A Laboratory Study of the Effects of CO2 Injection Sequence on Tertiary Oil Recovery

Abstract

Introduction The major reason that CO2 stands out as a fluid displacement agent for enhanced oil recovery is because of the adaptability and relatively low cost of CO2 compared with other chemical flooding agents. CO2 miscible displacement could be achieved for a wide spectrum of reservoir oils through an extraction/vaporization process. Even under immiscible reservoir conditions, incremental oil recovery still can be obtained by simple viscosity reduction and swelling of crude oil. Among other desirable properties of CO2 is its high density. At typical reservoir conditions, CO2 is nearly as heavy as reservoir oil; thus, the problem of overriding common to most gas injecting systems could be minimized greatly.In spite of all the advantages of CO2 process, it inherits the disadvantage of high mobility ratio so that the CO2 has a great tendency to channel through the oil, bypassing much of the oil in the reservoir. To alleviate the difficulties, a technique consisting of alternately injecting small CO2 and water slugs has been applied in field test. The injected water interferes with the flow of CO2 to minimize the chance of premature CO2 breakthrough.Another technique, called "programmed slug," has long been applied in polymer flooding to prevent deleterious effects of viscous fingering. More recently, Claridge has developed a method for designing graded banks for both polymer and miscible flooding. His study indicates that the use of a graded slug often results in improvement of oil recovery and/or economic attractiveness.The purpose of this research project was to provide information on whether or not the change of provide information on whether or not the change of injection sequence of CO2 slugs would affect the recovery of oil from a waterflooded porous medium. The research work involved laboratory displacement tests using various injection schemes at a constant amount of CO2. Experimental Equipment The CO2 flooding experiments were conducted using the Ruska miscibility apparatus. The apparatus consists of a 0.2425-in. (0.616-cm) ID stainless steel tube 59 ft (19.3 m) long. The tube was packed with 80–100 mesh glass beads having a porosity of approximately 35% and a permeability of 13 darcies. The tube was coiled and immersed in a constant temperature bath. The apparatus was equipped with a capillary sight glass operated at the selected experimental pressures and temperatures. This device was positioned downstream of the sand pack to provide visual observations of phase change provide visual observations of phase change throughout the entire experiment. The fluid was injected with a constant-rate metering pump manufactured by Instrumentation Specialties Co. A backpressure regulator was used to maintain the desired pressure in the sandpack system. Experimental Procedure The sandpack first was cleaned with isopropyl alcohol that then was displaced with distilled water followed by Drake No. 10 mineral oil until no water was produced. The oil-saturated sandpack was flooded with 3 PV of distilled water. After the waterflooding, the residual oil saturation was determined by a material-balance calculation.Liquid CO2 was drawn from a CO2 bottle and introduced into a holding coil made of 0.25-in. (0.635-cm) stainless steel tubing. The capacity of the holding coil was known, and the weight of CO2 was determined from the difference in weight before and after the coil was filled with CO2. The coil then was connected to the injection system and a predetermined volume of CO2 was displaced into the predetermined volume of CO2 was displaced into the sandpack at a constant temperature of 100 degrees F (37.8 degrees C). SPEJ P. 278

Optimization of Miscible CO2 Water-Alternating-Gas Injection in the Bakken Formation

“…Two sandstone reservoir core plugs were placed in series inside the Dean−Stark extractor and cleaned with toluene, methanol, and chloroform in sequence to remove hydrocarbons, salts, and clays, respectively. After the two sandstone reservoir core plugs were cleaned and dried, they were assembled in series in a horizontally placed 2.46 C 28 0.43 C 3 1.09 C 29 0.35 C 4 4.55 C 30 0.29 C 5 7.13 C 31 0.28 C 6 9.56 C 32 0.27 C 7 11.73 C 33 0.17 C 8 16.14 C 34 0.17 C 9 5.46 C 35 0.19 C 10 6.07 C 36 0.13 C 11 4.82 C 37 0.12 C 12 4.16 C 38 0.12 C 13 3.67 C 39 0.11 C 14 2.93 C 40 0.11 C 15 2.83 C 41 0.10 C 16 2.19 C 42 0.06 C 17 1.93 C 43 0.06 C 18 1.78 C 44 0.06 C 19 1 coreholder and vacuumed for 24 h. Then the synthetic brine was injected to measure the porosity of the composite reservoir core plugs. Afterward, the synthetic brine was injected at different volume flow rates (q brine = 0.01−0.05 cm 3 /min) to measure the absolute permeability of the composite reservoir core plugs.…”

“…17 Third, the fluid injection sequence is also an important factor in the WAG injection. 11 Therefore, it is required to determine the optimum operating parameters of WAG injection in a given oil reservoir, such as the WAG slug size, WAG slug ratio, and fluid injection sequence of each WAG cycle.…”

The Role of Molecular Diffusion Processes in Tertiary CO2 Flooding

“…[7][8][9][10][11][12][13][14][15][16] In direct contrast, for tertiary recovery experiments where CO 2 is injected into a previously watered-out test core, recoveries of residual oil are observed to be considerably lower, dependent on both flood rate and core length, and different for waterwet and oil-wet systems. [8][9][10][11][12][13][14][15][16][17][18][19][20][21][22] The differences in performance between secondary and tertiary flood experiments are usually explained in terms of the high water saturations present in the tertiary flood experiments and their effect on the microscopic displacement efficiency. 18,22 As a consequence ofthe highly unfavorable mobility ratio for the immiscible CO 2 water displacement, injected CO 2 bypasses considerable volumes of water, leaving high water saturations behind the displacement front in water-wet rock.…”

Miscible CO2 Water-Alternating-Gas (CO2-WAG) Injection in a Tight Oil Formation

“…A total of 59 WAG injection field applications were reviewed by Christensen et al (2001), 24 projects of which were miscible CO 2 -WAG injection. Most CO 2 -WAG injection projects had larger oil RFs than waterflooding projects by at least 5-10%.There are a number of laboratory studies (Wang, 1980;Fatemi and Sohrabi, 2013;Kulkarni and Rao, 2005) and numerical simulations (Spiteri and Juanes, 2006; Fatemi et al, 2012) to examine some key parameters that determine the performance of WAG injection. These parameters include WAG slug size, WAG slug ratio, and fluid injection sequence in each cycle.…”

“…There are a number of laboratory studies (Wang, 1980;Fatemi and Sohrabi, 2013;Kulkarni and Rao, 2005) and numerical simulations (Spiteri and Juanes, 2006; Fatemi et al, 2012) to examine some key parameters that determine the performance of WAG injection. These parameters include WAG slug size, WAG slug ratio, and fluid injection sequence in each cycle.…”