Two-dimensional brine saturations were determined with a flow rig, which was designed and built at the U. of Bergen, to measure gamma ray emission from 22 Na dissolved in the brine. Although CaCl 2 was in the brine to buffer Na adsorption, several pore volumes of nonradioactive brine were initially flushed through the block to minimize potential adsorption of the radioactive tracer, 22 NaCl, before the rock was exposed to the radioactive brine. The rig held the block in a vertical position and measured the radiation in the x-y plane over the block to produce a saturation map at each specified point in time. Radiation detection (i.e., saturation measurement) during the waterflood was made at the intersections in the grid shown in Fig., a -cm grid. The working principle of this nuclear tracer technique has been described in detail., Originally, the detector was collimated to produce an analysis area of cm at the surface of the block, which expanded to.. cm at the back of the block, giving an analysis volume of. cm 3. However, to avoid bypass, the blocks were placed in a pressure vessel, and a confinement pressure was applied., The thickness of the walls increased the distance to the detector, and the analysis volume increased to cm 3. The radiation counting time at each position was 2 min., giving a total sampling time, for one -cm saturation scan, of hours. The change in saturation during this time, less than 2 PV, is small compared to the volume needed to produce a noticeable change in the saturation map. Thus, no correction was made to account for the saturation change during the scanning time. When the blocks were fully saturated with radioactive brine, the counts of radioactivity at each gridpoint were normalized to % water saturation. The normalization coefficients at each gridpoint were then used to convert the radiation measurements into saturation distributions in all later images. To prevent countercurrent imbibition from producing oil into the water inlet, a low differential pressure, initially. kpa, was applied across the block during the constant-flow-rate waterfloods. The injection flow rates are included in Table 2. The outline and the results of the experimental sequence used to waterflood the unfractured and fractured blocks while using 2D imaging to determine the distribution of brine saturation are summarized in Table 2. Results and Discussion Block CHP was waterflooded at strongly water-wet conditions with an interconnected fracture network as shown in Fig.. Block CHP was, after subsequent oilfloods, waterflooded three times, first as a whole block, then with the embedded fracture network, and finally with the interconnected fracture network. Wettability Tests. To obtain a measure of the wettability conditions of CHP, the block was aged to reflect moderately water-wet conditions, and the duplicate set of core plugs, PC2-3 and PC2-, were tested for wettability. The plugs were treated similarly to the block and then cooled to room temperature after the crude oil was exchanged with decalin and decane. Oil recovery by spontaneous room temperature imbibition, followed by a waterflood, were performed on the aged core plugs, producing the Amott water index, I w. Core-plug history and results are found in Table 3 in Ref.. Fig. 2 shows the imbibition characteristics for the core plugs; for comparison, imbibition characteristics for some Rørdal chalk core plugs at strongly water-wet and nearly neutral-wet conditions are included. Imbibition rate and endpoint saturation after spontaneous imbibition decreased with increased aging time, corresponding to a consistent change toward a less water-wet state. Repeated imbibition tests on the core plugs after aging confirmed stable wettability conditions. The measured wettability index to water, I w, for the two plugs was recorded at 2 and, respectively. The Amott-Harvey test was conducted three times on these samples to verify stability and reproducibility in the measurements. The second wettability test was performed with iododecane as the oil phase, needed in a subsequent steadystate relative permeability test using a Penn State technique with X-ray attenuation imaging, to generate input for numerical simulations. The third wettability test was performed after the samples had been transported back and forth among Bergen, Norway, and Houston, where the relative permeability tests were performed by a service company. The term moderately water-wet in this paper means to cover the wettability conditions, reflecting an Amott- Harvey water index, I w, in the range of to. December 2 SPE Reservoir Evaluation & Engineering

4 TABLE 3 EXPERIMENTAL HISTORY FOR DRILLED-OUT PLUGS Core CHP- CHP-2 CHP- Drilled from block number CHP CHP CHP Outcrop Portland Portland Portland Location Denmark Denmark Denmark Length (cm) Diameter (cm) Porosity (%) Pore volume (ml) Abs. permeability (md) Oilflood Number: Oil viscosity (cp) i (%PV) (%PV) 3 3 f (%PV) Spontaneous Imbibition Number: Oil viscosity (cp) i (%PV) (%PV) f (%PV) Oil recovery (%OIP) Waterflood Number: Flow rate (ml/hr) i (%PV) (%PV) f (%PV) Recovery (%OIP) Endpoint efficient permeability (md) Wettability index 2 Waterfloods of Whole Blocks. Results from waterfloods of whole blocks, both at strongly water-wet and moderately water-wet conditions, have previously been shown to be similar with respect to in-situ saturations. The dynamics of the in-situ saturation for a typical waterflood of a whole block, CHP, is shown in Fig. 3. The individual saturation maps are identified by a scan number. Each scan number was preceded by a letter and number to identify each. I w =,2 ; PC2-3 I w =, ; PC2- I w =,32 ; PC2- I w =,3 ; PC2-2 I w =, ; CPA-. I w =, ; CPA-.., Fig. 2 Imbibition characteristics for the duplicate set of core plugs, PC2-3 and PC2-, used to indicate wettability conditions for CHP and for steady-state relative permeability measurements. For comparison, typical imbibition characteristics for strongly water-wet and nearly neutral-wet plugs are included. CPA-. and CPA-. are strongly water-wet samples used for reference only. block (e.g., P and P for CHP and CHP, respectively). The codes for the scans are as follows: the oil and water floods were labeled O and W, respectively, with the first digit being the flood number and the two digits following the dash indicating the chronological sequence of the scan. Thus, PW2- is the ninth scan of the second waterflood on Block CHP. In all the waterflood experiments, the brine was injected from the left side of the image, and the displaced fluids exited at the right side of the image. A uniform initial water saturation was measured for CHP as the first saturation map, PW- in Fig. 3. Scans PW- to PW-2 show a slightly higher brine saturation at the bottom of the block near the inlet, suggesting a gravitational effect in the vertical brine distribution across the block. This could be caused by the slightly higher pressure at the lower part of the block caused by the higher water head in the injection end piece; however, these were very small pressure differences, approximately. kpa. A dispersed waterfront flushed out % PV of the decane. Increasing the flow rate has been shown to produce a less dispersed waterfront. In waterfloods starting at higher initial water saturations, there essentially was no waterfront at all; a uniform increase in water saturation was recorded. A uniformly distributed final water saturation was obtained for all the tests. When the blocks were driven back to i with decane, an excellent reproduction of the original water saturation and saturation distribution was generally obtained (see Table 2). Average saturations from the in-situ nuclear tracer and mass-balance measurements were compared and showed good agreement. The blocks were then cut with a band saw into the five shapes shown in Fig.. The nuclear tracer saturation measurements of the whole and the assembled fractured block, at i, indicated that the cutting December 2 SPE Reservoir Evaluation & Engineering

5 ... 3 PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW-2 : Brine Fig. 3 Saturation development for the first waterflood of the whole block CHP. December 2 SPE Reservoir Evaluation & Engineering

6 ... PV injected PW-... PV injected PW-... PV injected PW-... PV injected PW-... PV injected PW-... PV injected PW PV injected PW-2 : Brine Saturation Fig. Saturation development for the first waterflood of fractured block CHP with interconnected fracture network. December 2 SPE Reservoir Evaluation & Engineering

7 ... 3 PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW PV injected PW3- : Brine Saturation Fig. Saturation development for the third waterflood of fractured block CHP with interconnected fracture network. December 2 SPE Reservoir Evaluation & Engineering

8 process did not measurably alter the saturation distribution, as was also observed in previous experiments.,, Waterfloods of Fractured Blocks. Fig. shows the time development of the in-situ water saturation while waterflooding CHP with an interconnected fracture network. The brine saturation increased as a dispersed front through Block A, the continuous inlet block, Scans PW- through PW-2. In Scan PW-, Block B was still at, or close to, i while the matrix just across the fracture in Block A was approaching f. This suggested a limited rate of transport of fluids across the closed vertical fracture at cm and the horizontal fracture at cm. In fact, the brine did not appear to cross any of the fractures before the saturation in all of Block A was close to its final water saturation. After Block A reached a high saturation and the fractures were filled with brine, the brine entered Block B, Scan PW-. The general appearance of Block B in Scan PW- suggested that the brine entered gradually from both the horizontal and vertical fractures between Block A and Block B. However, little, if any, water had gone across the 3-cm fracture into Block C when Scan PW- was taken. When Block B approached its final water saturation, water movement into Block C, the outlet block, was recorded (Scan PW-). Higher water saturation in the lowest part of Block C at the outlet end, shown in Scan PW-, indicated a gravity segregation of the fluids in the open fracture. This behavior also has been observed previously.,, The fractured block CHP was waterflooded twice, first with an embedded fracture network, and then with interconnected fractures (Table 2, Waterflood No. 2, and Waterflood No. 3, respectively). The time development of the advancing water was very similar for the two fracture networks. Fig. shows the scans for the time development of the 2D brine saturation during the waterflood of the moderately water-wet fractured block CHP with the interconnected fracture network. The brine saturation increased as a dispersed front through Block A, the continuous inlet block, and Block B (Scans PW3- through PW3-). No visible influence from the fractures was observed. This suggested a significant transport of fluids across the closed vertical fracture at cm and the horizontal fracture on the centerline of the block. This indicated () capillary contact across the closed fractures at moderately waterwet conditions, (2) a reduced capillary threshold pressure for water breakthrough owing to a less water-wet state, or (3) a mechanism where continuity in the wetting phase (the water) was established. As opposed to the water-wet case, Block CHP, gravity segregation in the open vertical fracture was not observed in Block CHP. The water entered Block C from the closed vertical fracture at 3 cm, with no visible influence from this fracture. The upper left corner near the inlet of CHP was poorly waterflooded, probably because of the increased permeability in the lower section of Block. CHP- Fractured Block; I w = CHP- Fractured Block; I w = CHP- Whole Block; I w = Brine Injected, PV Fig. Average water saturation during waterflooding of the strongly water-wet block CHP with interconnected fractures. Data for strongly water-wet block CHP,, when waterflooding the block as a whole and with embedded fractures, are included for comparison. A, caused by hydraulic continuity by the horizontal fracture from the inlet. It has been shown earlier that there is essentially no difference in total oil recovery, for a strongly water-wet block, between the whole block and the embedded fracture block.,, In Fig., the oil production for the fractured block CHP, with interconnected fractures, is compared to earlier results on strongly water-wet whole and fractured blocks with embedded fracture networks. This figure shows that water breakthrough in the block with interconnected fractures occured earlier, and the block produced less oil. The hydraulic contacts also resulted in a short period with two-phase production, giving a less-sharp water cut. Oil productions for the waterfloods on the whole and fractured moderately water-wet block, CHP, is shown in Fig.. Owing to the experimental problems of obtaining low initial water saturation when oilflooding the fractured blocks back to i, the water saturations for the waterfloods of the fractured block were initially higher than the waterflood as a whole block. At moderately waterwet conditions, the ultimate oil recovery was similar to the strongly water-wet case. This block showed earlier water breakthrough and a longer transition zone with two-phase production, causing additional oil to be produced after water breakthrough. By comparing the oil production in Figs. and, we observe that the total oil recovery from the blocks was reduced by a consistent, but small, amount after fracturing the blocks. This was consistent with results for all the different wettability conditions reported earlier. In the fractured block, CHP, the breakthrough of water occurred earlier than for the fractured water-wet block. The water breakthrough was also earlier in the less-water-wet fractured blocks than when waterflooded as whole blocks. This is consistent with the assumption that after fracturing, the permeability increased owing to the horizontal fracture along the center line of the blocks. The permeability increase for the embedded fracture network was insignificant; however, the interconnected fractures increased the endpoint relative permeability to oil at immobile water saturation by a factor of 2. The pattern of water movement during the first waterflood of the water-wet, fractured block CHP indicated that for the water phase, there was little capillary contact between Blocks A and C across the upper portion of the fracture at 3 cm. If there had been significant capillary continuity, water would have been expected to flow across the fracture and saturate the upper portion of Block C during the early stages of imbibition into Block A. However, gravity segregation of the fluids in the fractures indicated fairly open fractures at 3 cm for CHP. For the less-water-wet block, CHP, the water entered Block C across the closed vertical fracture at 3 cm, and no visible influence from the open fracture was observed. This indicated that the influence of the closed fractures on the flow pattern during waterflood was reduced as the wettability was changed toward moderately water-wet conditions. This may result from better physical contacts between the blocks in CHP, but because the reassembly procedure was similar for all the blocks, we speculate that the reduction in capillary holdup of the wetting. Brine Injected, PV CHP-, Whole Block CHP-, Interconnected Fractures Fig. Average water saturation in the moderately water-wet block CHP during waterflooding. 2 December 2 SPE Reservoir Evaluation & Engineering

9 phase at less-water-wet conditions was responsible. Alternatively, water droplets at the fracture may form and establish wetting-phase bridges across the fractures when the contact angle increases as wettability is changed to less-water-wet. The latter displacement mechanism depends on the fracture aperture and the viscous pressure in the wetting phase (i.e., the applied differential pressure and the wettability conditions, reflected by the increase in contact angle). We believe one of these two mechanisms, or a combination of the two, are responsible for observing less impact from the fractures on the waterflood at less-water-wet conditions. Capillary Pressure and Relative Permeability. We have previously measured the capillary pressure and relative permeabilities in chalk core plugs at strongly water-wet, moderately water-wet and. INITIAL PV SIMULATED EXPERIMENTAL PV 2 Fig. Comparison of experimental and simulated average water saturations for Block CHP with interconnected fracture network. nearly neutral-wet conditions. Plug wettability was selectively altered by aging outcrop chalk plugs at i in crude oil at an elevated temperature for selected periods of time. This procedure reproduced the desired wettability while keeping the pore-network structure and the mineralogy constant. Aging to a less-water-wet state significantly reduced spontaneous brine imbibition rate and brine saturation endpoint. However, it did not reduce the total moveable oil (i.e., imbibition plus forced displacement). In fact, the total moveable oil generally increased slightly with reduced water wettability; however, this occurred at the cost of higher differential pressures. Reduced water wettability also lowered the drainage threshold pressure. Repeated imbibition tests on individual plugs indicated that the wettability alteration was permanent.. INITIAL PV SIMULATED EXPERIMENTAL PV 2 Fig. Comparison of experimental and simulated water-saturation profiles averaged over a cross section of blocks at initial, PV, and PV when waterflooding Block CHP with interconnected fracture network.... PV injected PW-... PV injected PW PV injected PS PV injected PS PV injected PW-... PV injected PW PV injected PS PV injected PS PV injected PW-... PV injected PW PV injected PS PV injected PS PV injected PW-2 : Brine Saturation PV injected PS -2. : Brine Saturation Fig. Comparison of experimental (left two columns) and simulated (right two columns) in-situ saturation development for the first waterflood of the strongly water-wet block CHP with interconnected fracture network. December 2 SPE Reservoir Evaluation & Engineering 3

10 . - Experimental Simulation. Brine Injected, PV Fig. Comparison of experimental and simulated average water saturations when waterflooding the whole block CHP. Experimentally measured relative permeability curves and capillary pressure curves are used in the simulations. These tests were conducted to provide experimentally obtained input data for capillary pressure and relative permeability at a range of wettability conditions for numerical simulations of the waterfloods of the blocks. Numerical Simulations. A full-field simulator for fractured reservoirs, SENSOR,* was used in black-oil mode to simulate the waterflood experiments on the two blocks. The first simulations were run with the experimental measured values for capillary pressure and relative permeabilities at the different wettabilities. To improve the history match for both the oil production and the dynamics of the in-situ saturations, optimization of capillary pressure curves was carried out, keeping the relative permeabilities from the core-analysis results constant, and vice versa, using the capillary pressure from the centrifuge measurements and optimizing the relative permeabilies. This procedure would also give information on which measured values could be most trusted. Figs. through exhibit the results from simulating the waterfloods of the fractured strongly water-wet block, CHP, with the interconnected fracture network. Fig. displays the simulated average water saturation in the block compared to the experimental results. Fig. exhibits the match with in-situ saturations averaged across the cross section of the block perpendicular to the flood direction. Fig. shows a comparison of the 2D in-situ saturations obtained from simulations with the corresponding experimental results. The overall best match with the experiments was obtained with the capillary pressure curves and by optimizing the relative permeabilities. *All rights reserved separately and equally to K.H. Coats and Co. Inc. and Phillips Petroleum Co. Relative Permeability. Water Relative Permeability Simulation Oil Relative Permeability Simulation Water Relative Permeability Experimental Oil Relative Permeability Experimental. Fig. 2 Comparison of experimental and simulated water-saturation profiles averaged over a cross section of block at initial, PV, and PV when waterflooding the whole block CHP. Experimentally measured relative permeability curves and capillary pressure curves are used in the simulations. Figs. and 2 exhibit the results from simulating the waterfloods of the moderately water-wet whole block, CHP. The overall best match with the experiments was again obtained with the capillary pressure curves and by optimizing the relative permeabilities. Figs 3 and show the relative permeability curves and the capillary pressure curves for the chalk matrix as measured at the moderately water-wet conditions and the optimized curves from the simulations, respectively. The experimental results on wettability measurements of core plugs drilled out of the blocks after all the waterfloods had been completed are shown in Fig. and compared to the duplicate set of plugs used earlier. The results reveal that the aging process in the epoxy-coated block CHP has been slower than for the twin samples submerged in crude oil, leaving the block at a wettability index to water of I w rather than I w, as indicated by the twin samples. This result was corroborated by numerical simulations because applying more water-wet capillary pressure curves gave a better match with the experiments, as shown in Figs. and, and particularly exhibited by the improvement in the in-situ saturation match illustrated in Figs. 2 and. Conclusions. Two-dimensional in-situ saturations during waterfloods at strongly water-wet and moderately water-wet conditions in large fractured blocks of chalk have been monitored and used to determine oil-recovery mechanisms at different wettability conditions. 2. Water movement during waterflooding was significantly affected by the presence of fractures at strongly water-wet conditions for both embedded and interconnected fracture networks. 3. Water movement was not significantly affected by closed fractures during waterflooding at less-water-wet conditions, corresponding to I w. Capillary Pressure, psi INITIAL PV 2 Drainage Capillary Pressure Simulation Imbibition Capillary Pressure Simulation Drainage Capillary Pressure Experimental Imbibition Capillary Pressure SIMULATED EXPERIMENTAL PV Fig. 3 Experimentally obtained relative permeability curves compared to optimized relative permeability curves during history matching of the waterfloods of the whole block CHP. Fig. Experimentally obtained capillary pressure curves compared to the modified capillary pressure curves (I w=) used for input to the simulator. December 2 SPE Reservoir Evaluation & Engineering

11 . PC 2-3; I w = PC 2-; I w = CHP-; I w = CHP-2; I w = CHP-; I w = PC 2-; I w = PC 2-2; I w = P -; I w =., Time, hours Fig. Imbibition characteristics for a duplicate set of core plugs, PC2-3 and PC2-, and drilled-out plugs, CHP- to, from the moderately water-wet block CHP. Corresponding data for strongly water-wet and nearly neutral-wet plugs are included for comparison.. For unfractured and fractured chalk, the oil recovery by waterflooding was similar for strongly water-wet chalk and moderately water-wet chalk, even with a permeability increase of a factor close to after fracturing.. Interconnected fractures from injector to producer in the laboratory model did not significantly impact the final oil production, either at strongly water-wet conditions or at moderately water-wet conditions, but in-situ saturation distributions are shown to be affected significantly by the wettability conditions.. Even at fairly low flow rates, more oil was mobilized by waterflooding chalk at less-water-wet conditions than recovered by spontaneous brine imbibition, but oil recovery for these flow rates was always less than or equal to that recovered by strongly water-wet spontaneous imbibition.. Application of a simulator for fractured reservoirs has been validated by large-scale experiments with 2D in-situ imaging information.. Experimentally obtained P c and k r input data to the simulator have been evaluated by history matching the in-situ saturation distribution development and the production profile.. The overall best match between the simulations and the experiments was obtained with the capillary pressure curves and by optimizing the relative permeabilities. Nomenclature d = diameter, cm I = Amott wettability index k = permeability, md L = length, cm P c =capillary pressure, bar R = oil recovery, % S = saturation. I w =. I w = I w = I w = Experimental Simulation. Brine Injected, PV Fig. Matching of experimental and simulated average water saturation when waterflooding the whole block CHP. A modified capillary pressure curve is used in the simulations. t = time, days T = temperature, C, = change in water saturation = viscosity, cp H = density, g/cm 3 I = interfacial tension B = porosity, % Subscripts a = aging D = displacement eff = effective f = final i = initial I = imbibition k = permeability, md o = oil S = saturation SI = spontaneous imbibition w = water References. Lien, J.R., Graue, A. and Kolltveit, K.: A Nuclear Imaging Technique for Studying Multiphase Flow in a Porous Medium at Oil Reservoir Conditions, Nucl. Instr. & Meth. () A2, Graue, A. et al.: Imaging Fluid Saturation Development in Long- Coreflood Displacements, SPEFE (December ). 3. Graue, A.: Imaging the Effect of Capillary Heterogeneites on Local Saturation Development in Long Corefloods, SPEDC (March ) ; Trans., AIME, 2.. Graue, A. et al.: Large-Scale Two-Dimensional Imaging of Impacts of Wettability Effects on Fluid Movement and Oil Recovery in Fractured Chalk, SPEJ (March ) 2.. Graue, A., Viksund, B.G., and Baldwin, B.A: Reproducible Wettability Alteration of Low-Permeable Outcrop Chalk, SPEREE (April ) 3.. Viksund, B.G. et al.: 2-D Imaging of waterflooding a Fractured Block of Outcrop Chalk, paper presented at the Chalk Research Symposium, Reims, France, October.. Viksund, B.G. et al.: 2D-Imaging of the Effects from Fractures on Oil Recovery in Larger Blocks of Chalk, paper presented at the Intl. Symposium of the Society of Core Analysts, Calgary, September.. Amott. E.: Observations Relating to the Wettability of Porous Rock, Trans., AIME () 2,.. Graue, A. et al.: Impacts of Wettability on Capillary Pressure and Relative Permeability, paper SCA- presented at the Intl. Symposium of the Soc. of Core Analysts, Golden, Colorado, August.. Coats, K.H., Thomas, L.K., and Pierson, R.G.: Compositional and Black Oil Reservoir Simulation, paper SPE 2 presented at the SPE Reservoir Simulation Symposium, San Antonio, Texas, 2 February.. INITIAL PV SIMULATED EXPERIMENTAL PV 2 Fig. Comparison of experimental and simulated water-saturation profiles averaged over a cross section of block at initial, PV, and PV when waterflooding whole block CHP. Simulation with modified (I w = ) capillary pressure curve. December 2 SPE Reservoir Evaluation & Engineering

12 SI Metric Conversion Factors cp.* E 3 = Pa s ft 3.* E = m ft 2.2 3* E 2 = m 2 ft E 2 = m 3 in. 2.* E = cm lbf. 222 E = N psi. E = kpa *Conversion factor is exact. SPEREE Arne Graue is a professor of reservoir physics in the Dept. of Physics, U. of Bergen, Norway. Arne.Graue@fi.uib.no. His primary research interests include fundamental studies of multiphase flow in porous media, particularly emphasizing hydrocarbon-recovery mechanisms and the impacts of wettability on oil recovery in heterogeneous reservoirs. He has been a visiting scientist at MIT and Phillips Research Center and a visiting professor at the U. of Wyoming. He has been coordinating interdisciplinary reservoir research at the U. of Bergen for years. Graue holds BS degrees in mathematics and physics, an MS degree in nuclear physics, and a PhD degree in reservoir physics, all from the U. of Bergen. Thomas Bognø is a research assistant in the Dept. of Physics at the U. of Bergen. Thomas.Bogno@fi.uib.no. His primary research interests are studies of multiphase flow in porous media, emphasizing special core analysis and research on improved oil recovery. Bognø holds BS degrees in mathematics and physics and an MS degree in reservoir physics; he is currently studying for his PhD degree in reservoir physics at the U. of Bergen. Bernard A. Baldwin is a retiree from Phillips Petroleum Co., Bartlesville, Oklahoma, and is currently the President of Green Country Petrophysics, an E&P consulting firm. bbaldwi@ppco.com. His current interests include magnetic resonance imaging of fluids and saturation development in core, electrical properties, wettability, and surface characterization. Prior assignments included automotive lubrication, surface analysis, and UV-visible-IR spectroscopy. Baldwin holds a BS degree from La Verne U., an MS degree from San Diego State U., and a PhD degree in physical chemistry from the U. of California, Santa Barbara. Eugene A. Spinler is a senior principal reservoir engineer at Phillips Petroleum Co. Reservoir and Production Technology Branch in Bartlesville, Oklahoma. e- mail: easpinl@ppco.com. His primary research areas are reservoir fundamentals, IOR, and wettability. Spinler holds a BS degree in engineering science and an MS degree in mechanical engineering, both from Montana State U. December 2 SPE Reservoir Evaluation & Engineering