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A propane-gas-water miscible-phase displacement process has been in operation on the H. T. Boyd lease, Slaughter field, since May, 1958. The total requirement of 255,416 bbl of liquid propane and 2,625 MMcf of residue gas has been injected. These materials were injected to obtain the high unit displacement efficiency of a miscible process in a portion of the reservoir. This lease is not bounded and the pressure differential created by high injection rates places a limit on the area to be miscibly swept. Water injection is being used to improve the miscible sweep, to displace the oil bank, and to flood portions of the reservoir not miscibly contacted. A total of 4.2-million bbl of water has been injected. The lease performance history indicates the small propane slugs have created a substantial oil bank in the major portion of the reservoir. Considerable test data have been obtained and interpreted to determine the type of displacement in each injection area. These data show that a portion of each injection area has been miscibly swept. There is a wide variation in performance between the areas, and this difference is attributed to permeability stratification. Field data have been used to make required changes in the original plan of operation, and miscible displacement is continuing. The small propane slugs (about 3 per cent of the volume to be miscibly contacted) are expected to sweep at least 18 per cent of the hydrocarbon pore volume. The predicted recovery for this project is 58 per cent of the oil in place. This recovery is about 1.5-million bbl of oil over the predicted waterflood recovery, and it is almost three times the predicted primary recovery.
A combination secondary recovery process has been in operation on the H. T. Boyd lease, Slaughter (San Andres) field, Tex., since May 9, 1958. A propane-gas-water miscible-phase displacement process to be followed by water flooding is being used to increase the ultimate recovery from this lease. The project was designed to take advantage of the desirable features of both processes. The past performance of this project has answered some of the questions concerning the application of the gas-miscible slug process. Considerable test data have been obtained and interpreted to learn bow effective the small propane slugs injected here have been in displacing oil miscibly and to aid in developing plans for the future operation of the lease.
Plan of Operation
The original plan of operation can be described in terms of the type of fluid injected and the type of displacement planned. Step 1-Inject a volume of propane into each injection area to miscibly sweep a portion of the hydrocarbon pore volume. The liquid propane is miscible with the reservoir fluid and efficiently displaces it from the rock. Step 2-Inject a volume of lean hydrocarbon gas, equal to the volume left as residual gas to water flooding in the volume to be swept miscibly. A gas slug is injected to maintain a buffer zone between the propane and the water zone. The gas must be injected at a rate high enough to maintain the miscible-displacement pressure at the gas-propane front. The miscible-displacement pressure for this project is about 1,300 psia. The gas will then miscibly displace the propane slug. Step 3-Inject water at a high pressure to maintain the pressure of the gas-propane boundary at, or above, the miscible-displacement pressure until the planned sweep by miscible displacement is achieved. The water immiscibly displaces the gas slug and increases the sweep efficiency of the miscible phase. Step 4-Continue to inject water to abandonment, but at a lower pressure. This lease is surrounded by other producing wells and the pressure of the gas-propane front must be maintained above 1,300 psia. This is several hundred pounds greater than the offset lease pressures. This limits the area to be swept miscibly by propane-gas-water injection to the central portion of the lease. After the miscible sweep has been completed, water flooding will be used to increase the recovery from the portion of the lease not contacted by the miscible sweep. The area to be swept by water will depend upon the extent of the offset lease cooperation.
Geology and Reservoir Data
The Slaughter field is one of several large San Andres reservoirs in the Permian Basin.
Miscible phase displacement of oil from reservoirs has been emphasized in the past few years. The reason for this emphasis lies in the high oil recovery attainable by this process. Removal of capillary effects in the reservoir leads to recoveries approaching 100 per cent in the area contacted by the miscible phase.
The miscible slug process is one means of obtaining a miscible displacement. Here a band or slug of LPG is injected into the reservoir prior to gas injection. The idea is to maintain the band of LPG "wedged" between the gas and oil phases and thus achieve a miscible phase displacement. A second method for achieving miscibility is through the injection of a gas which is not miscible with the reservoir fluid but which develops a zone of miscibility in the reservoir through mass transfer with the reservoir oil. This mass transfer results in either an enrichment of the lean injected gas by intermediates from the oil or an enrichment of the oil by intermediates from a rich injection gas or one that has been enriched on the surface by LPG addition. We are interested here in discussing the process in which miscibility is developed at the displacement front by the evaporation of intermediates from the oil phase into the gas phase. This process "builds up" its own slug of miscible material at the displacement front and therefore does not require the injection of LPG to obtain miscibility. Each process has its own area of applicability. Generally, the high pressure gas process is applicable only with reservoir fluids which contain a high concentration of intermediates. If the high pressure gas process is technically feasible at pressures less than 4,500 psi, it is probably more desirable economically than the slug process. The slug process has broad applicability in the shallower reservoirs and with reservoir fluids which contain a relatively low concentration of LPG and natural gasoline constituents.
This paper deals with some new concepts of the high pressure gas injection process where it is proposed that flue gas can be substituted for hydrocarbon gas without sacrificing our goal of miscibility.
Wang, Jie (China University of Petroleum, Beijing) | Zhou, Fujian (China University of Petroleum, Beijing) | Fan, Fan (China University of Petroleum, Beijing) | Zhang, Lufeng (China University of Petroleum, Beijing) | Yao, Erdong (China University of Petroleum, Beijing)
ABSTRACT: CO2 finger-channeling seriously affects oil displacement efficiency. It is necessary to research the factors that influence finger-channeling and prevention of finger-channeling in CO2 flooding. In this paper 1) the effects of different gas injection factors on finger-channeling degree in CO2 gas flooding and oil displacement efficiency by slim tube and core displacement experiments are studied, 2) oil-gas interfacial characterization under high temperature and high pressure is analyzed by interface tensiometer, and 3) the inhibitory effect of different gas injection patterns on channeling in heterogeneous reservoirs is compared by heterogeneous core displacement experiments. The results show the finger-channeling degree of CO2 gas drive is lower than that of natural gas flooding oil and has higher displacement efficiency under the same injection pressure. With gas injection pressure increasing, the finger-channeling degree in both CO2 gas drive and natural gas drive decreases while the oil displacement efficiency significantly increases. Oil displacement efficiency influenced by oil/gas ratio, MMP and pressure. According to oil-gas interfacial tension test, with pressure increasing, the extraction effect of injection gas on crude oil is enhanced, the oil-gas interfacial tension decreases, oil and gas properties are closer, which is conducive to suppress finger-channeling. Meanwhile, alternate injection of water and gas is one of the most effective ways to restrain gas drive in heterogeneous reservoirs.
This paper presents the results of a visualization study on the effect of pressure on CO2-foam displacements at pressures above and below the minimum miscibility pressure (MMP). CO2-foam visualization experiments were performed by simultaneous injection of surfactant solution and CO2 into a high-pressure, glass micromodel saturated with Maljamar crude oil. CO2-foam was generated in situ during the simultaneous injection of surfactant solution and CO2. Simultaneous injection of brine and CO2 (WAG) displacements and pure CO2 displacements were also conducted to provide a reference point for the CO2-foam displacements. Results of these displacements were compared to examine the effects of pressure and injection mode on displacement performance and mechanisms. Two different kinds of micromodels were used in this study: modified-layer (MLAY) and modified-heterogeneous (MHET) micromodels. Pressures ranging from 775 to 1320 psia were investigated at a system temperature of 90 F. The surfactant solution used was 1% Alipal CD-128 in a 1% NaCl brine.
Results show that sweep efficiencies were generally lower for pressures below the MMP. However, the effect of pressure on sweep efficiency for CO2-foam displacements was less than for WAG displacements and much less than for pure CO2 displacements. Sweep efficiencies for CO2-foam displacements at pressures just below the MMP were as high as above the MMP. Due to the lower density of injected CO2 near and below the MMP compared to that at higher pressures, the required mass of CO2 was as little as one-third of that required at higher pressures for similar sweep efficiencies using CO2-foam. These observations suggest the economical potential of operating CO2-foam floods at pressures close to and just below the MMP.
In gas floods, a high-pressure gas such as CO2 can mobilize oil effectively if miscibility is achieved by either first contact or multicontact. Sweep efficiency of injected high-pressure CO2, however, can be poor because of the unfavorable mobility ratio, the unfavorable density ratio, and rock heterogeneity. These problems seem to be alleviated by alternating the injection of an aqueous solution of a suitable surfactant with CO2. When CO2 is dispersed within a surfactant solution forming a foam, the mobility of CO2 is lowered, thus improving its sweep efficiency.
Conventionally, CO2 floods are operated at a pressure above the minimum miscibility pressure (MMP). The MMP is defined as the pressure above which a crude oil and an injection gas develop multicontact miscibility; however, the interpretation of the experimental data to determine this pressure varies within the industry. CO2 flood applications are limited because some reservoirs can be operated only at pressures below the MMP. A similar problem is that pressures in portions of many reservoirs are also below the MMP.
This article is a synopsis of paper SPE 62547, "Enhanced Oil Recovery With High-Pressure Nitrogen Injection," by Necmettin Mungan, SPE, Mungan Petroleum Consultants Ltd., originally presented at the 2000 SPE/AAPG Western Regional Meeting, Long Beach, California, 19-23 June.