Immiscible CO2 Process for the Salt Creek Field
- C.L. Bargas (Amoco Production Co.) | H.D. Montgomery (Amoco Production Co.) | D.H. Sharp (Amoco Production Co.) | J.L. Vosika (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1992
- Document Type
- Journal Paper
- 397 - 402
- 1992. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 3 Production and Well Operations, 5.4 Enhanced Recovery, 4.2.3 Materials and Corrosion, 2.4.3 Sand/Solids Control, 5.1.1 Exploration, Development, Structural Geology, 5.4.1 Waterflooding, 5.5.8 History Matching, 1.2.3 Rock properties, 2 Well Completion, 5.4.2 Gas Injection Methods, 5.3.2 Multiphase Flow, 5.4.3 Gas Cycling, 5.5 Reservoir Simulation, 4.1.4 Gas Processing, 1.6 Drilling Operations, 5.4.10 Microbial Methods, 4.6 Natural Gas, 4.3.4 Scale
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Summary. An immiscible CO2 flooding process was investigated for use at the Salt Creek field, WY. This proposed process with CO2 slug and 100% carbonated chase water may recover an incremental 8.6% original oil in place (OOIP). However, tertiary recovery of this light crude is sensitive to the reservoir crude composition, temperature, and pressure. Initial studies and simulations led to a proposed process pilot.
An immiscible CO2 slug and carbonated chase water EOR process is being investigated for use at the shallow, light-oil Salt Creek field in Natrona County, WY. Salt Creek currently produces about 9,000 BOPD with a cumulative oil recovery of about 635 million bbl from all horizons.
In an immiscible CO2 process, part of the injected CO2 is absorbed into the reservoir fluids and part forms a free-gas phase in the reservoir. Tertiary recovery of the light crude under this process is sensitive to the reservoir crude composition, process is sensitive to the reservoir crude composition, temperature, and pressure.
Gravity drainage, gas cycling, and localized natural-gas-liquid (NGL) injection have caused significant areal variation in the intermediate hydrocarbon composition in Salt Creek's main producing zone, the Second Wall Creek (WC2). Structural relief of 1,500 ft and 33 years of variable-temperature waterflooding also have caused reservoir temperature variations. Finally, although waterflooding restored the reservoir to near original pressure, local pressures vary, not only with structure, but also with nearby injection and production bottomhole pressures (BHP's).
In general, light-oil recovery improves under an immiscible CO2 process as reservoir pressure increases, reservoir temperature decreases, or the percentage of intermediates in the oil increases. Thus, cooler injected water, increased reservoir pressure, and high grading of process areas on the basis of crude composition should improve tertiary performance in the WC2.
A 17.8-acre immiscible CO2 pilot was designed and could be initiated in the 1990's. If the pilot is successful, implementing this tertiary process should improve field recovery and extend field life.
Salt Creek field is in Natrona County, about 40 miles north of Casper, WY. Light oil at Salt Creek is produced from 10 pays and two domes on a 20-mile-long anticline. The large, northern dome is known as the Salt Creek field 1 and is divided into two producing units. The Salt Creek Light Oil Unit (SCLOU) encompasses the northern two-thirds of this dome and was unitized in 1939. The remainder of the Salt Creek dome was unitized in 1962 as the Salt Creek South Unit. The structure to the south of the Salt Creek dome is best known as Teapot Dome. Fig. 1 shows the location of the field, a WC2 type log, and the structural contours of the WC2 sandstone.
The Salt Creek WC2 is a single, 50- to 100-ft-thick sand body deposited as an offshore barrier bar during Cretaceous time. It is about 1,500 ft deep at the crest and nearly 3,000 ft deep at the water/oil contact (WOC). The reservoir extends over most of the Salt Creek field and contains nearly 20,000 acres above its WOC, including 12,770 acres within the SCLOU. This paper deals only with the WC2 within the SCLOU.
Fig. 2 plots historical SCLOU WC2 production. The initial drive mechanisms were solution gas and gravity drainage. These were augmented later by gas cycling in 1926 and then waterflooding in 1961. SCLOU WC2 oil recovery to date is about 370 million bbl, or 43.5% of the 850 million bbl of OOIP.
After discovery of the WC2 in 1917, field development progressed rapidly, with the drilling of more than 1,100 SCLOU wells within 10 years. In 1918, gas processing began at Salt Creek with a small compression plant that recovered pentanes for sale and supplied residue gas for field and camp use. WC2 production peaked in 1923 at more than 85,000 BOPD and then dropped at a 30% decline rate (Fig. 2).
In 1926, the plant capacity peaked at 65 x 10-6 scf/D and WC2 gas injection began. Plant residue gas first was injected as a conservation measure to save gas for future field operational needs. However, rapid oil response in offset wells led to an expansion of gas injection to aid oil recovery. Fig. 3 shows the various stages of expansion. Butane extraction from the produced gas began in 1943, followed by propane extraction. Gas injection continued until 1971 as a partial pressure-maintenance gas-cycling project.
Beginning in the mid-1920's, unsold SCLOU plant NGL's also were reinjected into the WC2 near the crest. In the 1940's and 1950's, this practice was moved to injectors in the crest and along the west flank. Since 1956, no injection of NGL products into the SCLOU WC2 has occurred.
SCLOU WC2 waterflood operations began in 1961-62 with injection into the crestal area to collapse the gas cap. Later, operations were expanded in segments to form a peripheral waterflood and finally, a five-spot pattern waterflood. Fig. 3 shows the WC2 waterflood expansion phases.
The SCLOU WC2 waterflood oil rate peaked in 1973 and was followed by a steep production decline (Fig. 2). From 1975 to 1985, additional drilling and pattern improvement stabilized production at about 10,000 BOPD but with rising WOR's. Since the 1986 oil price collapse, efforts to improve the cost performance at SCLOU price collapse, efforts to improve the cost performance at SCLOU have resulted in shutting in hundreds of marginal wells and caused WC2 oil production to drop to 7,000 BOPD in May 1991. Ultimate WC2 waterflood recovery should approach 50% OOIP.
To improve SCLOU recovery further, CO2 injection at pressures below the minimum miscibility pressure (MMP) is being evaluated. The proposed procedure entails the injection of a continuous CO2 slug followed by carbonated chase water. The following five factors are identified as important inuniscible CO2 process parameters for this project. parameters for this project. 1. Oil swelling. At average reservoir conditions, CO2 swells WC2 crestal and east flank crude by 12% and 10%, respectively. This improves oil mobility by increasing the oil relative permeability. 2. Viscosity reduction. At average reservoir conditions, the addition Of CO2 reduces the WC2 crestal crude viscosity from 3.1 to 2.0 cp and east flank crude viscosity from 4.1 to 3.0 cp. This lowers the mobility ratio and improves oil mobility and recovery. 3. Trapped gas saturation. CO2 trapped by chase water forces additional trapped oil out of water-wet pore spaces, as noted by several investigators. The magnitude of this effect for Salt Creek has not been quantified.
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