Berea Cores Research Articles

New Fluosilicic Acid System Removes Deep Clay Damage

Summary Recent models for sandstone acidizing have shown that the secondary reaction of fluosilicic acid (H2SiF6) with clays plays a significant role in the removal of formation damage. The conventional wisdom is that possible precipitation during the secondary reactions can adversely affect treatment success. However, this paper presents laboratory experiments with Berea cores and two Brazilian sandstone cores, as well as with field tests, that show that fluosilicic acid can be injected, by itself, into a sandstone reservoir without causing any damage. In fact, mixtures of fluosilicic acid, with a proper amount of hydrochloric acid (HCl) or an organic acid such as acetic acid (HAc), have been able to improve the performance of two Brazilian water-injection wells by removing clay damage. These two wells, which were injecting 11 and 15 m3/d, respectively, are sustaining injection rates at or above the desired quota of 30 m3/d 5 months after the treatments. The treatments were monitored with a real-time monitoring program, which showed that the skin factor has dropped from about 30/40 to zero. Besides having a lower cost than conventional hydrofluoric acid (HF) mixtures, the main advantage of the new acid system is that it reacts mostly with clays and feldspars, but it almost does not react with quartz. Thus, it can dissolve damage without weakening the rock structure, which makes it suitable for deep damage removal. The low cost of H2SiF6, which is a byproduct of sodium fluoride manufacturing, also makes it a viable option for routine acidizing operations that normally would require the use of an HF acid system.

Mapping of Permeability Damage Around Perforation Tunnels

We have investigated porosity and permeability damage around perforations using a combination of transient analysis and X-ray CT. The method applied allowed us to perform the entire experiments on samples under simulated in-situ stress conditions and to map variations in permeability along the length of the core as well as with radial distance from the perforation. Berea (10.2-cm (4-in.) dia) cores saturated with low-viscosity silicone oil were perforated using conventional-shaped charges (6-g HMX) and API RP43 procedures by using 6.88-MPa (1000-psi) effective stress and 5.16-MPa (750-psi) and 2.61-MPa (350-psi) underbalance. Low-permeability Torrey Buff Sandstone was also perforated using 5.16-MPa (750-psi) underbalance. After sufficiently flowing the perforations, higher-viscosity silicone oil was injected. The movement of fluids was tracked using X-ray CT to measure the local velocity of the viscous fluid front at different locations along the perforation. Results of these tests were compared in terms of permeability and porosity damage. Quantitative analysis on Berea cores show, for the specific charge and test conditions used, that damage extends approximately 2 cm (0.78 in.) from the center of the perforation. Comparison of tests performed with 2.41-MPa (350-psi) and 5.16-MPa (750-psi) underbalance show a clear increase in permeability near the tunnel wall at the higher underbalance. A zone of somewhat-reduced permeability exists at approximately 1.7 cm from the perforation center in the latter case. Porosity profiles calculated show that porosity is almost uniform out from the tunnel and there is no compacted zone near the tunnel wall in liquid-saturated cores. However, there is a high-porosity zone from the tunnel wall out about 2 mm. This may be due to a region of circumferential partings and small cracks that lead to high porosity or due to the possible artifacts discussed in the paper. Qualitative results have also been obtained for a tight sandstone for which underbalance was insufficient to remove debris from the perforation tunnel. CT images reveal that the plugged tunnel acts as a conduit for fluid flow, showing that the plugging material has significantly higher permeability than the surrounding rock.

Permeability Reduction by Treatment With KUSP1 Biopolymer

Summary The application of KUSP1 biopolymer for use in permeability reduction treatments of oil reservoirs was investigated. KUSP1 is a nontoxic polysaccharide that is produced by a bacterium. Alkaline solutions of KUSP1 have low viscosities and can be gelled by different methods. Three methods were examined to gel KUSP1 in porous media. Two of the methods are based on the reduction of pH of alkaline KUSP1 solutions. KUSP1 is soluble in alkali but forms a gel when the pH is lowered to values below 10.8. The first method employed the hydrolysis of an ester to reduce pH and trigger gelation. Gel times on the order of days were observed for KUSP1 solutions that contained the monoethylphthalate (MEP) ester. The performance of the KUSP1-MEP system in treatments of sandpacks, Berea cores, and carbonate field plugs was studied at 25°C. Brine permeabilities were reduced by factors that ranged from 75 to 4,500. Permeability reduction by treatments with the KUSP1-MEP system was stable to brine flow for periods of up to six months. The second method to gel alkaline KUSP1 solutions was based on the chemical interactions with rock material. It was found that interactions with Berea sandstone, Baker dolomite, silica sand-packs, and field core plugs were insufficient to reduce the pH of alkaline KUSP1 solutions to values required for gelation. Alkaline KUSP1 solutions were gelled by the addition of boric acid in the third method. Bulk gelation studies conducted at 25, 45, and 65°C showed that gel times could be regulated up to several days by selection of pH and boric acid concentrations. The gels were more rigid than those produced by pH-reduction methods, indicating a different gelation mechanism. Syneresis was observed and was more pronounced at lower pH values and higher temperatures. The KUSP1-boric acid system reduced brine permeabilities in sandpacks and Berea cores (25, 45°C) by factors that ranged from 50 to 3,300.

Permeability Modification With Sulfomethylated Resorcinol-Formaldehyde Gel System

Summary The effect of various parameters on the gelation of the resorcinol-formaldehyde (RF) system and a newly developed sulfomethylated resorcinol-formaldehyde (SMRF) system was investigated. The SMRF system was more tolerant of salinity, divalent ion content and pH than the RF system. The SMRF system was tested in laboratory core floods conducted at 41°C (106°F) using Berea sandstone cores, Baker dolomite cores and reservoir rock from the Lansing-Kansas City formation. SMRF forms strong and stable gels at temperatures between 25 and 52°C (77 and 126°F) and in the pH range between 5 and 8.0. Gel times are a function of pH, salinity, concentration of the chemical constituents and temperature, and can be controlled by appropriate adjustment of these parameters. Laboratory data describing the characteristics of the SMRF system in beaker tests are presented. The SMRF gel system has a viscosity close to water when the reactants are mixed and is easily injected into porous rock. In core tests, the gel system was injected into short cores and allowed to gel in situ. Permeability to brine after in-situ gelation was determined for each core as well as permeability after several pore volumes of brine injection. The SMRF gel system reduced the permeabilities of Berea and Baker dolomite cores by factors on the order of 10,000. The Lansing-Kansas City reservoir rock was plugged by the gel system. The SMRF gel system is one of a few gel systems that will form a gel in situ in the presence of the strong buffering that occurs when brine is injected into carbonate rock. The SMRF system has potential for treatments of carbonate matrix rock such as that found in the Lansing-Kansas City formations of central Kansas as well as the low-permeability carbonates found in the San Andres formations in west Texas.

Effect of Brine Salinity and Crude-Oil Properties on Oil Recovery and Residual Saturations

SummaryCentrifuge experiments were conducted on Berea cores to measure the drainage and imbibition relative permeabilities in two-and three-phase systems. Three crude oils, Prudhoe Bay and Shell Mars A-1 and A-20 crude were used in our tests. No effect on oil recovery was obtained in the drainage experiments when the crude oil was displaced by air at connate water. However, in the imbibition experiments the oil recovery increased significantly with the salinity of the connate brine. The salinity of the displacing brine had no significant influence on the oil recovery. The relative permeability curves obtained during drainage were also found to be insensitive to the salinity of the brine. However, the imbibition relative permeability curves show strong salinity dependence. A comparison of the two crude oils and a nonpolar mineral oil indicates that the more water-wetting Mars crude oil shows a higher oil relative permeability at the same bond number compared to the mixed-wetting Prudhoe Bay crude oil. The salinity dependence of the residual saturations and the relative permeabilities clearly indicate that the change in wetting properties of the rocks surfaces from water-wet to mixed-wet during the drainage process is an important factor controlling the imbibition relative permeability curves. This suggests that the performance of waterfloods will be strongly affected by the composition of the crude oil and its ability to wet the rock surfaces, the salinity of the connate brine in the reservoir, and the height above the oil/water contact.

Scale-up Methods for Micellar Flooding and their Verification

Abstract Design of micellar floods is largely based on laboratory experiments, which are usually unscaled. This paper describes scaling criteria for the process, derived from the basic flow equations, using Dimensional Analysis and Inspectional Analysis. The derivations are based on three-phase (oleic, emulsion, and aqueous), six-component (oil, water, surfactant, polymer, monovalent ion, and divalent ion) flow in a porous medium. The general scaling criteria were simplified for core floods, and verified by micellar floods in scaled models. Model and prototype were geometrically scaled Berea cores. Prototype performance was predicted using the model results and compared with the actual prototype results. Good agreement was obtained in most cases between the actual and predicted oil production histories, showing the validity of the scale-up. The scaling criteria derived can be used for designing a micellar flood. Implications of partial scaling are discussed for field applications. Introduction Micellar flooding process is one of the proven chemical recovery methods for the tertiary recovery of light oils. The process consists of injecting a micellar solution slug (5 - 10﹪ rock pore volume) and a polymer buffer (40 - 50﹪ pore volume), followed by continuous injection of water (drive water). Micellar solutions are surfactant stabilized oil-water micro-emulsions. Often, they also contain co-surfactants, such as alcohols, for viscosity control, and salts to improve solution properties. Micellar solutions are effective in increasing the Capillary Number, which is crucial for the mobilization and recovery of tertiary Oil(1). Polymer buffer, usually a dilute polymer solution (about 500 ppm), provides mobility control behind the displacement front so that most of the residual oil is mobilized and banked before the drive water dissipates the micellar slug. The process has been evaluated in thirty field tests(2) and was found to be technically successful, having a process efficiency (oil recovered-to-slug volume ratio) of three to four. Recently, Thomas et al.(3) showed that process efficiency can be improved to 12 - 15 through the use of multiple slugs and graded slugs instead of a single micellar slug. Economics of the process remain unattractive, mainly due to the cost of chemicals and the initial capital outlay in the development of the process for a particular field, as well as low oil prices (< $20/bbl). Chemicals that are better adapted to reservoir conditions, and laboratory studies representative of field conditions will improve the economic feasibility of the process. Laboratory results based on scaled model experiments will reduce the risk in extending them to field. Scaling criteria derived for the process were discussed in a previous paper(4). Mathematical Model The micellar flooding process can be described mathematically for simplified situations, e.g., considering the oil (o) to be one component, surfactant (s) another, and water (w), polymer (p), monovalent ions (m), and divalent ions (d) similarly single components. The concentration of a particular component in a given phase is expressed as a mass fraction Cphase, component. Diffusion and dispersion is assumed to occur in the case of surfactant (s), polymer (p), monovalent ions (m), and divalent ions (d). It is assumed that the coordinate axes are oriented in the direction of flow.

Utilization of Polymer Gels, Polymer Enhanced Foams, And Foamed Gels For Improving Reservoir Conformance

Abstract A series of experiments were performed in order to study the applicability of polymer gels, polymer enhanced foams and foamed gels in environments that are relevant to Western Canadian reservoirs. The problem of plugging fractures in tight gas reservoirs was tackled first. Three commercial technologies were evaluated and two gave spectacular results for carbonate core from Western Alberta. The testing experience led to the conclusion that chemical compositions and operating parameters are reservoir specific and need to be developed by the design team. The exercise further demonstrated that the design team should never rely on the service company alone to perform a test. On site viscosity and gelation tests must be performed to ensure that the injected product has the desired properties. This will lead to considerable savings in capital spending. In the second part of this work, a wide variety of surfactants were screened using Berea core, high pressure, moderate temperature and high salinity solutions. Polymer enhanced foams were created in various combinations. The design team had to tackle problems of adsorption versus optimum concentration, compatibility of reagents and presence of oil. Foamed gels are faced with the problem of controlling gelation while maintaining a low cost for chemicals. Introduction The possibility of enhancing reservoir conformance by utilizing polymer gels and aqueous foams have been two areas of significant importance in the petroleum engineering literature for the past twenty-five years. Recently, the idea of combining the two technologies for the same purpose has also been given some consideration. The term Foamed Gels (FGs) and Polymer-Enhanced Foams (PEFs) are used in the literature to describe such combinations of gels and foams. The foam is generated by mixing a gas with a surfactant solution. The gel is created through the in situ cross-linking of a polymer in the presence of a catalytic agent. Foamed gels are simply a polymer cross-linking solution containing a surfactant which is foamed using a gas. A foamed gel can be created by means similar to those used in regular aqueous foam generation. The major difference between foamed gels and aqueous foams is that after some time, the external phase of the foamed gel cross-links thereby greatly enhancing the mechanical stability of the foam system. Aqueous foams, whose interfaces are stabilized by surfactants alone, collapse if surfactant-free water flows through them. Ideally, the polymer gel foaming solution will not gel during the injection of a foam into the porous matrix. Thus, a foamed gel system behaves like a foam during injection; and after gelation, it behaves similarly to a gel. This work deals with testing the applicability of polymer gels and polymer enhanced foams in Canadian oil and gas reservoirs. A series of experiments were conducted to illustrate this potential. Recent Literature A tremendous amount of work has been published on gels, foamed gels and polymer enhanced foams. The following is a brief selection of some recent papers. According to Miller and Fogler(1), foamed gels offer greater control over permeability reduction than do commonly used bulk gels.

Visualization and Measurement of Gas Evolution and Flow of Heavy and Light Oil in Porous Media

Summary In a number of experiments, the efficiency of solution-gas drive for both light and heavy oils was studied. In these experiments a special coreholder was used to visually observe the formation of gas bubbles on the rock surface of a Berea core and the production from the core outlet. The results from all the experiments reveal that the critical gas saturation for three hydrocarbon liquids; 1. a light model oil, 2. an 11-API gravity oil, and 3. a 35-API gravity oil, does not exceed 3%. However, the gas mobility for the heavy oil is very low and for the light model oil very high. Consequently, solution-gas drive for a heavy oil of 11-API gravity is more efficient than for a light oil.

Capillary pressure scanning curves by the micropore membrane technique

Experimental procedures have been developed for capillary pressure hysteresis measurements. Capillary drainage and imbibition bounding curves (complete bounding cycle) and a number of scanning curves have been measured for a water-wet Berea core and an oil-wet reservoir core by the micropore membrane technique. The curves are measured both with stepwise and continuous change of the differential pressure. A continuous and slow change of capillary pressure gives considerable savings in experimental time. Reversibility of scanning curves is observed for the Berea core when the range of saturation reversal is less than 5% and may be explained by a pinning effect. The oil-wet reservoir core, however, exhibits a hysteresis loop even for this small saturation range. For saturation reversals in excess of 5%, the scanning curves for both samples form closed loops that are similar in shape to the bounding loop, i.e., for each sample, all hysteresis loops have the same shape but different sizes. This fact may be used to improve the algorithm for hysteresis modelling.

Microbial Profile Modification With Spores

Summary To overcome the shortcomings of conventional, near-wellbore profile modification methods, a microbial profile modification (MPM) method with spores was investigated. A halotolerant, spore-forming mesophile was isolated and characterized. These biopolymer-producing spores propagate easily in Berea cores with permeabilities more than about 500 md. With a specifically formulated nutrient package, they are readily germinated and produce biofilm, which reduces the permeability of the rock. The depth of penetration and the degree of permeability reduction can be controlled by varying injection schemes.

Impact of Asphaltene Presence in Some Rock Properties

Abstract Several studies have shown that asphaltene precipitation at porous medium level leads to changes in some of its properties, such as wettability and hydraulic conductivity. This work shows the results obtained in a study aimed at assessing the effect of asphaltenes and its occasional precipitation on wettability and permeability of rocks found in Venezuelan oil reservoirs. Fluids and cores from five crude reservoirs having different asphaltene contents and Berea cores plugs were used. Wettability measurements were performed by using a variation of Amott method. Similarly, measurements were effected on cores in which precipitation was induced by n-pentane injection. Permeability reduction was evaluated by carrying out displacements tests before and after the precipitation induction. All cases indicated the presence of changes in wettability. Such changes depend on the specific crude asphaltene content and always tend to an intermediate or preferential oil wettability condition, which does not increase during asphaltene precipitation. Mean hydraulic radius reductions in tests where the precipitation was induced were in the range of 93.3 – 47%, which corresponded to asphaltene retention values of 19 and 3.6 %PV, respectively. These reductions depend on the rock nature and the core properties: permeability, porosity and pore size distribution.

Delayed gelation in corefloods using Cr(III)-malonate as a crosslinker

Flow experiments have been conducted using a hydrolysed polyacrylamide (HPAM) or an acrylamide-AMPS copolymer crosslinked with chromium malonate. Retention of the chemicals prior to gelation has been studied at different temperatures and injection rates. The retention of the polymer was independent of the crosslinker concentration. The two polymers gave different results; the acrylamide-AMPS copolymer showed very low retention; the HPAM gave quite high retention values. At low temperatures, malonate with a ratio 1:3 (CrMa 3) and 1:4 (CrMa 4) protected the chromium against precipitation in Berea cores. At high temperatures, chromium precipitation was observed; retention increased with decreasing injection rate. An excess of malonate has some protecting effects on retention. Reducing the initial pH from 7 to 5 lowered the retention. In quartz sand and Bentheim sandstone the retention of CrMa 3 was very low even at high temperatures; no precipitation was observed before gelation. After a shut-in period, gel formed at pH less than 7 in the sand and the Bentheim cores. However, no gel formed in the Berea cores.

Adsorption VII. Dynamic adsorption of a dual surfactant system onto reservoir cores at seawater salinities

The adsorption of a dual surfactant system of the type nonylphenyl-6-ethoxy-sulfonate (6EOS) and dodecyl-benzene-sulfonate (DDBS) in the mole ratio of 1:1 has been studied by: (a) static adsorption onto kaolinite, (b) nonequilibrium long-term dynamic adsorption on a reservoir core, and (c) dynamic slug injection in a Berea core. The studies were conducted at 70 °C using artificial seawater. The corefloods were performed at residual oil saturation. The static adsorption of the mixture showed that DDBS adsorbed more strongly than 6EOS at surfactant concentration below the CMC. The plateau adsorption appeared to be quite similar, but significantly higher than for pure 6EOS. The long-term dynamic study was conducted by circulating the dual surfactant solution through the core for 16 weeks, and the slug injection was performed by injecting 0.5 PV of the surfactant mixture followed by a xanthan solution. In both cases it appeared to be a selective adsorption until the surfactant mixture, forming the most stable micelles, was obtained. Further adsorption at surfactant concentration above the CMC seems to be governed by a linear relationship between the two surfactants. Possible impacts on surfactant flooding, using dual surfactant mixtures of this type, are discussed.

Asessment of Solvent Extraction Efficiency In Sandstones Using BET Specific Surface Area Measurements

Abstract Cleaning core is standard procedure prior to routine measurement of parameters such as porosity and permeability and before performing special core analyses. It is shown that the cleaning efficiency of different solvents and the degree of cleanliness of a core can be assessed through specific surface area measurement. Berea and Crossfield Cardium sandstone core plugs containing residual Crossfield Cardium oil from-laboratory core floods were extracted with the azeotropic mixture of chloroform/methanol, toluene, and methylene chloride, and the specific surface areas were measured as a function of cleaning time. Solvent cleaning increased the specific surface areas by a factor of three to four in some instances. Chloroform/methanol was found to be the most efficient of the three tested solvents. It is shown that the presence of residual oil may render a drastically reduced specific surface area for a rock, but the specific surface area can be restored to its original value by extraction with chloroform/methanol. The solvent itself does not seem to alter the clay structure within the rock. Introduction It is standard procedure in the petroleum industry to dean core for removal of all reservoir fluids before measuring core properties such as porosity and permeability, or performing laboratory core floods. Cores must also be cleaned before conducting special core analyses such as mercury capillary pressure and surfactant/chemical adsorption measurements. Laboratory resting of cores often requires that the cores first be cleaned of residual fluids and/or contaminants and be restored to the original conditions of wettability that prevail in the reservoir. Despite the importance of core cleaning, there are no generally accepted and convenient methods for choosing the most suitable solvent for any given system, or for assessing the cleanliness of a core. A number of investigators have addressed the subject of core cleaning. As pointed out by Gant and Anderson (1988). it has been usual lab procedure to consider a core for routine core analysis "clean" when the extract from the care is visually clean (API, 1960). However, although certain solvents are effective in removing some hydrocarbon components from the surfaces of the grains, it is known that asphaltenes can be more difficult to remove from cores. Dubey and Waxman (1991) studied the effect of various solvents on asphaltene desorption to evaluate solvent efficiency in core cleaning operations. Solvents are used, not only to remove residual reservoir fluids, but also mud additives introduced during coring (Basan et al.. 1988). Previous studies have demonstrated qualitatively the effectiveness of various solvents and combinations of solvents in cleaning cores (Jennings, 1958; Grist et al., 1975: Basan et al., 1988; Gant and Anderson, 1988; Hirasaki et al., 1990). Jennings (1958) reported that toluene used by itself was ineffective in removing all types of contaminants from core. Grist et al (1975) reported the effects of solvent cleaning on wettability. They concluded that different core cleaning methods can result in differing wetting conditions. They suggested cleaning oil-bearing samples with either alternate toluene/methanol cycles or using the azeotropic solvent mixture chloroform/methanol.

Towards measurement of capillary pressure and relative permeability at representative wettability

Abstract Equipment and experimental methods are presented for simultaneous measurement of capillary pressure and relative permeability, using a modification of the continuous injection method. Initial experiments on Berea core material using laboratory fluids showed that the reproducibility of the measured data is good. Capillary pressure and relative permeability curves measured by our new methods were consistent with previous results. Experiments with a dead reservoir crude demonstrated that wettability changes can be monitored as a function of time. This possibility will be used in future experiments to compare capillary pressure and relative permeability curves under reservoir conditions with those under less severe conditions.

On Some Remarkable Observations of Laboratory Dispersion Using Computed Tomography (CT)

Abstract Fickian dispersion theory is traditionally and routinely used to analyze laboratory dispersive flows. We present evidence, however, that shows laboratory dispersion in Berea sandstone is not Fickian. The Berea mixing zone growth does not grow proportional to the square root of time as required by Fickian theory, rather it grows more nearly proportional to time. Mathematical modeling efforts confirm that this non-Fickian flow behavior is attributed to very small yet significant spatial permeability variations. It is likely that these conclusions apply to other laboratory-scale consolidated rock samples, especially media more heterogeneous than Berea sandstone. This work leads to a deeper understanding of dispersion in porous media. Introduction Dispersion is a well known phenomenon which affects fluid flow in porous media(1). Dispersion is particularly important in oil recovery processes involving fluid injection because it directly affects the efficiency with which the injected fluid displaces and recovers oil(2). Dispersion is also important in slug processes such as miscible and chemical flooding because it directly affects slug dissipation and controls injected fluid requirements(3,4). This work is restricted to a discussion of dispersion in equal-viscosity, equal-density fluid displacements. To study and predict the effects of dispersion, most investigators employ a Fickian dispersion model. By Fickian, we mean a model based on some variation of Fick's first law of diffusion(5). Accordingly, the dispersive flux of a chemical species will depend strongly on its concentration gradient. To describe longitudinal dispersion in uni-directional laboratory displacements, most investigators employ a longitudinal dispersion coefficient which is an active function of molecular diffusion and convective dispersion(6). This type of model dictates that at sufficiently low flow rates, molecular diffusion dominates; conversely at sufficiently high flow rates, molecular diffusion is negligible and convective dispersion dominates. This type of (Fickian) dispersion model is strongly supported by experimental observations in uniform sand or bead packs and has been shown to accurately model the elution history performance(7,8) and mixing zone growth behavior(9,10). This type of model has also been successful at modeling the elution history performance from consolidated cores(11). Despite the successes of Fickian dispersion theory, a complete study validating its applicability to consolidated porous media has not been presented to date. For example, Fickian dispersion theory has not been widely shown to model mixing zone growth in consolidated cores. Fickian dispersion theory has also yielded some persistent inconsistencies when comparing the results of synthetic and consolidated porous media. For example, Fickian dispersion theory yields essentially length-independent dispersivities in synthetic media whereas it predicts strongly length-dependent dispersivities in consolidated media. Fickian dispersion theory also requires the use of empirical constants to account for the apparent greater dispersivities in consolidated media than in synthetic media(6). These observations are a possible sign that Fickian dispersion theory may not be applicable to consolidated media. One purpose of this work is to re-examine the applicability of Fickian dispersion theory to consolidated porous media by analyzing the recent experimental results of Withjack(12). Aided by computed tomography (CT), Withjack performed laser tests in a 91 cm long Berea core and measured tracer fluid

Effect of Oxidation-Reduction Condition on Wettability Alteration

Summary This paper presents results of a laboratory study exploring the effect of the oxidation-reduction (redox) condition on crude-oil adsorption on rock mineral surfaces and consequent wettability alteration. Experiments were performed by aging Berea outcrop and Loudon reservoir sandstones with crude oil under various redox conditions and water saturations. Wettability alterations after aging were evaluated by the U.S. Bureau of Mines (USBM) method and by waterflood tests. The natural, oxidized Berea cores changed from strongly water-wet to mixed-wet conditions when aged at irreducible water saturation. Wettability alteration was greatly reduced when aging experiments were conducted under reduced conditions. The degree of wettability alteration depended on availability and redox state of iron on the mineral surfaces and also on aging time. We suggest two possible mechanisms to explain the role of iron in the wettability-alteration process. Wettability alteration in the water-wet Berea cores was insignificant when the cores were aged at residual oil saturation (ROS). Wettability alteration was also insignificant in the mixed-wettability Loudon reservoir cores, regardless of the water saturation or redox condition used in the aging experiments. We present the implications of these findings on core-handling procedures for wettability preservation.

A Laboratory Investigation of Viscosified CO2 Process

ABSTRACT Supercritical CO2 was thickened using a commercial silicon polymer and toluene as cosolvent. The pressure range for polymer solubility in CO2 was determined, and the viscosity of the thickened CO2 measured. The viscosified CO2, increased by two orders of magnitude in viscosity, was used in corefloods in Berea and carbonate reservoir cores. The oil recovery obtained with the viscous CO2 was compared with the results obtained using neat CO2, WAG(1:1), and CO2 with a cosolvent without a polymer. The results show clearly that oil recovery is enhanced and CO2 breakthrough retarded significantly with viscosified CO2.

Effect of Solvent Viscosity on Miscible Flooding

Summary This paper presents experimental results for tertiary miscible displacements in strongly water-wet Berea cores. Floods with both continuous solvent and simultaneous solvent/water injection were studied at ambient conditions. Three solvent/oil systems are compared: heptane (0.4 cp) displacing mineral oil (6 cp), tagged heptane displacing heptane, and tagged mineral oil displacing an equal-viscosity mineral oil (6 cp). Saturation profiles from microwave absorption measurements and production histories are presented. The experimental results show that the manner in which residual oil is mobilized and propagated depends on solvent/water injection ratio, oleic/water-phase viscosity ratio, and fractional-flow hysteresis.

Impact of Miscible Flooding on Wettability, Relative Permeability, and Oil Recovery

Summary The fluid-flow effects in miscible gas processes were studied in several series of corefloods involving water-wet, intermediate-wet, and oil-wet reservoir systems. Three more series of floods were conducted in Berea cores for the same three crude oils used in the previous set. Each of the coreflood series involved three cycles of water and miscible gasfloods, with each cycle consisting of the steps necessary to cover the range of saturations from connate water to miscible flood residual oil saturation (ROS). The results from these flow tests revealed that the oil/water relative permeabilities, saturations, and oil recoveries can be significantly different from cycle to cycle, indicating alterations in the in-situ wettability caused by miscible flooding. These wettability alterations had a significant positive effect on the miscible flood oil recoveries in the case of intermediate-wet and oil-wet reservoirs, while their influence in a strongly water-wet reservoir was negligible. In some cases, a mixed-wettability condition developed as a result of miscible flooding, resulting in higher subsequent waterflood oil recoveries. The water/oil relative permeability ratios have been used to identify the development of mixed-wettability in cores.