Oil-wet Carbonate Reservoirs Research Articles

Post-Surfactant $$\hbox {CO}_{2}$$ CO 2 Foam/Polymer-Enhanced Foam Flooding for Heavy Oil Recovery: Pore-Scale Visualization in Fractured Micromodel

Carbonate reservoirs hold significant reserves of heavy crude oil that can be recovered by nonthermal processes. Chemical-enhanced oil recovery from oil-wet carbonate reservoirs has focused on the use of surfactants to change wettability and enhance imbibition into the matrix; however, the fractured nature of carbonate formations makes oil recovery a challenging process. Recently, developments in foam/polymer-enhanced foam (PEF) injection for heavy oil recovery application have come about, but the process of PEF for carbonate reservoirs is still not fully understood. This paper introduced a new approach to accessing the heavy oil from fractured carbonate reservoirs. \(\hbox {CO}_{2}\) foam/PEF was used to decrease oil saturation after surfactant flooding. Three types of surfactants (nonionic, anionic, and cationic) were used for both surfactant and foam flooding. A specially designed fractured micromodel representing a porous media system was used to visualize pore-scale phenomena. In addition, the static performances of foam/PEF were analyzed in the presence of heavy crude oil. The results showed that in both static and dynamic studies, the PEF had higher stability than the foam. Nonionic surfactant generated the least stable foam in the presence of crude oil. Surfactant flooding slightly increased the oil recovery from matrix after water injection. This was more evident in the case of cationic surfactant with highest imbibition rate. Observation through this study proved that stable foam/PEF bubbles can significantly push the injected fluid toward untouched parts of the porous media and increased the oil recovery. Due to the liquid viscosity enhancement and bubble stability improvement, the effectiveness of PEF in heavy oil sweep efficiency was much higher than that of conventional foams. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix.

Impact of Sulfate Ions on Wettability Alteration of Oil-Wet Calcite in the Absence and Presence of Cationic Surfactant

The modification of the surface wetting characteristics in fractured oil-wet carbonate reservoirs, by reversing wettability from oil-wet to water-wet, leads to improved oil recovery. However, in order to obtain a successful oil recovery process, it is crucial to understand the active mechanisms of wettability alteration. This study looks at the effect of sulfate ions as one of the most promising wettability influencing ions on the wetting properties of oil-wet calcite; the effect is studied both with and without the presence of cationic surfactant and possible mechanisms of wettability alteration are explored. A number of analytical techniques were utilized to analyze the mineral surface before and after treatment. The study presents a thorough discussion of the influence of sulfate ions in displacing adsorbed carboxylate from the oil-wet surface, both with and without the presence of cationic surfactant are discussed thoroughly. The interaction between sulfate ions and the calcium ions attached to carbox...

Mechanism of calcite wettability alteration by alkyl polyglucoside

Surfactant injection into oil-wet carbonate reservoirs offers a large potential for increased oil recovery due to reservoir wettability alterations. Here, the mechanism of wettability alteration by non-ionic surfactant alkyl polyglucoside (APG) is investigated and compared to that of the cationic surfactant dodecyltrimethylammonium bromide (DTAB). Techniques used include 1H and 13C magic angle spinning NMR, zeta potential, adsorption and contact angle (CA) measurements. APG monomers effectively desorb stearic acid (SA) from an SA treated calcite surface by replacing it at cationic sites on the surface, both above and below the APG critical micelle concentration (CMC). Increased polarization of the APG hydroxyl groups upon interaction with Ca+ sites is a driving force for APG adsorption. CAs show that APG treatment changes wettability to water-wet both below (CA = 66.9°) and above (CA = 77.2°) CMC. An observed sphere-to-rod transition occurring in APG solution above 1 mM is accompanied by a structural transition from half-micelles to patches of partial bilayers at the calcite surface, which further increases APG adsorption and CA (CA = 88.1°). In the presence of SA, adsorption of APG onto calcite is similar to that of DTAB below CMC, while above CMC APG adsorption is 2–3 times higher than DTAB. In absence of SA, DTAB adsorption is negligible. CAs are comparable after APG and DTAB treatment, making APG an interesting candidate for such purposes due to its effectiveness at very low concentrations.

Experimental study of water-based nanofluid alternating gas injection as a novel enhanced oil-recovery method in oil-wet carbonate reservoirs

Water-alternating gas injection (WAG) is a common EOR method used at different reservoirs around the world. In this paper we present a novel method called a nanofluid alternating gas (NWAG) injection to improve the ability of the conventional WAG process for the oil-wet carbonate reservoirs. Different experimental tests of water-alternating gas (WAG), as well as nanofluid alternating gas (NWAG) injection were performed on carbonate core samples saturated with crude oil. SiO2 nanoparticles, with spherical morphology and two different sizes of 11–14 and 30–40 nm, were used to improve the performance of the WAG injection method. The WAG process in the core-flooding experiments was carried out by the injection of gas and SiO2 water-based nanofluids. Also, different characterization investigations, such as interfacial tension and contact angle measurements, were completed to study the nanoparticles effect on the recovery mechanisms.Our experiments showed that nano-silica adsorption on the rock surface changed the wettability of reservoir rock from oil-wet to strongly water-wet. Moreover, nanoparticles were located at the oil/water interface, which leads to a reduction in interfacial tension (IFT) between oil and water. Also, by adding SiO2 nanoparticles to the aqueous phase, the viscosity of the injected fluid was increased. Increasing viscosity and changing wettability affect the viscous and capillary forces and increase the capillary numbers; hence, the recovery is improved. Our tests showed that the dominant mechanism is the wettability alteration. These mechanisms enhanced the oil production from the porous media compared to the conventional WAG process.The results indicated a better recovery factor and efficiency for smaller nanoparticle size.Moreover, the experiments showed higher recovery factor for the core sample with lower permeability in comparison with the other.

Carbonate and sandstone reservoirs wettability improvement without using surfactants for Chemical Enhanced Oil Recovery (C-EOR)

In this paper, we have been proposed the preparation of Silica–MWCNT nanohybrid that can increase the water wettability of carbonate and sandstone reservoirs. Chemical agents such as surfactants have been used as wettability modifiers to increase oil recovery from oil-wet carbonate and sandstone reservoirs. Addition of chemical compounds such as polymers, ionic materials and nanoparticles can improve the effectiveness of the mentioned chemical agents.The effectiveness of nanohybrids without using surfactants has not been reported yet and it is still in its infancy. In this work, the effect of MWCNT–SiO2 nanohybrid-based nanofluids on the wettability alteration of a carbonate and a sandstone reservoir rocks was experimentally studied. Therefore, MWCNT–Silica nanohybrid has been prepared by adding the suitable amount of MWCNT in situ of silica nanostructure preparation. In this research, MWCNT–Silica nanohybrid was prepared with ultrasound assisted sol–gel method and characterized with X-ray diffraction (XRD), Field Emission Scanning Electron Microscopy (FE-SEM) and Transmission Electron Microscopy (TEM). The effect of the related nanofluid on the wettability of carbonate and sandstone rocks was investigated by measuring contact angle and interfacial tension. Results show that the nanofluid could significantly change the water wettability of the mentioned rocks from oil-wet to water-wet condition without using surfactant.

Experimental investigation of SiO2 nanoparticles on enhanced oil recovery of carbonate reservoirs

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents are used as wettability modifiers in carbonate systems; however, the role of Nanoparticles in this field is still in its infancy and consequently has attracted the attention of many researchers in the last decade. In this work, the impact of SiO2 Nanoparticles on the wettability of a carbonate reservoir rock was experimentally studied. The impact of these Nanoparticles on the wettability of carbonate systems is still in its infancy. For this purpose, the effect of Nanofluid’s concentration on wettability and interfacial tension were investigated to determine the optimum concentration of Nanofluid for injection into core samples. The result suggests that a concentration of 4 g/L of Nanofluid could significantly alter the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Moreover, we studied the Nanofluids’ potential in enhanced oil recovery of oil-wet core plugs. The results show that a considerable amount of oil can be recovered right after start of water injection to the aged core plug with Nano fluid.

A Laboratory Investigation into Wettability Alteration of Carbonate Rock by Surfactants: The Effect of Salinity, pH, and Surfactant Concentration

Wettability alteration is an important method for i ncreasing oil recovery from oil-wet carbonate reservoirs. Chemical agents like surfactants are kn own as wettability modifiers in carbonate systems. Oil can be recovered from initially oil-wet carbona te reservoirs by wettability alteration from oil-we t to water-wet condition with adding dilute surfactan t and electrolyte solutions. This paper investigate s the effects of brine concentration, surfactant conc entration, and the pH of injection water on the wettability alteration of carbonate reservoirs by d ifferent class of surfactants. Scanning electron microscopy images verified the formation of surfact ant layer surfaces and the adsorption of surfactant molecules on the rock. The results revealed that TX -100, as a nonionic surfactant, and CTAB, as a cationic surfactant, were better wettability modifi ers than SDS, as an anionic surfactant, for carbona te rocks. At the concentration of 1 wt.% and higher, t he contact angle reduction was approximately unchanged. The results also proved that there was a n optimum salinity for the maximum wettability alteration by surfactants. Increasing the pH of agi ng fluid resulted in better wettability alteration by CTAB, while, in the case of SDS, the wettability al teration was reduced. Acidic conditions had a negligible effect on the wetting behavior of TX-100 .

Influence of New SiO<sub>2</sub> Nanofluids on Surface Wettability and Interfacial Tension Behaviour between Oil-Water Interface in EOR Processes

Fine SiO2 nanosphericals (2-5nm) and new various stable nanofluids including Tween 80, Span 80, Lauric alcohol-3EO, CTAB, SDS and K-Laurate surfactants in water or paraffin based solution were used as new SiO2 nanoproducts in oil recovery. These nanofluids can strongly change oil-wet carbonate reservoir rock to complete water-wet wettability and showed an excellent trend of surface tension (S.T) and IFT (interfacial tension) reduction in comparison with pure water and reference solutions. The CaCO3 plates reservoir was then aged for 2, 5 and 8 days into the 1, 3 and 8% of different concentrations of synthesized SiO2 nanofluids (effect of various concentrations via different aging time). Air/water and n-decane/water contact angles on oil-wet and clean carbonate rock aged in designed SiO2 nanofluids were measured and the pH value as a significant factor estimated. The interesting influence of microwave irradiation on surface tension and IFT including various SiO2 nanofluids was investigated after 12 min which some of the especial nanofluid concentrations showed successful reduction. Our findings indicated the important effect of temperature over decreasing of surface tension and IFT between oil and water interface including SiO2 nanofluids after annealing at 70°C. Therefore, this phenomenon can be significantly capable and valuable in applying of new technology in the fabrication of novel nanofluids in EOR processes and saving source of energy regarding to conventional production.

Effect of surfactant composition on reservoir wettability and scale inhibitor squeeze lifetime in oil wet carbonate reservoir

Abstract In the oil industry, scale inhibitor (SI) squeeze treatment is an established method to prevent deposition of inorganic scales in the wellbore and near wellbore formation. Most scale inhibitor chemicals are water soluble and therefore typically deployed as an aqueous solution. However, most carbonate reservoirs being preferentially oil-wet, SI squeeze treatment could be short lived, because of the competition for adsorption surface between the native oil and the SI. Although several authors studied surfactant activities on reservoir rock and fluid properties in relation to enhanced oil recovery, the literature lacks information on the effect of surfactant based preflush treatment on rock characteristics in relation to SI squeeze lifetime. It is obvious that a proper design of preflush, based on a detailed understanding of rock–fluid properties, could be as important as designing the main treatment (SI) itself. The objective of this study was to develop an understanding of surfactant composition and pH in altering carbonate rock wettability, and its impact on scale inhibitor squeeze performance. A set of carbonate core plugs with oil wet characteristics, crude oil and treatment chemicals (anionic surfactant and SI) were collected from an offshore oilfield. Surfactant preflush compositions with and without alkalis were evaluated for their ability to minimize oil–brine IFT and the extent of rock wettability alteration. A series of coreflood studies were conducted with selected preflush compositions and SI, followed by injecting incompatible brines. SI squeeze lifetimes were determined through observation of core permeability damage. The scale inhibitor and strontium return profile analyzed through ICP-MS studies also validated the onset of permeability damage. The study clearly established a correlation between rock wettability and scale inhibitor lifecycle. Extended SI lifecycle is evidenced in the core with a strongly water wet core and vice versa. The importance of proper preflush design based on rock–fluid characteristics and the role of alkali in changing wettability characteristics, surfactant adsorption and inhibitor lifecycle are discussed with experimental evidence.

Wettability Alteration in Carbonates using Zirconium Oxide Nanofluids: EOR Implications

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents like surfactants are known as wettability modifiers in carbonate systems. However, the effectiveness of these agents can be increased by the addition of chemicals such as polymers, ionic materials, and nanoparticles. The impacts of nanoparticles on the wettability of carbonate systems have not been reported yet, and it is still in its infancy. In this work, the effect of ZrO2-based nanofluids on the wettability alteration of a carbonate reservoir rock was experimentally studied. Several nanofluids were made composed of ZrO2 nanoparticles and mixtures of nonionic surfactants. The effect of nanofluids on the wettability of carbonate samples were investigated by measuring the contact angles, and it was shown that designed nanofluids could significantly change the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Scanning electron microscopy (SEM) images and X-ray Diffraction (XRD) data verify adsorption of nanoparticles on the rock and formation of nanotextured surfaces. Moreover, this paper reports the quick imbibitions of ZrO2 nanofluids into oil-wet core plugs saturated with stock tank oil. The results show that a considerable amount of oil can be quickly recovered by free imbibitions of the nanofluids into the core plugs. A theoretical approach is also presented to explain the wettability alteration by formation of composite nanotextured surfaces.

Whole Core vs. Plugs: Integrating Log and Core Data to Decrease Uncertainty in Petrophysical Interpretation and Oil-In-Place Calculations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137679, “Whole Core vs. Plugs: Integrating Log and Core Data To Decrease Uncertainty in Petrophysical Interpretation and STOIP Calculations,” by S. Serag El Din, SPE, ADCO; M.R. Dernaika, SPE, Weatherford Laboratories; I. Al Hosani, ADCO; L. Hannon, Weatherford Laboratories; S.M. Skjeveland, SPE, University of Stavanger; and M.Z. Kalam, ADCO, prepared for the 2010 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 1–4 November. The paper has not been peer reviewed. Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. The specific types and relative percentages of pores present, and their distribution within the rocks, exert strong control on production and stimulation characteristics of carbonate reservoirs. The effects of heterogeneity on core and log measurements are presented. The challenge is to determine the reliability of applying relatively small-scale properties measured by a log or core to the large-scale reservoir property. Introduction Most sandstone reservoirs are single-porosity systems (i.e., interparticle pores) of relatively uniform (homogeneous) nature. However, most carbonate reservoirs are characterized by multiple-porosity systems. Reservoir heterogeneity results from physical and chemical reorganization processes over time (e.g., compaction, solution, dolomitization, and cementation). Heterogeneity complicates the reservoir-description task, in which reservoir properties (e.g., permeability, porosity, saturation, and rock types) tend to vary as a function of spatial locations in vertical and areal directions. Vertical heterogeneity has shown large effects on sweep efficiencies of waterfloods and conventional gas injection into mixed- to oil-wet carbonate reservoirs. These effects are a result of large variations in permeability between different strata. Permeability and other rock properties can vary along the areal (lateral) direction of the reservoir, which necessitates establishing an accurate and detailed understanding of geological heterogeneities and their effect on petrophysics and reservoir engineering. The effect of rock heterogeneity becomes greater when petrophysical properties are measured at scales ranging from a small trim sample in the laboratory to log measurements in the field. Permeability variation of three orders of magnitude has been reported over a distance of a few centimeters in a carbonate-core plug. In heterogeneous reservoirs, the real challenge is predicting reservoir performance through the acquisition of representative measurements. The challenge would be to reconcile the variability seen in high-resolution (e.g., trim or plug samples) and low-resolution (e.g., wireline logs) measurements and to quantify the technical and physical considerations at the various scales.

Wettability Alteration Mechanism for Oil Recovery from Fractured Carbonate Rocks

Oil can be recovered from fractured, initially oil-wet carbonate reservoirs by wettability alteration with dilute surfactant and electrolyte solutions. The aim of this work is to study the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and identify underlying mechanisms. Contact angles, phase behavior, and interfacial tensions were measured with two oils (a model oil and a field oil) at temperatures up to 90°C. There exists an optimal surfactant concentration for varying salinity and an optimal salinity for varying surfactant concentration at which the wettability alteration on an oil-aged calcite plate is the maximum for anionic surfactants studied. As the salinity increases, the extent of maximum wettability alteration decreases; also the surfactant concentration needed for the maximum wettability alteration decreases. IFT and contact angle were found to have the same optimal salinity for a given concentration of anionic surfactants studied. As the ethoxylation increases in anionic surfactants, the extent of wettability alteration on calcite plates increases. Wettability of oil-aged calcite plates can be altered by divalent ions at a high temperature (90°C and above). Sulfate ions alter wettability to a greater extent in the presence of magnesium and calcium ions than in the absence. A high concentration of calcium ions can alter wettability alone. Magnesium ions alone do not change calcite plate wettability. Wettability alteration increases the oil recovery rate from initially oil-wet Texas Cordova Cream limestone cores by imbibition.

Overview: EOR/IOR (January 2008)

Overview Currently available primary- and secondary-oil-production technologies leave behind two-thirds of the oil in place as stranded oil. However, many analysis and field projects have shown that significant oil-recovery increases are possible with improved/enhanced oil recovery (EOR) by gas injection, thermal recovery, or chemical injection. The first two methods have proved cost-effective even at low oil prices. Current oil prices have created renewed interest in more-costly chemical-based EOR methods such as gel treatment, foam flooding, polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline flooding. This year, we focus on chemical-based EOR methods. Chemical-EOR methods focus on improving the sweep efficiency by correcting reservoir heterogeneity or controlling fluid mobility, or they focus on increasing displacement efficiency by reducing residual-oil saturation. Gel treatment usually is intended to improve sweep efficiency and to reduce excess water production in channeled or fracture-dominated mature reservoirs. A newer trend in gel treatment is to apply preformed gels for in-depth treatments. These gels have been reported to penetrate deeply into superhigh-permeability streaks or fractures and seal or partially seal them off, thus creating high flow resistance in formerly watered-out, high-permeability zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water. Foam flooding often is used to reduce gas mobility and to correct reservoir heterogeneity and increase sweep efficiency for gasflooding. Foam can be injected into the reservoir by coinjection of gas and surfactant solution or by injection of surfactant solution alternating with gas (SAG). Foam stability, surfactant-adsorption reduction, and optimized SAG-process design are the keys to controlling the economics of foam flooding. Polymer flooding is designed to control mobility for waterflooding. High-molecular-weight and new high-temperature salt-resistant polymers have made polymer flooding more economical. Adding either an alkaline or surfactant chemical, or both, in a polymer flood will scour residual oil from the rock, resulting in higher oil recovery than with polymer flooding alone. However, the scale problem associated with alkaline limits the use of ASP flooding. Wettability is of major importance to oil recovery, especially for fractured oil-wet carbonate reservoirs where water flows through the fractures but does not imbibe into the matrix because of negative capillary pressure. The chief concern is to develop cost-effective chemical formulations that change the carbonate wettability from oil-wet to water-wet. EOR/IOR additional reading available at the SPE eLibrary: www.spe.org SPE 107095 "Field-Scale Wettability Modification—The Limitations of Diffusive Surfactant Transport" by W.M. Stoll, SPE, Shell International E&P, et al. SPE 107776 "Improved ASP Design Using Organic-Compound/Surfactant/Polymer for La Salina Field, Maracaibo Lake" by E. Guerra, PDVSA Intevep, et al. SPE 107727 "Polymer Flooding: A Sustainable Enhanced Oil Recovery in the Current Scenario" by Ivonete P. Gonzalez da Silva, Petrobras, et al. SPE 106901 "SAGD Optimization With Air Injection" by J.D.M. Belgrave, EnCana Corporation, et al.

Wettability alteration in carbonates

Abstract Fractured oil-wet carbonate reservoirs are often located at low temperatures and pressures, and the oil recovery by pure pressure depletion is usually low. The potential for improved oil recovery (IOR) is therefore very high. An IOR method is to change the wettability of the reservoir towards more water-wet conditions so that water can spontaneously imbibe into the matrix blocks and expel the oil. This paper focuses on cheap commercial available surfactants of the type R-N(CH 3 ) 3 Cl prepared from fatty acids from the coconut palm, which are able to turn the carbonate water-wet when added to the injection water. Two products were tested: Arquad MC-50 (Arquad) containing a mixture with R=C12 and C14, and Dodigen 5462 (Dodigen) with the composition R=C12, C14, C16, and C18. Imbibition experiments using low-permeability (3 mD) outcrop chalk cores and 100–350 mD dolomite reservoir cores at 40 and 70 °C were performed, both with and without initial water. In general, Arquad was more efficient than Dodigen regarding imbibition rate. Very high oil recovery was obtained, approximately 70% of original oil in place (OOIP) for the chalk cores and ≈90% of OOIP for the dolomite cores. The imbibition mechanism is discussed in relation to the influence of capillary and gravity forces, and the difference in behavior of the two surfactant systems is discussed in terms of critical micelle concentration (CMC) and oil–water interfacial tension (IFT).

An Evaluation of Spontaneous Imbibition of Water into Oil-Wet Carbonate Reservoir Cores Using a Nonionic and a Cationic Surfactant

Some surface-active chemicals are able to improve the spontaneous imbibition of water into oil-wet carbonates. In this work, the oil recovery from oil-wet reservoir cores was compared using aqueous solutions of an ethoxylated alcohol (EA) and a cationic surfactant (C12TAB). The experiments were conducted at room temperature using short (∼5 cm) and long (∼30 cm) cores with initial water saturation in the range of 17−33%. Due to wide variation in porous structure, the cores were characterized into two groups, i.e., moldic and sucrosic. The former cores had more than 25% of the pore volume (PV) related to vugs, and the latter appeared more homogeneous. The permeability of the moldic and sucrosic cores varied between 20 and 180 and 80−350 mD, respectively. In general, the efficiency of C12TAB was superior to EA regarding spontaneous oil expulsion from the cores. For the short core experiments, about 40−45% of original oil in place (OOIP) was recovered using C12TAB, while only 10% was the average recovery usin...

Relative Permeability Studies of Gas-Water Flow Following Solvent Injection in Carbonate Rocks

Abstract Flow studies were conducted of 19 preserved cores from four oil-wetcarbonate reservoirs to provide data for evaluating the water-rich, gas-injection improved recovery process. Results indicate that these cores werewater repellent following displacement of oil by a solvent similar to thereservoir solvent. Restored-state tests of some of the same cores followingcleaning by a polar solvent yielded water-wet flow behavior. These resultsindicate that tests of preserved cores are required if water-gas flow dataapplicable to oil-wet reservoirs are to be obtained. Water-gas relativepermeability data also were obtained from preserved cores following bothcomplete and preserved cores following both complete and incompletedisplacement of oil by solvent. The presence of a small "bypassed" oilsaturation presence of a small "bypassed" oil saturation significantlyincreased the trapped gas saturation and reduced water permeability atflood-out. Use of these data in a mathematical model of the reservoir processgave reduced water injectivities (compared process gave reduced waterinjectivities (compared with those attained during water preinjection) similarto those experienced in the field. Introduction Increased emphasis is being placed on the application of secondary andtertiary recovery processes for increasing oil recoveries from known fields.One of these processes involves the injection of gas that is rich either inlight hydrocarbons or in carbon dioxide. Under appropriate reservoir pressureand temperature conditions, rich-gas injections can develop a solvent zone thatwill miscibly displace the oil it contacts in the reservoir. A dry scavenginggas usually follows the injection of some predetermined volume of the rich gas.Water also may be injected alternately with the rich or dry gas to decrease thegas mobility and, thus, improve reservoir sweep efficiency. Mathematical modelstudies of these recovery processes are made frequently. In the planning stagesof the improved recovery program, the model studies assist in sizing therich-gas volume to be injected and the subsequent dry-gas and water volumes.Once the program has been put into operation, the model may be used to matchfield performance (such as injectivity, pressure, or productivity), diagnoseunexpected problems, and extrapolate the future performance. Relativepermeability data applicable to a reservoir recovery process are a prerequisiteto reliable performance predictions with a mathematical mode. This means thatthe predictions with a mathematical mode. This means that the displacementsequence and mechanisms that occur in the reservoir must be known andreproduced accurately in the laboratory flow test. One important additionalrequirement is the need for reservoir core samples that adequately representthe producing horizon. This paper is concerned with the development of relativepermeability data for application to a recovery process of permeability datafor application to a recovery process of the type just described. Theparticular reservoirs of interest are West Texas carbonates. In thesereservoirs, rich-gas injection is being used as a secondary recovery process.However, water preinjection was necessary to process. However, waterpreinjection was necessary to increase reservoir pressure to a level such thatmiscibility could be achieved between the reservoir oil and the subsequentlyinjected rich gas. Because of this water preinjection, the displacement processis essentially the same as would occur in a tertiary application (that is, after waterflooding). Thus, relative permeability data were obtained forseveral different displacement conditions, selected specifically to model thereservoir process shown schematically in Fig. 1. The stepwise simulation ofthis recovery process in laboratory flow tests is discussed later. Ofparticular interest in this study were the relative permeabilities applicableto the water-displacing-gas process, permeabilities applicable to thewater-displacing-gas process, permeabilities that are needed to model thegas-water injection permeabilities that are needed to model the gas-waterinjection process following solvent displacement of oil. process followingsolvent displacement of oil. SPEJ p. 23