Search

Summary In this paper, we describe a laboratory investigation of a nonionic surfactant for carbon dioxide-(CO2-) foam mobility control in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. A method of high-performance liquid chromatography-evaporativelight-scattering detector (HPLC-ELSD) was followed for characterizing the surfactant stability. The foam transport process was studied in the absence and the presence of East Seminole crude oil, with test results showing that strong CO2-foam forms in either a bulk-foam test or foam-flow test. An oxygen scavenger, carbohydrazide, was found effective for controlling the stability of the surfactant up to 80°C and total dissolved solid of ∼34,000 ppm. Moreover, a phosphonate scale inhibitor was investigated and found to be compatible with the oxygen scavenger to accommodate a surfactant solution in a gypsum-oversaturated reservoir brine. During the oil-fractional flow test, an emulsion appears to form, causing a noticeable pressure increase; however, emulsion generation failed to cause a significant phase plugging in the test. Also, a STARS™ (Computer Modelling Group Ltd., Calgary, Alberta, Canada) foam model was applied to obtain the foam parameters from the foam-flow experiments at steady-state conditions. The insights from laboratory experiments better enable translation of the foam technology to the field.

Wettability controls the location, distribution, and flow of fluids in a pore network. Obtaining a uniform core scale wettability distribution is therefore a necessary condition for reliable special core analysis (SCAL). In the present work, dynamic and static aging procedures were used to alter the wettability of outcrop Edwards limestone, and Amott-Harvey cycles were performed on whole and split core samples to evaluate wetting distribution and stability. Dynamic aging was observed to be more efficient and produced a more uniform and reproducible wettability distribution compared to static aging. Rock-fluid and fluid-fluid interactions, evaluated by Isothermal Titration Calorimetry (ITC) experiments, confirm that supplying fresh crude oil during the aging procedure to a core plug causes the greatest wettability change. Synergy between ITC and simple core scale experiments provide an improved understanding of the wettability alteration at microscopic and macroscopic levels in heterogeneous Edwards limestone.

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.

An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.

Numerical tools are essential for the prediction and evaluation of conventional hydrocarbon reservoir performance. Gas hydrates represent a vast natural resource with a significant energy potential. The numerical codes/tools describing processes involved during the dissociation (induced by several methods) for gas production from hydrates are powerful, but they need validation by comparison to empirical data to instill confidence in their predictions. In this study, we successfully reproduce experimental data of hydrate dissociation using the TOUGH+HYDRATE (T+H) code. Methane (CH4) hydrate growth and dissociation in partially water- and gas-saturated Bentheim sandstone were spatially resolved using Magnetic Resonance Imaging (MRI), which allows the in situ monitoring of saturation and phase transitions. All the CH4 that had been initially converted to gas hydrate was recovered during depressurization. The physical system was reproduced numerically, using both a simplified 2D model and a 3D grid involving ...

Foam injection is a proven enhanced oil recovery (EOR) technique for heterogeneous reservoirs, but is less studied for EOR in fractured systems. We experimentally investigated tertiary \(\text {CO}_{2}\) injections, and \(\text {N}_{2}\)- and \(\text {CO}_{2}\)-foam injections for enhanced oil recovery in fractured, oil-wet limestone core plugs. Miscible \(\text {CO}_{2}\) and \(\text {CO}_{2}\)-foam was compared with immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foam as tertiary recovery techniques, subsequent to waterfloods, in fractured rocks with different wettability preferences. At water-wet conditions waterfloods produced approximately 40 % OOIP, by spontaneous imbibition. Waterflood oil recovery at oil-wet conditions was below 20 % OOIP, due to suppressed imbibition where water predominantly flowed through the fractures, unable to mobilize the oil trapped in the matrix. Tertiary, supercritical \(\text {CO}_{2}\)-mobilized oil trapped in the matrix, particularly at weakly oil-wet conditions, by diffusion. Recovery by diffusion was high due to small core samples, high initial oil saturation and a continuous oil phase at oil-wet conditions. Both immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foams and miscible, supercritical \(\text {CO}_{2}\)-foam demonstrated high ultimate oil recoveries, but immiscible foam was less efficient (30 pore volumes injected) compared to miscible foam (2 pore volumes injected) to reach ultimate recovery. This is explained by the capillary threshold pressure preventing the injected \(\text {N}_{2}\) gas from entering the matrix, verified by computed X-ray tomography, and the mobilized oil was displaced by the aqueous surfactant in the foam. At miscible conditions, there exists no capillary entry pressure between the oil-saturated matrix and the injected \(\text {CO}_{2}\), allowing foam to invade the matrix for efficient oil recovery.

This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.

The use of foam to increase oil recovery by reducing the gas mobility during gas injection in heterogeneous reservoirs with permeability variations is a proven EOR technology. The use of foam for fracture permeability reduction in fractured reservoirs is less studied. In this work laboratory experiments using foam to reduce fracture transmissivity and improve the matrix sweep in highly fractured, low permeable, oil-wet limestone are reported. Oil recovery either by individual water-, surfactant-, or gas injection exhibited low recovery, less than 10%OIP, with oil recovered predominately from the fractures. Oil recovery was significantly improved by simultaneous injection of surfactant and gas to generate foam in the fracture network and thus divert flow to the oil saturated matrix. Two foam injection schemes were tested: 1) co-injection of surfactant and gas in the fracture for in-situ foam generation, and 2) pre-generated foam injection. In-situ foam generation in the smooth-walled fractures was weak and not sufficient to divert fluids from the fractures and into the matrix. Injection of stable, pre-generated foam caused an increase in the differential pressure and diverted fluid to the matrix, yielding a significant increase in oil recovery, 80% OIP was receverd at high pore volumes injected.

We present experimental wettability alteration results in originally strongly water-wet, outcrop chalk core plugs using a static and two dynamic aging methods. Dynamic aging with continuous crude oil injection during the entire aging process exhibited greater reduction in water-wetness of the strongly water-wet chalk plugs than static aging without flushing. Two dynamic aging procedures were tested to find an optimal flooding rate for the most efficient reduction in water-wetness: (1) a constant crude oil flooding at 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable flooding rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Aging was performed on consolidated, porous chalk samples with initial water present in the pore space. It was shown that static aging, i.e., ...

SummaryDuring waterfloods of six outcrop chalk core-plug samples prepared at various wettabilities, simultaneous local pressures and in-situ fluid saturations were measured. Using high-spatial-resolution magnetic-resonance imaging (MRI) to image fluid saturations and pressure taps with semipermeable disks to measure individual phase pressures allowed calculations of relative permeabilities and the dynamic capillary pressure curves for the imbibition processes. A second objective was to identify individual-fluid saturation changes caused by spontaneous imbibition and viscous displacement to determine the local recovery mechanism and to calculate local recovery factors and in-situ Amott-Harvey indices. The obtained results contribute to improved description and understanding of multiphase-fluid flow in porous media, including in situ measurements of relative permeabilities, dynamic capillary pressure curves, Amott-Harvey Indices, and local oil-recovery mechanisms.

A novel centrifuge technique to obtain the capillary pressure curve by measuring the local fluid distribution in a spinning core is presented. The Nuclear Tracer Imaging Centrifuge (NTIC) method measures the fluid saturation profile along the length of the core to directly obtain the capillary pressure curve. The proposed method is superior to conventional centrifuge techniques because (1) the capillary pressure curve is obtained at one rotational speed, (2) core plugs are not removed from the spinning centrifuge for imaging, and (3) no mathematical solution is needed to calculate the capillary pressure curve. The literature states that the various mathematical solutions used in conventional centrifuge tests are the greatest source of error, not the uncertainty in the experimental data. By eliminating the dependence of such solutions, the NTIC represents an alternative to conventional centrifuge tests, and may be used to validate the various mathematical procedures applied in conventional centrifuge capillary pressure tests. NTIC may also confirm the applicability of other imaging techniques that rely on core plug removal for saturation imaging, by verifying if there is no fluid re-distribution at static conditions.

Polymer gels are frequently applied for conformance improvement in fractured reservoirs, where fluid channeling through fractures limits the success of waterflooding. Placement of polymer gel in fractures reduces fracture conductivity, thus increasing pressure gradients across matrix blocks during chase floods. A gel-filled fracture is re-opened to fluid flow if the injection pressure during chase floods exceeds the gel rupture pressure, thus channeling through the fractures resumes. The success of a polymer gel treatment therefore depends on the rupture pressure. Swelling of gels, e.g. pre-formed particle gels, due to salinity differences between the gel network and surrounding water phase has recently been observed, but the effect has been less studied in conjunction with conventional polymer gels. Using core floods, this study demonstrates that low-salinity water can swell conventional Cr(III)-acetate HPAM gels, thereby improving gel blocking performance after gel rupture. Formed polymer gel was placed in fractured core plugs and chase waterfloods were performed, using four different brine compositions of which three were low-salinity brines. The fluid flow rates through the matrix and differential pressures across the matrix and fracture were measured and shown to increase with decreasing salinity in the injected water phase. In some cores, the fractures were re-blocked during low-salinity waterfloods, and gel blocking capacity was increased above the initial level. Low-salinity water subsequently flooded the matrix during chase floods, which provided additional benefits to the waterflood. The improved blocking capacity of the gel was caused by a difference in salinity between the gel and injected water phase, which induced gel swelling. The results were reproducible through several experiments, and stable for long periods of time in both sandstone and carbonate outcrop core materials. Combining polymer gel placement in fractures with low-salinity chase floods is a promising approach in integrated EOR (IEOR).

The blockage performance of a Cr(III) acetate-HPAM gel was investigated using several different application regimes and gel maturities. Fractured core plugs from four outcrop core materials were used, all constituting smooth, longitudinal fractures of 1 mm aperture. Mature and immature gel was placed in the fractures, and for some application regimes in the surrounding core matrix, and the blockage performance assessed by recording rupture pressures and subsequent residual resistance factors during chase waterfloods, Frrw. Placement of mature gel in open fractures yielded consistent rupture pressures during subsequent water injections, following linear trends for given gel placement rates and throughput volumes. The rupture pressures were predictable and stable in all the core materials studied. Rupture pressures achieved after placement and in-situ crosslinking of gelant were comparable to mature gel rupture pressures, but were less predictable. When maximizing gelant saturation in the matrix, rupture pressures were measured to 12 – 53 psi/ft. The maximum achieved rupture pressure when gelant was placed without matrix taps to promote leakoff was 11.9 psi/ft. Interactions between rock material and gelant were observed when Bentheim sandstone cores were used, and gel was in some cases not formed. No such interactions were observed in experiments using formed gel. Significant permeability reduction for water was achieved when both gel and gelant were used. Residual resistance factors for cores treated with gel and gelant were initially comparable. After eight water flushes (>120 fracture volumes (FV) water injected) substantially greater pressure gradients were observed in cores treated with formed gel rather than gelant cross-linked in-situ and the permeability reduction averaged a factor 5000 for gel and 600 for gelant treated cores. The significance of these observations to field applications will be discussed.

This paper reports on studies of two-dimensional local saturation development in a cross layered reservoir model. Numerical simulations and experimental studies have been performed on a heterogeneous reservoir model consisting of three blocks of porous material with capillary and permeability contrasts connected at a dip angle of 45°. The physical reservoir model measured 22 cm × 5 cm × 5 cm and was composed of blocks of Vosges sandstone alternating with Aerolith-10, an artificial sintered porous medium with high porosity and permeability. The physical properties, porosities, permeabilities, capillary pressures, and end-point saturations of the blocks composing the heterogeneous medium were measured independently on isolated samples. A series of oilfloods and waterfloods were performed, and dynamic two-dimensional saturation fields were measured by gamma-ray attenuation. After drainage, during a no-flow state at low water saturation, we observed a redistribution of fluids near the boundaries of permeability contrasts due to capillary pressure differences between the blocks. The two-dimensional saturation fields recorded during the low-rate waterfloods showed a different behavior in different layers due to the contrasts of permeability and capillary pressure. Recovery efficiency by waterflooding isolated samples does not necessarily predict local recovery in composite models. Good reproducibility was obtained by performing different experiments with the same boundary conditions and petrophysical properties. Two-dimensional numerical simulations performed with the full-field commercial simulator ECLIPSE confirmed the observed experimental behavior. However, the simulated recovery from each block did not match the experimental results. We concluded that two-dimensional local saturation information in larger scale three dimensional reservoir models significantly improves the interpretation of the recovery mechanisms in heterogeneous porous media.

A comparative study of numerical modelling and laboratory experiments of two-phase immiscible displacements in a 33 cm × 10 × 3 cm thick cross-bedded reservoir model is reported. Dynamic two-dimensional fluid saturation development was obtained from experiments by use of a nuclear tracer imaging technique and compared to numerical predictions using a full-field black oil simulator. The laboratory cross-bedded reservoir model was a sandpack consisting of two strongly waterwet sands of different grain sizes, packed in sequential layers. The inlet and outlet sand consisted of low permeable, high capillary, sand while the central crosslayer with a dip angle of 30° was a high permeable, low capillary, sand. Results on moderate contrasts in permeability and capillary heterogeneities in the cross-bedded reservoir model at different mobility ratios and capillary number floods temporarily showed a bypass of oil, resulting in a prolonged two-phase production. The final remaining oil saturations, however, were as for isolated samples. Hence, permanently trapped oil was not observed. Simulations of waterfloods, using a commercial software package, displayed correct water breakthrough at low flow rate and unity viscosity ratio, but failed in predicting local saturation development in detail, probably due to numerical diffusion. The simulator was used to test several cases of heterogeneity contrasts, and influence from different relative permeability curves. Further, by altering the capillary pressure at the outlet, the end effects were proven important.

This work experimentally investigates a two-step, integrated EOR technique for heavily fractured, oil-wet carbonate rocks by combining fracture mobility control and chase fluid injections for increased sweep. The combination of mobility control using a cross-linked Cr(III)-Acetate HPAM polymer gel, and three different chase fluids (water, surfactant or CO2 foam) was investigated as an integrated EOR approach. Waterflood oil recovery was low with poor sweep efficiency and oil production from the fracture volume only. Fracture conductivity was significantly reduced after polymer gel placement in the fracture, leading to increased sweep and oil recovery during chase fluid injections, with oil recoveries up to 60%OOIP.

During waterfloods of a total of six outcrop chalk core plug samples prepared at various wettabilities, simultaneous local pressures and in situ fluid saturation from Magnetic Resonance Imaging (MRI) intensities were measured. Complementary use of high spatial resolution fluid saturation imaging and phase pressure measurements allowed calculations of the relative permeability to water and the dynamic capillary pressure curves for the imbibition process. One objective was to validate the theory for relative permeability calculations based on data from the fluid phase pressures measured separately using semi-permeable discs and local in situ fluid saturation measurements. A second objective was to identify fluid saturation changes due to spontaneous imbibition and viscous displacement, respectively, to determine the local recovery mechanism and allowing local recovery factors and in situ Amott-Harvey indices to be measured. The analysis of the experimental data from three of the core samples shows that the presented theory only applies for the saturation interval when the pressures are measured in the same phase. A new and improved experimental setup is therefore introduced for the remaining three cores in order to measure each of the dynamic phase pressure gradients separately using semi-permeable discs located at fixed pressure ports. The obtained data contributes to improved description and understanding of multi-phase fluid flow in porous media, including in situ measurements of relative permeabilities, capillary pressure curves, wettability distribution and local oil recovery mechanisms.

The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at increasing constant pressures were carried out to determine the relation between remaining oil and applied capillary number in waterfloods at different wettability conditions. Various uniform distributed mixed wettability conditions were established and quantified by the Amott test for 21 core plug samples. Minimum remaining oil at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The residual oil saturation decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery.

Abstract The ratio between the viscous and capillary forces, commonly denoted the Capillary Number Nc, is crucial in determining the remaining oil saturation. The impact on residual oil saturation by a systematic increase in Nc is determined in homogeneous chalk at wettabilities varying from nearly neutral-wet to strongly-water-wet conditions. In fractured chalk reservoirs waterflood residual oil saturation is strongly dependent on the wettability. The current results provide assistance in determining the potential target for tertiary oil recovery by measuring the amount of mobile oil at various Nc. A series of displacements of oil by water injection at constant pressure were carried out to determine the relation between oil recovery and applied capillary number in waterfloods at different wettability conditions. Maximum oil recovery at constant Nc occurred at wettability conditions reflecting an Amott Index to water at 0.3. The remaining oil decreased with increasing capillary number and significant trapped oil after completed spontaneous water imbibition was mobilized at moderately water-wet to nearly neutral-wet conditions. Similar results as reported in the literature for waterflooding residual oil saturations as function of wettability and PV water injected in sandstone were found for chalk at increasing capillary number. Distinct dome shaped curves of oil recovery as function of wettability, with consistent increase in oil recovery with increasing capillary number, reflected similarities to earlier results on waterflooding oil recovery. Introduction The opportunity window for implementing IOR schemes for a given reservoir in production is limited when reaching the tail production. It is vital that the amount of potential target oil for EOR is determined as early as possible, and in this respect that the ultimate immobile or residual oil saturation for the rock/crude/brine system at the wettability conditions present in the reservoir is determined. Oil recovery depends strongly on the wettability condition and the interaction between the capillary and viscous forces will accordingly change with wettability [1, 2]. This study emphasizes the impact from wettability on the residual oil saturation during increasing differential viscous pressure drops at various wettabilities. Capillary forces are responsible for fluid entrapment during an immiscible displacement in porous media. Laboratory studies have shown that more of the remaining oil may be recovered in immiscible displacements if increased viscous displacement is applied. By exceeding the capillary forces trapped residual oil may be mobilized [3]. The capillary forces are determined by the wettability conditions and the oil/water interfacial tension (IFT). The potential to mobilize capillary trapped oil depends on the pore geometry. The required viscous force needed to mobilize trapped oil is determined by the fluid dynamics of the displacing phase. Thus an important parameter determining mobilization of capillary trapped oil during immiscible fluid displacements is the capillary number; exhibiting the ratio of viscous forces to the capillary forces.

Abstract A nuclear tracer imaging technique is evaluated for use in core analysis in studies of oil recovery from chalk reservoirs. In-situ fluid saturation data in long-core flood experiments in chalk, enhance the interpretations of the data; especially in mapping the local recovery efficiencies. In various long core flood displacements, including both drainages and waterfloods, emphasis has been on recording local in-situ saturation development, obtaining recovery efficiencies and studying effects on the saturation profiles from displacement pressure drops, flow rates and initial and final water saturations. The benefits of having access to local in-situ saturation information, the importance of being able to identify rock heterogeneities and tests of repeatability have been stressed. Introduction Over the past 20 years extensive efforts have been put on research on improving hydrocarbon recovery from chalk reservoirs. The challenge to understand and predict oil production from tight chalk reservoirs fully came in focus when the enormous potential for oil and gas production from chalk reservoirs in the southern part of the North Sea was discovered. The chalk reservoirs in this region are heavily fractured and the interwell fluid transport is thus conducted through the fracture network. The production mechanism is based on spontaneous water imbibition into the low permeable rock matrix, expelling the in-situ hydrocarbons into the surrounding fractures; and by continuous waterflooding of the fractures transporting the expelled oil to the producing wells. The imbibition rate and the sweep efficiency due to the spontaneous water imbibition are both crucial factors for the economics of the oil production. Deterministic for these processes are the wettability conditions and the relationships between the interacting forces: the capillary hold up, the viscous forces and the gravity. Extensive work have been reported on the challenge to understand and describe the production mechanisms, both regarding the interaction between fluid transport in the fractures and the matrix imbibition/reimbibition, and the oil displacement mechanism governed by wettability induced spontaneous water imbibition (ref. 1-8). The major problems related to the latter are to determine endpoint saturations, production rates and may be most important how to convert such laboratory data to results valid for the in-situ reservoir conditions. With regard to the fracture/rock matrix interactions, the dual porosity approach for modelling purposes has frequently been used (ref. 9), however, the important effects induced by gravity; fluid segregation, reimbibition and gravity assisted drainage in matrix block systems in capillary contact, have yet not been adequately addressed. A thorough investigation of these problems requires access to in-situ saturation information during an experimentally simulated production situation. For core analysis various imaging techniques (ref. 10-16) are applicable, including NMR-imaging and CAT-scanning, in order to obtain detailed information of the saturation development during the oil displacement. However, these techniques are not well suited in larger scale experiments using long cores to minimize disturbance from the end-effects experienced in small core plugs and when studying gravity drainage. P. 571^

Polymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. With successful polymer gel conformance control in place, increased pressure gradients across matrix blocks may be achieved during chasefloods, diverting water, gas or EOR chemicals into the matrix to displace oil. Knowledge of gel behavior during placement and chase floods is important, because it largely controls the success of subsequent injections. Polymer gel behavior is often studied in core floods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chasefloods. The work presented in this paper utilize complimentary PET-CT imaging to quantify the behavior and blocking capacity of Cr(III)-Acetate HPAM gel during chase waterflooding. In-situ imaging provides information about changes that may not be extracted from pressure measurements and material balance only, such as changes in local fluid saturations and dynamic spatial flow within the fracture and within the structure of the gel network. Polymer gel was placed in core plugs with longitudinal fractures that connected the inlet and outelt, and chase water was subsequently injected to measure the gel blocking capacity. The water phase was labelled with a positron emitting radiopharmaceutical (F-18) to visualize and quantify local flows with positron emission tomography (PET) during gel rupture and subsequent flooding. Using PET, we study gel rupture and the development of wormholes during gel erosion after rupture as a function of flow rate. A particular strength with access to dynamic, local flow patterns is the direct comparison to global measurements, such as differential pressure and production rate, to verify existing gel behavior models.