Relationship between Residual Saturations and Wettability using Pore-Network Modeling

Oil-water transition zones may contain a sizable part of a field's STOIIP, specifically in low permeable sandstone and carbonate reservoirs. The amount of recoverable oil in a transition zone depends–among other things- on the distribution of initial oil saturation (Soi) as a function of depth and the dependency of the oil's mobility, i.e., the residual oil saturation (Sor) and relative permeability, on initial oil saturation. In this paper we present laboratory measurements of residual oil saturation and oil relative permeability as a function of initial oil saturation to properly characterize oil mobility in transition zone. We found that the residual oil saturation after water flooding showed, for the example studied here, no dependence on initial oil saturation. On the other hand we found that there is a clear trend in the imbibition oil relative permeability for decreasing Soi, i.e., for a given oil saturation oil mobility increases as initial oil saturation decreases. In other words, laboratory measurements show that the mobility of oil in the transition zone is much higher than conventional analysis would suggest. Consequently, in a given time span more oil can be produced from the transition zone than generally assumed and potentially large volumes of reserves can be added to reservoirs with large transition zones. The impact of the measured relative permeabilities and residual oil saturations on oil recovery has been quantified for a generic field example by numerical modeling using MoReS, the Shell group reservoir simulator. The recovery factor was found to increase from 32% using a single set of relative permeability curves for the whole field independent of initial oil saturation to 56% using the measured Soi dependent relative permeability curves. The water cut at abandonment was for both cases taken at 95%.

Hysteresis commonly exists in relative permeability curves, especially during a cyclic process. To describe hysteresis impact on fluid behaviors, scanning curves are normally applied in numerical simulation models. Hysteresis pertains to saturation history, in which scanning curves and trapped oil saturation are dependent on the initial oil saturation. For mixed-wet carbonate reservoirs that have thick transition zones, initial water saturations greater than irreducible water saturations are distributed conforming to saturation-height functions and rock types. Therefore, water-flood follows the scanning curve path where intermediate saturation reversal occurs, altering the trapped oil saturation. In the field development plan during water-flooding process, infill drilling identification is traditionally based on simulation model remaining-oil-in-place map or single residual oil saturation attributed to rock types. In this paper, hysteresis-model derived recoverable oil is computed from history-matched model and employed to assist wells planning. An automated infill-drilling program has been coded by considering Killough hysteresis model. First, initial and current saturation at development time are extracted, and end-point residual saturation is identified from saturation functions. Second, the amount of trapped and up-to-date remaining recoverable oil is calculated for each grid cell. Then, the optimum infill locations are identified to maximize contact area with mobile oil. Completion data are generated as output for reservoir simulation. Since optimum infill locations are identified, better oil-recovery is achieved by implementing the proposed approach, which targets both oil zone and transition zone. Single residual oil by rock types may not help identify the anticipated wells locations in the mature reservoirs. The approach is validated by suggesting less and optimum number of wells while bringing higher recovery according to simulation results. Potential of Enhanced Oil Recovery (EOR) can be further evaluated after quantifying the remaining oil saturation. In the transition zone, larger pores are filled with oil and the trapped oil saturation is lower than that above dry oil intervals, enabling possible wells production in the transition zone. Initial-saturation-dependent residual oil saturation is used to better map the infill drilling. Rather than adopting the single residual oil saturation by roc type, this approach considers hysteresis-led trapped oil saturation for the preliminary automatic wells screening and optimization prior to dynamic simulation. This process is repeatable and adjustable in line with the development strategy. For the giant and mature oil reservoirs, it demonstrates a better and more efficient development plan.

Summary The amount of recoverable oil in an oil/water transition zone depends on the distribution of oil saturation as a function of depth and on the relationship between initial and final oil saturation in the transition zone (Soitz and Sortz), as well as the volumetric extent of the zone. Conventionally, it is assumed that Sortz is constant and equal to the residual oil saturation in the oil column (Sor) above the transition zone. However, limited data in the literature show that residual oil saturation depends on initial oil saturation as described by the trapped-oil relationship. Thus, Sortz should be a function of Soitz. The purpose of this paper is to present recent experimental corroboration of the trapped-oil relationship and to demonstrate the impact of the trapped-oil relationship on reserves determination in oil/water transition zones. The effect of the trapped-oil relationship on reserves determination is shown in two ways: first, with an analytical model that shows the maximum possible incremental benefit of including the trapped-oil relationship; and second, with an extended black-oil simulation that incorporates the effects of relative permeabilities on reserves determination.

The objective of this paper is to investigate the transport and incremental oil recovery associated with Polyethylene Oxide (PEO) compared to Hydrolyzed Polyacrylamide (HPAM) through a series of corefloods in low permeability carbonate cores for use in enhanced oil recovery (EOR). Recent studies have brought attention to PEO's improved injectivity in low permeability carbonate reservoirs compared to acrylamide-based polymers offering a promising alternative (Mejia et al., 2022a; Mejia et al., 2022b; Trine et al., 2022). Five two-phase experiments were conducted in Indiana limestone cores (permeability <100 mD) with PEO and HPAM of similar molecular weights (4 MM Dalton) and viscosity; they were designed to measure incremental oil recovery for both polymers. Tracer tests were completed to determine heterogeneity. Brine was displaced by a 50-cP oil, and initial oil saturations averaged 55.8%. The oil was displaced initially with a waterflood for 3-5 pore volumes. The waterflood, on average, recovered 60.7% of original oil in place (OOIP). Oil cut was consistently zero at the conclusion of the waterflood suggesting the cores were at or near residual oil saturation. The polymer flood followed the waterflood for three pore volumes or until oil cut was zero. HPAM was injected in the first two experiments, and PEO was injected in the final three. When HPAM was injected, oil production in terms of OOIP from the polymer flood was minimal (average 2.2%) which was expected since oil saturation was presumed near residual. However, in the experiments when PEO was injected, oil production from the polymer flood averaged 13.5%, suggesting that residual oil saturation was decreased by the polymer. PEO was consistently shown to produce more oil compared to HPAM. This work suggests that PEO may result in higher oil recoveries and reduced residual oil saturation under certain conditions.

It is widely recognized that the determination of the amount and distribution of residual oil saturation (Sorw) is a significant factor in managing ongoing waterflooding and the selection of EOR methods that are applicable and economically suitable for oil reservoirs. Laboratory core flooding tests are often used to estimate the amount of Sorw. The same core samples are then usually subjected to EOR flooding experiments to estimate the extra amount of oil that can be recovered with the specific EOR option. Failure to accurately determine Sorw will lead to wrong estimates of recovery factor of both waterflooding and the subsequent EOR methods. Significant amount of data is available in the literature on determining Sorw and on the critical capillary or bond number to mobilize Sorw. However, most of the data are measured on sandstone rock and for water-wet conditions. In this study the focus is on 1- determination of Sorw in the laboratory for carbonate reservoirs, 2- The factors that affect Sorw, including capillary end effect, capillary and Bond numbers, initial oil saturation, rock permeability, rock heterogeneity and experimental techniques and 3- The use of numerical simulation as tool to aid proper interpretation of laboratory experiments. The main conclusions of the study are: 1- Performing the water flooding experiments at reservoir rates of ~1 ft/d will lead to overestimation of Sorw as the data can be dominated by capillary end effect; 2- The relative contribution of capillary end effect increases as the permeability increases especially for heterogeneous carbonate rocks; 3- There is no correlation between Sorw and rock permeability or porosity for the case understudy; 4- The critical capillary or bond number of non-water-wet carbonates is much higher than those reported in the literature for water-wet sandstone; thus experiments can be performed at higher rates than those expected in the field without the risk of de-saturation of Sorw and 5- Once an equilibrium between capillary and viscous (or gravity) forces is established, the remaining oil saturation is independent of the number of pore volumes injected. The data presented in this paper has significant impact on the design of any subsequent EOR process. It shows that the EOR target (after waterflood) is significantly reduced if the measurements are performed using high rates (or high centrifuge speed) to overcome capillary end effect. Moreover, for non-water wet rock surfactant flooding will require much higher reduction in IFT to mobilize residual oil saturation than for water-wet rocks.

Wettability Literature Survey- Part 4: Effects of Wettability Part 4: Effects of Wettability on Capillary Pressure Summary. The capillary-pressure/saturation relationship depends on the interaction of wettability, pore structure, initial saturation, and saturation history. No simple relationship exists that relates the capillary pressures determined at two different wettabilities. Therefore, the most accurate measurements are made with cores that have native reservoir wettability. In a uniformly wetted porous medium, pore geometry effects and the extremely rough surfaces of the porous medium make the capillary pressure curve insensitive to wettability for small contact angles (less than about 50 deg.[0.87 rad] for drainage capillary pressure curves and less than about 20 deg. [0.35 rad] for spontaneous-imbibition capillary pressure curves). When the porous medium has fractional or mixed wettability, both the amount and distribution of the oil-wet and water-wet surfaces are important in determining the capillary pressure curve, residual saturations, and imbibition behavior. Imbibition also depends on the interaction of wettability, pore structure, initial saturation, and saturation history. Because of these interactions, there is a large range of contact angles where neither oil nor water will imbibe freely into a uniformly wetted reservoir core. In contrast, it is sometimes possible for both fluids to imbibe freely into a core with fractional or mixed wettability. Contact Angles, Capillary Pressure, and Wettability This paper is the fourth in a series of literature surveys covering the effects of wettability on core analysis. Changes in the wettability of cores have been shown to affect electrical properties, capillary pressure, waterflood behavior, relative permeability, dispersion, simulated tertiary recovery, irreducible water saturation (IWS), and residual oil saturation (ROS). When oil and water are placed together on a surface, a curved interface between the oil and water is formed, with a contact angle at the surface that can range from 0 to 180 deg. [0 to 3.15 rad]. By convention, the contact angle, 0, is measured through the water. Generally, when 0 is between 0 and 60 to 75 deg. [0 and 1.05 to 1.31 rad], the system is defined as water-wet. When 0 is between 180 and 105 to 120 deg. [3.15 and 1.83 to 2.09 rad], the system is defined as oil-wet. In the middle range of contact angles, a system is neutrally or intermediately wet. It can be shown that whenever an oil/water interface is curved, the pressure will abruptly increase across the interface to balance the interfacial tension (IFT) forces. This pressure jump, which is the capillary pressure, is given by Laplace's equation : (1) where sigma = IFT, P = capillary pressure, p = pressure in the oil, p = pressure in the water, and r1, r2 = radii of curvature of the interface, measured perpendicular to each other. By convention, the capillary pressure is defined as po-pw. Because of this definition, a radius of curvature po-pw. Because of this definition, a radius of curvature directed into the oil is positive, while one directed into the water is negative. Depending on the curvature of the surface, the capillary pressure can be positive or negative. When the interface is flat, the capillary pressure is zero. When fluids other than oil and water are used, the capillary pressure is usually defined as (2) where pNW is the pressure in the nonwetting fluid and pWET is the pressure in the wetting fluid. pWET is the pressure in the wetting fluid. The radii of curvature of the interface, and hence the capillary pressure, are determined by local pore geometry, wettability, saturation, and saturation history. For most porous media, the equations for the interfacial curvature are much too complicated to be solved analytically, and capillary pressure must be determined experimentally. In these cases, a simple relationship between contact angle and capillary pressure cannot be derived. One geometry where capillary pressure can be calculated as a function of geometry, wettability, and IFT is a capillary tube. Laplace's equation can be used to solve for the capillary pressure as a function of IFT, contact angle, and rt, the radius of the tube. P. 1283

Summary A method is presented for testing enhanced oil recovery (EOR) processes in a single well. The method uses a multitracer version of the single-well tracer test (SWTT) for determining residual oil saturation to measure the oil displaced by an EOR slug process. A test was conducted to demonstrate the validity of the method. This test and its results are described. Introduction Piloting an EOR process is both time-consuming and expensive. Conventional pilot tests can take 3 years or more to conduct and cost several million dollars. A single-well test for evaluating tertiary slug processes has been developed that is both faster and less expensive than conventional piloting by at least one order of magnitude. The basis for this method of evaluating tertiary slug processes is the SWTT for measuring residual oil saturation developed by Exxon Production Research Co. The large depth of investigation from the wellbore of the SWTT and the ability to control this investigation depth are unique properties that make the single-well test for evaluating EOR slug processes possible. This single-well test consists of the following steps.Conduct an SWTT to determine the residual oil saturation after waterflooding.Inject a small slug containing an oil recovery chemical to establish an oil saturation profile within the SWTT pore volume (PV) of investigation.Inject a mobility control bank if needed.Inject a brine bank to displace the mobile banked oil from the test area, and recover the inaccessible PV caused by the mobility control bank if one was used.Conduct another SWTT with several different esters, each having different partition coefficients, so that average oil saturations can be measured for different distances from the wellbore. Steps 1 and 5 can be analyzed to determine oil saturation curves as a function of contacted PV and percent oil recovery vs. chemical slug size. These data are very useful in scale-up to larger projects and are not directly available from multiwell pilot tests. Another application of this testing method could be to conduct several tests with different chemical formulations in a given area. This would aid in selecting the best system for a particular field. Conoco Inc. has conducted a 1-acre (4047-m2) pilot test of a surfactant process at the Big Muddy field in Wyoming. Success of that pilot led to expansion of the surfactant process to 90 acres (364 km 2). In April 1979, Conoco ran a single-well surfactant test in conjunction with the surfactant expansion project. This single-well test was conducted to measure residual oil saturation after waterflooding and to determine the potential for evaluating tertiary slug processes by use of the single-well method. The same surfactant formulation used in the pilot test was used in the single-well test to provide a basis for checking the single-well test. This paper discusses theory, design, operation, results, and interpretation of the single-well surfactant test conducted in the Big Muddy field. Theoretical Development The theoretical basis and the general technique for measuring residual oil saturation by the single-well tracer method are well documented in the literature. Briefly, the method relies on determination of the chromatographic retardation factor of a tracer, which partitions between the oil and water phases in the reservoir. In practice, this determination is made by injecting a slug of primary tracer, such as an organic ester (having solubility in both water and oil), followed by a relatively large volume of water. A shut-in period then follows, during which the ester partially hydrolyzes to form an alcohol (having essentially no solubility in oil); this is the secondary tracer. JPT P. 1887^

The oil/water transition zone, particularly pronounced in low-permeability formations with small pore diameters and high capillary pressure, contains a substantial portion of original oil in place. The capillary pressure curves provide essential data for the calculation of the original oil in place as well as the oilfield development simulation. However, the traditional single capillary pressure curve cannot provide enough information. To address this challenge, an experimental investigation was conducted to explore the capillary pressure diagrams within the oil/water transition zone of low-permeability reservoirs. The results shed light on the complex behavior of capillary pressure, the influence of initial water saturation, and the relationship between initial oil saturation and residual oil saturation. Incorporating the behavior of capillary pressure into reservoir simulation models can enhance reservoir characterization and improve the accuracy of oil production performance in low-permeability reservoirs.

In order to determine the residual oil saturations in two sandstone reservoirs that were considered for tertiary oil recovery projects, test wells were drilled and the projects, test wells were drilled and the reservoirs were cored and logged. Both oil fields are located in South Central Illinois, and they had been under waterflood for about ten years. In one case the reservoir was cored by a special pressure core barrel that was developed by Esso Production Research laboratory; this same well was logged by an electric log and by a neutron decay time log. The oil saturations measured in the water swept areas of these two reservoirs ranged from 6% to 26% of the pore space. Introduction Material balance calculations show that many millions of barrels of potentially recoverable tertiary reserves are in Aux Vases sand reservoirs in the Illinois Basin. These reserve calculations are based on a residual Oil saturation equal to about 25 percent of the pore volume after waterflooding. Aux Vases sands are more uniform than most reservoir sands that we have studied, but interbedding of small gray shale laminations and variations in carbonate cementing material has caused heterogeneities. This heterogeneity and also the well locations affect the flow of fluids during primary and secondary recovery operations. It is possible that a large portion of the residual oil is retained in the periphery of these reservoirs and outside the well patterns; however, we are primarily interested in the residual oil that remains in areas between wells. We should be able to move this oil by miscible displacement, but we need to determine if this can be done economically, and the economics depends to a great extent on the oil saturation in the swept areas. In this paper we describe our methods for evaluating two Aux Vases sand reservoirs before selecting a test site for a tertiary recovery process. We were interested in finding a test process. We were interested in finding a test area in the Aux Vases reservoir that contained a typical residual oil saturation so that a tertiary recovery process could be applied to other similar areas. We used three common basic methods for determining oil saturations in the two areas.

The special techniques described here appear to be promising for determining precise quantitative residual oil saturations - under certain reservoir conditions. A field test of one method was encouraging. The PNC logs showed saturations that agreed with other measurements, and the degree of uncertainty in the estimates approached theoretical expectations. Purpose and Scope The basic physical principles of pulsed neutron capture (PNC) logging and descriptions of logging instrumentation and operation have been documented in earlier publications.3,4 In addition, several methods of PNC data interpretation for petroleum engineering applications have appeared in the literature.6 These latter reports demonstrate that PNC logging has become a valuable technique for formation evaluation. The most significant use of PNC logging has been to discriminate among gas-bearing, oil-bearing, and salt-water-bearing formations in cased holes. For example, gas-oil, gas-water, and oil-water contacts have been found and followed. Unsuspected hydrocarbon migration between zones also has been detected. In addition, water saturations have been calculated from PNC log data when porosity, rock type, formation hydrocarbon type, and formation water salinity were known or could be estimated. Interpretations of PNC log data are often precise enough for decisions regarding recompletion or for a qualitative assessment of reservoir mechanism and performance. But how useful are these data when we must decide whether or not to conduct a tertiary recovery project in the flooded-out portion of a reservoir? In comparison with waterflooding, tertiary recovery is more complicated; thus its performance is harder to predict. Also, the process costs are higher, so there is much less margin for error. Therefore, many of the parameters must be measured with great accuracy for designing a tertiary recovery project. One of the most important parameters is the residual oil saturation - the target for profit. A decision to undertake a tertiary recovery project could depend entirely on the estimate of residual oil saturation and the margin of error associated with the estimate. Minimum expected errors in oil saturation and saturation distribution (among other parameters) are essential for a tertiary recovery project. The purpose of this paper is to describe in some detail the possibility of using PNC data to estimate more precisely the residual oil saturation remaining at the end of a waterflood (either natural or induced).

Experimental studies have been carried out to determine the effects oil injection pressure and rate on formation heating by steam flooding. Heat losses, vertical sweep efficiency, and steam zone volume were determined for steam displacing water at different rates and pressures. A radial flow model was used that consisted of reservoir, overburden, and substratum, all composed of unconsolidated sand. Following are some of the results and conclusions. Heat loss to overburden and substratum, as percent of the total injected, is almost solely a percent of the total injected, is almost solely a function of time for given formation thickness, a conclusion that tends to agree with the theoretical result that percent loss is a function only of dimensionless time at/ 2 (where a is thermal diffusivity, t is time, and h is formation thickness). The volume of the steam zone was found to be a function of time and the dimensionless injection parameter will hkhf (Tb-Ti) (where Lv is parameter will hkhf (Tb-Ti) (where Lv is heat of vaporization, wi is mass injection rate, khf is thermal conductivity, Tb is saturation temperature, and Ti is initial reservoir temperature). Vertical sweep efficiency, defined in the text, depends mostly on injection rate - improving at higher rate - and bas minimal dependence on pressure and time. pressure and time. A few floods were carried out with an initial oil saturation and residual water saturation and using oils with viscosities of 18,100 and 900 cp at initial reservoir temperature. Results arc presented. A radio-frequency capacitance probe was used in some runs in an effort to measure water (liquid) saturation changes in the steam zone. Introduction Reports appearing in the literature on oil recovery by steamflooding now show that almost every aspect of the process has been studied by a variety of methods. Early experimental work 1 by Willman and colleagues demonstrated that steam is an effective oil-displacing agent in a linear flood system; theoretical methods have been developed for calculating the thermal efficiency of reservoir heating by steamflooding; and several field trials have been reported that attempted to test the over-all economics of the process. Shutter, in two papers, published work on a numerical model that includes heat loss, gravity effects, and oil recovery. Reported results of heat flow studies in an experimental steamflood model have shown that a significant portion of the injection heat is contained in the "hot water zone"; i.e., in the flooded formation but outside the steam zone. With gravity override (steam overrunning) much of this heat would be under the steam zone. Gravity override has been observed in steamflood field trials and in Shutler's numerical model. In the experiments described in Ref. 10, gravity override was noted, but was not quantitatively measured. in a new experimental project, using a new model, the pressure range was extended upward to 100 psig. At the same time, more detailed definition of psig. At the same time, more detailed definition of the steam front was obtained, providing a quantitative measure of steam zone volume and gravity override, or vertical sweep efficiency. Model floods were carried out at different pressures between approximately 1 psig and 100 pressures between approximately 1 psig and 100 psig, and at rates between 0.1 and 1.0 lb/min psig, and at rates between 0.1 and 1.0 lb/min (576 and 5,760 lb/D-ft in the 3-in.-thick model formation). In most runs the reservoir was initially saturated with water because such a series of experiments would not be practical to carry out in a reasonable period of time with viscous oil. The results of these runs, which are given in detail in the text, show the effects of pressure and rate on gravity override, steam zone volume, and heat losses under ideal fluid flow conditions. /L few runs were made with an initial oil saturation, using oils with viscosities of 18,100 and 900 cp at initial reservoir temperature. Results with 18- and 100-cp oil differed very little from those with water only; but with the 900-cp oil, gravity override increased and the steam zone pattern became definitely nonradial. This indicates pattern became definitely nonradial. This indicates that the observed pressure and rate effects should be valid for initial oil viscosities up at least 100 cp in a medium as homogeneous as the model. SPEJ P. 274

Two field tests were conducted using the single-well tracer test to measure residual oil saturation. A description of the tests is presented. A dilution effect or production from zones that did not take tracer injection occurred and had to be accounted for in the data analysis. Introduction Residual oil saturation measurements are important in the evaluation of tertiary recovery projects. Reliable values are necessary to evaluate a pilot performance and to determine the potential for commercial tertiary recovery projects. projects. The single-well tracer method to measure residual oil saturation in watered-out formations has been described by Tomich et al. This method has the attractive feature of measuring the residual oil saturation in a relatively large pore volume and involves the following steps:Injecting a bank of water containing a primary tracer, either ethyl acetate or n-propyl formate.Shutting in a well to allow time for some of the primary tracer to react, forming a secondary tracer of primary tracer to react, forming a secondary tracer of ethyl alcohol or n-propyl alcohol.Producing a well and analyzing water samples to determine concentration profiles of the primary and secondary tracers. The separation of the arrival times of the two tracers indicates the residual oil saturation. This separation is caused by different partitioning of the primary and secondary tracers between the oil and water. primary and secondary tracers between the oil and water. The greater the separation between the tracers, the higher the residual oil saturation. Continental Oil Co. has been licensed to conduct Exxon Production Research Co.'s single-well tracer method to determine residual oil saturation since 1973. Residual oil saturations were run at three locations in five different wells. A service company tested two wells at one location, while Conoco Production Research tested at the other sites. Logistic problems of scheduling the tests on short notice and economic considerations caused Conoco to conduct its own tests. Two wells were tested at the Maier lease in the Illinois Basin and one well was tested at the Big Muddy field in Wyoming. Both locations had low rates that limited test size. The Big Muddy is a fresh water reservoir, while salinity of the Maier lease is about 10,000 ppm. There was no appreciable gas production with either test. This paper coversthe details of the field tests conducted solely by Conoco,the determination of the partition coefficients, andthe fitting of the produced partition coefficients, and (3) the fitting of the produced tracer concentrations using Exxon's single-well tracer computer models. Several approaches were made to fit the data from the Big Muddy test because results were complicated by drift and the tracers were diluted by water from zones that did not accept them. Test Design The following items were considered when designing the test.A large test (up to 90 bbl of injection per foot of pay) was desirable. Injection of 50 bbl per foot of pay was pay) was desirable. Injection of 50 bbl per foot of pay was a good design size.The reservoir temperature dictated the selection of the primary tracer. Ethyl acetate was used for the higher temperatures and n-propyl formate for the cooler reservoirs. JPT P. 194

Substantial amount of crude oil remains in the reservoir after primary and secondary production. Chemical flooding is one of the enhanced oil recovery (EOR) methods; however, chemicals (i.e., Surfactant) used are sensitive to the harsh environment characterizing the local reservoirs. The current study aimed at investigating the utilization of ionic liquids (ILs), known as environment friendly salt with good solubility, thermal stability and effective surface activity, as an alternative to conventional organic surfactants in enhanced oil recovery process. In this work, screening tests of nine ILs were performed. These ILs were diluted in different brine solutions of different salt compositions at 10 % (w/w) salinity and their solubility, thermal stability and surface activity in presence of Saudi medium crude oil were tested. Tetra alkyl ammonium sulfate known as Ammoeng 102 was found to be the ionic liquid of choice. Further investigations on Ammoeng 102 solutions at 10 and 20 % (w/w) salinity were conducted and IFT measurements indicate enhanced surface activity of Ammoeng 102 with increasing solution salinity. Effects of pressure and temperature on interfacial tension (IFT) were also tested and the results indicate minor effects. Adsorption test indicates high Ammoeng 102 adsorption tendency with more adsorption for higher salinity solution. Different flooding scenarios were conducted in sandstone rock samples to investigate the effectiveness of Ammoeng 102 IL as an EOR chemical. The findings indicate promising results for ionic solution flooding in secondary mode at irreducible water saturation (S wirr). Ultimate recovery obtained is higher than that obtained with combined secondary brine flooding followed by tertiary ionic solution flooding at residual oil saturation (S or). Injection of slug of ionic solution in secondary mode provides lower recovery compared to that recovered with continuous ionic solution injection in the same mode. Rock water content affects recovery efficiency indicating higher oil recovery for secondary brine and tertiary ionic solution flooding at low S wirr. Contact angle and relative permeability measurements demonstrate the role of wettability alteration behind the extra oil recovery which is very much affected by ionic liquid concentration that can be altered by dilution with formation and injected brines.

WILLMON, G.J., IMPERIAL OIL LTD., EDMONTON, ALTA., CANADA Abstract The Redwater field, Alberta, Canada, discovered by imperial Oil Ltd. in 1948, has now produced approximately 25 percent of the oil originally in place. The present position of the oil-water contact in this strong bottom-water drive pool has been interpreted from borehole contact measurements in observation wells and from an analysis of producing well behavior. Based on this information, and material balance calculations of water influx, the displacement efficiency of the encroaching water is 64 percent. This value has been confirmed by a study of the residual oil and connate water saturations of the two principal rock types in the reservoir. Connate water saturations above the present oil-water contact and residual oil saturations in the water-invaded region were measured directly in cores obtained from the reservoir. in this operation we used a low-invasion, oil-base coring fluid especially developed to minimize flushing of the core by mud filtrate, with a pressure-retaining core barrel to prevent loss of fluids due to depressuring as the core was brought to the surface. Connate water saturations were also determined from conventional oil-base cores and from restored-state capillary pressure tests run at reservoir temperature using reservoir fluids. Introduction The Redwater field (Fig. 1) which is located 35 miles northeast of the City of Edmonton in Alberta, Canada, was discovered in 1948. Development was rapid and by the end of 1951 over 900 wells had been drilled on 40-acre spacing. Most of these wells were completed openhole and generally had productivities in excess of 1,000 B/D following a small acid treatment. Production in Redwater is from the reefal Leduc limestone formation of the Woodbend group which is Upper Devonian in age. The Redwater reef covers an area of some 200,000 acres, but only the eastern or updip portion is productive. This part of the reef may be generally divided into three sections: a fore-reef zone, a biohermal zone in the center of the reef and a back-reef zone (Fig. 2). The fore-reef consists of two types of porosity: a zone of infilled clastics which has poor granular and chalky porosity, and a fragmental zone which has good granular porosity. The algal-biohermal zone has vuggy porosity while the back-reef zone has vuggy as well as some granular and chalky porosity. A detailed geological study of the core material from wells that penetrated the reef section through to the oil-water contact shows that 76 percent of the reservoir is composed of vuggy material which contains 60 percent of the total pore space. The remaining granular material contains 40 percent of the total pore volume. JPT P. 449ˆ

Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5% to 30% OOIP in core flooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil wet or mixed-wet to more water wet conditions. Modeling of wettability alteration experiments, however, are challenging due to the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggests that desorption of acidic oil components from rock surfaces make carbonate rocks more water wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface while cations (Ca2+, Mg2+) decrease the oil surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional un-tuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of over 40% OOIP, while cations such as Ca2+ have a relatively minor effect on recovery (about 5% OOIP). Other physical parameters, including the total surface area of the rock and the diffusion coefficient, control the rate of recovery, however not the final oil recovery. The simulation results further demonstrate that the optimum brine formulation for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios.