Enhanced Oil Recovery by CO2 Miscible Displacement in the Little Knife Field, Billings County, North Dakota
Authors: Desch John B. , Larsen Wayne K. , Lindsay Robert F. , Nettle Robert L. 
Published: December 2007

Summary
A CO2 minitest involving the miscible displacement process was conducted in the Mission Canyon formation process was conducted in the Mission Canyon formation (lower Mississippian) at Little Knife field, ND. The Mission Canyon is a dolomitized carbonate reservoir at approximately 9,700 to 9,900 ft [2957 to 3018 m] subsurface, which is undergoing primary depletion. Four wells were drilled in an inverted four-spot configuration, covering 5 acres [20 234 m2]. The central well served as the injection well and was surrounded by three nonproducing observation wells. Oriented cores were cut in each well for detailed reservoir characterization and laboratory testing. In addition, a well test program was conducted that involved two pulse tests and program was conducted that involved two pulse tests and injectivity tests on the individual wells. Results from these tests were used to upgrade two reservoir simulation models. Various parameters within the computer models were modified to determine the most efficient injection plan for the specific reservoir characteristics. plan for the specific reservoir characteristics. A water-alternating-gas (WAG) type injection sequence had five alternate slugs of formation water and CO2. Preflush injection began Dec. 11, 1980, followed by the WAG slugs from Jan. 7 to March 25, 1981. Drive water injection began immediately and was completed on Sept. 24, 1981. Injection rates were maintained at 1,150 B/D [183 m3/d] during water injection and 40 ton/D [36 Mg/d] during CO2 injection. Tracers were used during the waterflood preflush and with the water during the WAG. A pressure core behind the flood front was obtained to confirm residual oil saturations in the project interval. Overall rock recovery was excellent, 90%, but sample recovery under reservoir pressure was less than anticipated. Invasion of drilling fluids during coring was checked by introduction of a radioactive tracer into the coring fluid. A compositional simulation model was used to history match the field performance of the CO2 minitest. A detailed reservoir characterization was developed and used in the simulator to match bottomhole pressures, water and CO2 breakthrough times, and fluid saturation histories at the observation wells. The effects of gravity segregation, stratification and crossflow, and reservoir heterogeneity also were investigated. The pattern sweep efficiency for CO2 approached 52% in the minitest area. Displacement efficiency, as indicated by simulation study, was 50% of the oil in place at the start of the project, compared with an efficiency of 37% for waterflood. A total of 3,100 scf CO2/ incremental bbl [558 std m3/incremental m3] of displaced oil were required. The absence of producing wells and only one zone within the Mission Canyon being flooded favorably influenced these figures.

Introduction
Little Knife field is near the central portion of the Williston basin (Fig. 1). The field is isolated within the broad, low lying, northward plunging Little Knife anticline, an anticlinal nose. Closure on the east, north, and west is created by the gentle anticlinal fold, with stratigraphic entrapment forming closure to the south. Production is from dolomitized, porous beds of the Production is from dolomitized, porous beds of the Mission Canyon formation. The reservoir was originally under saturated and had no free-gas saturation. The primary recovery mechanism in the reservoir is fluid primary recovery mechanism in the reservoir is fluid expansion with limited edge water drive. Since discovery in Jan. 1977, to June 1, 1984, the field has produced 31 × 106 bbl [4.47 × 106 m3] oil, 9 × 109 cu ft [1.33 × 109 m3] sour gas (1,380 GOR), and 5.8 × 106 bbl [0.92 × 106 m3] water. Oil gravity is 41 deg. API [0.82 g/cm3] with a viscosity of 0.20 cp [0.0002 Pas] and density of 0.6043 g/mL [604 kg/m3] at a reservoir temperature of 245 deg. F [118 deg. C] (Table 1). The solution GOR is 1,119 scf/STB [199.4 std m3/stock tank m3] with a saturation pressure of 2,698 psia [18 602 kPa]. Minimum miscibility pressure with CO2 is 3,400 psig [23 442 kPa]. Swelling factors of oil/CO2 mixtures is illustrated graphically in Fig. 2. The temperature effect on the hydrocarbon phase behavior in the reservoir was negligible during the minitest. The production wells surrounding the CO2 minitest site were drilled in late 1977 through early 1978 on 160-acre [647.5 × 103-m2] spacing.
JPT
P. 1592