February 1978 Original manuscript received in Society of Petroleum Engineers office Jan. 14, 1977. Paper accepted for publication Aug. 15, 1977. Revised manuscript received Sept. 21, 1977. Paper (SPE 6387) was presented at the SPE-AIME Permian Basin Oil and Gas Recovery Conference, held in Midland, Tex., March 10-11, 1977. Abstract This paper presents experimental phase behavior data on two CO2-reservoir oil systems at reservoir pressures and temperatures. pressures and temperatures. The data includepressure-composition diagrams with bubble points, dew points, and critical points;vapor-liquid equilibrium compositions and related K values;vapor and liquid densities compared with values calculated by the Redlich-Kwong equation of state;vapor and liquid viscosities compared with predictions by the Lobrenz-Bray-Clark correlation; andinterfacial tensions for six vapor-liquid mixtures compared with values calculated by the Weinaug-Katz parachor equation. These and other published data contribute to development of the generalized correlations needed by reservoir and production engineers for evaluating, designing, and efficiently operating CO2-injection projects. projects Introduction This paper presents experimental phase behavior data for two CO2-reservoir oil systems. These data are used in predicting the performance of CO2 floods with a compositional simulator. The simulator calculates vapor and liquid compositions, densities, viscosities, and interfacial tensions to describe the phase behavior as the injected CO2 advances through phase behavior as the injected CO2 advances through the reservoir. The simulator predictions are used to evaluate proposed projects and to design and efficiently operate approved ones. The data in this paper consist of pressure-composition diagrams with bubble points, pressure-composition diagrams with bubble points, dew points, and critical points; and compositions, densities, viscosities, and interfacial tensions of vapors and liquids in equilibrium in the two-phase region. These data were obtained by the experimental procedure shown in Fig. 1. procedure shown in Fig. 1. We have compared our measured data with values calculated by existing methods: Redlich-Kwong equation for densities, Lohrenz-Bray-Clark correlation for viscosities, and the Weinaug-Katz parachor equation for interfacial tension. We found parachor equation for interfacial tension. We found that these published methods give acceptable agreement in some areas, but in general, they are not satisfactory for engineering purposes. Therefore, we conclude that improved calculation methods are needed for CO2 systems. For the special case of compositional simulator applications, we devised a technique for obtaining satisfactory calculated density, viscosity, and interfacial tension values. This technique is discussed in the section on "Measurements vs Calculations." We believe that our data, along with previously published information and information yet to come, published information and information yet to come, will advance the development of satisfactory correlations, thus reducing the need for extensive laboratory studies of individual systems. PRESSURE-COMPOSITION DIAGRAMS PRESSURE-COMPOSITION DIAGRAMS OIL A Ten mixtures of CO2 and Reservoir Oil A were prepared. These mixtures contained CO2 concentrations prepared. These mixtures contained CO2 concentrations of 0, 20, 40, 55, 60, 65. 70, 75, 80, and 90 mol percent. At 130 degrees F, pressure traverses were made with each mixture. These traverses started in the single-phase region at a pressure above the bubble (or dew) points and lowered the pressure in discrete steps, passing from the single-phase into the two-phase region. At each step, the vapor and liquid volumes were measured. The results are described in Fig. 2A. At 130 degrees F, the critical point of the CO2-Reservoir Oil A system (where intensive properties of the gas and liquid phases were equal) properties of the gas and liquid phases were equal) is 2,570 psia and 60-mol percent CO2. OIL B Eight mixtures of CO2 and Reservoir Oil B also were prepared and studied in the visual cell at 255 degrees F. CO2 concentrations for these mixtures were 0, 20, 40, 55, 65, 75, 80, and 85 mol percent. The pressure was varied from 800 to 6,100 psia, and the pressure was varied from 800 to 6,100 psia, and the relative vapor and liquid volumes measured. The results are given in Fig. 2B. The critical point of the CO2-Reservoir Oil B system at 255 degrees F is 4,890 psia and 74-mol percent CO2. psia and 74-mol percent CO2. SPEJ P. 20

This study presents a new model that describes foam displacement in two layers with differing permeabilities, using three-phase fractional flow theory. Results showed that not only frontal velocities but also saturation profiles should be considered to evaluate diversion process. There are two conditions to be satisfied for successful diversion: (1) the mobility reduction factor should be relatively large in both layers to form piston-like displacements; and (2) the mobility reduction factor of the lowpermeability layer should be relatively smaller than that of the high-permeability layer for displacement front in the low-permeability layer to catch up with that in the high-permeability layer.

An experimental technique is described for isolating the influence of low interfacial tension (IFT) from the influence of other CO2 displacement mechanisms. Also, the capillary number concept was extended to correlate the displacement efficiencies of the CO2-oil systems. Experimental results indicate that low IFT displacement by CO2 is an effective recovery mechanism. Introduction The use of CO2 as an enhanced oil recovery agent in petroleum reservoirs has been investigated both in the laboratory and in the field. Several recovery mechanisms were identified among which those most often considered were: swelling, viscosity reduction, and vaporization and extraction of portions of oil. A CO2 displacement may be either immiscible or miscible portions of oil. A CO2 displacement may be either immiscible or miscible depending on injection gas composition, reservoir oil composition, reservoir temperature, and pressure. The concept of low IFT flooding has been extensively studied for surfactant and micellar enhanced oil recovery processes; however, the literature shows no investigations of the influence of low IFT on CO2 displacement efficiency. During CO2 flooding, low IFT occurs simultaneously with vaporization, swelling, and viscosity reduction, making its influence difficult to isolate. In this paper we discuss an experimental technique designed to isolate low IFT effects. EXPERIMENTAL TECHNIQUE The following procedure was used to isolate the effect of IFT on CO2 displacement efficiency from other CO2 displacement mechanisms:CO2 and reservoir oil were mixed at the desired temperature, pressure, and CO2-to-oil mole ratio.The mixture was brought to equilibrium.Compositions, densities, and viscosities of the equilibrated oil and gas, as well as the IFT between phases were measured. IFT measurements used the pendant drop method.The core was saturated with the equilibrated oil as described below.The equilibrated oil was displaced from the core with equilibrated gas. As the displacing gas and reservoir oil were preequilibrated, their compositions and physical properties, including IFT, remained constant during displacement. Injection rate was also constant. The pressure drop across the core was kept at a minimum to preserve the equilibrium between the displacing gas and the displaced liquid. Each experiment consisted of three stages:Bringing the core to the experimental stage. This included the following operations:saturating the core with brine,measuring permeability to brine, anddisplacing the brine with several volumes of equilibrated oil to a specified irreducible water saturation, Swi.Performing the displacement. The equilibrated gas was injected at a constant rate, and the pressure drop across the core was continuously recorded.

Dulang oilfield is a multistacked sandstone reservoir offshore Peninsular Malaysia with 19 years of production history. Water injection was implemented to supplement the partial water drive. To date, the field recovery factor is approximately 20%, prompting initiatives to increase the recovery. Based on encouraging results from pilot test and simulation studies, immiscible WAG (IWAG) injection was chosen as the recovery strategy in the recently concluded conceptual field redevelopment study. Prior to full-field implementation of IWAG injection, optimization studies were conducted to maximize incremental recovery from IWAG injection with optimal cost. The case study presented in this paper is that of the E10–14 sand unit, which is one of the major producing sands in Dulang field. In conceptual development study, the expected ultimate recovery (EUR) is 163 MMstb or 49% of STOIIP, contributed partly by 14 infill wells and IWAG injection, according to results from 3D compositional simulation studies. This is an incremental of 15% or 50 MMstb over the expected recovery from the existing depletion strategy which is expected to yield 35% recovery. The same 3D reservoir model was then used for further optimization by performing modification sensitivity runs on a restoration program of idle wells, infill well locations and numbers and injection rate parameters. Location of infill wells were selected on the basis of mobile oil saturation at the end of simulation run with well restoration and production enhancement. Additional increase in oil recovery was obtained by focusing on mobilizing remaining oil saturation. This was achieved mainly by tuning the injection rate of WAG injectors located at the flank of the reservoir. Through multiple iterations, 52% (173 MMstb) recovery can be achieved from IWAG injection with only 6 infill wells, a marked reduction from the proposed 17 wells in the conceptual development plan. This represents an incremental recovery of 18%. The performance of edge water injection in Dulang has not been consistent due to operational issues and this has affected the reservoir pressure & oil recovery. However going forward, improved water injection & later optimal WAG injection strategy utilizing existing wells as well as putting in additional drainage and injection points can help increase oil recovery.

To develop reliable design data for glycol contactors, gas-liquid equilibria in the system water-methane-triethylene glycol (TEG) were investigated experimentally. Equilibrium values vary little at the very high TEG concentrations used in modern contactor design, but increase significantly with increasing water concentration in the contacting TEG, and with increasing equilibrium temperature. Various methods of data correlation are described and compared with experimental data. The correlation provides the means for extending the results of this investigation to other pressures and temperatures. Introduction Water removal is a fundamental operation in natural gas processing. Hydrate formation, corrosion, and the formation of liquid water that might separate in the transmission lines are some of the problems caused by an excess of water in the gas. Of the methods available for gas dehydration, water absorption is by far the most generally used. Glycols, especially triethylene glycol (TEG), are the preferred absorbents. A survey of the literature on the water dew point of natural gas over glycol solutions reveals point of natural gas over glycol solutions reveals significant disagreements. A sampling of published dewpoint data for gas in equilibrium with TEG (Fig. 7) illustrates the prevailing confusion. Scant, but still contradictory, information was published for glycol concentrations in excess of 99.8 weight percent. Data in that range are needed in designing percent. Data in that range are needed in designing modern glycol contactors where the water dewpoint temperature must be reduced by more than 100 deg. F. The main reason for discrepancies in experimental results is the difficulty of measuring accurately very small amounts of water in gas. Water is easily adsorbed on the surfaces of experimental apparatus. Normally acceptable data scatter looms large in relation to the low water concentrations that must be measured. Attempts to establish water dew points on the basis of plant performance have been points on the basis of plant performance have been more successful. However, accuracy is limited by the difficulty in establishing the relative contribution of various factors that interrelate in plant operation. plant operation. Faced with these doubts, contactor designers have chosen to provide for TEG circulation rates that are overly high so as to insure more than adequate water removal. Such a practice is undesirable, however, where space and power are at a premium, as on offshore production platforms. Thus, the range of this investigation was governed by the need to extend equilibrium information to the contact temperatures and TEG concentrations necessary m optimize glycol contactors on offshore production platforms. production platforms. New procedures were developed for sampling and analyzing very small concentrations of water in gas and in TEG. To avoid experimental difficulties encountered by previous authors, equilibrium was reached and samples were taken under dynamic conditions. Experimental equilibrium results were smoothed and correlated by several methods. Thermodynamic equations were used to check on the internal consistency of data and to calculate equilibrium constants at conditions outside the range of the investigation itself. The White expression, fitted to the COFRC experimental data, adequately describes the results within the range of temperatures and concentrations studied. DEFINITIONS AND METHODS At water dewpoint temperature, the water contained in a natural gas reaches saturation. Part of that water will condense if the gas is brought to a lower temperature or to a higher pressure. Thus, the "dewpoint temperature" describes the water content of the gas. When dewpoint gas contacts TEG, the water content of the gas decreases. The lower water content corresponds to saturation water at a lower temperature; that is, the dew point will be lower. The initial dewpoint temperature is the contacting temperature. The temperature corresponding to the lowered water content is the equilibrium dewpoint temperature, and the difference between the two temperatures is the dewpoint depression. SPEJ P. 297