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The Hawkins field, located in east Texas, US, contained more than 1.3 billion barrels of original oil in place (OOIP) and 430 Bcf gas in the original gas cap. The reservoir consists of two high-quality sandstone intervals (27% BV porosity and 1- to 3-darcy permeability), the Lewisville and the Dexter; the Dexter, the better-quality sandstone, contains 70% of the oil. The structure caused by a deep-seated salt dome has 1,200 ft of closure and is extensively faulted (see structure map in Fig. 1). The reservoir is divided into two areas separated by a major fault. The eastern area contains 20% of the OOIP and 7% of the original gas cap gas and is underlain by the active Woodbine aquifer that covers much of east Texas. The western area contains the rest of the oil and gas. The western area has a tar mat that varies in thickness from 50 ft on the north to 100 ft on the south. This tar mat impeded aquifer influx until a decline in reservoir pressure resulted in water influx in the north that constituted a strong waterdrive that tilted the gas cap to the south, where aquifer influx did not occur. The average formation dip is 6 to 8°. Oil gravity averages 24.2°API gravity and varies somewhat vertically (21 to 26°API range). Oil viscosity averages about 3.7 cp (with values as high as 15 cp observed near the oil-water contact (OWC) on the east side), and its formation volume factor (FVF) is 1.22 RB/STB.
Fig.1 – Areal view of the Hawkins field. Top of reservoir structure showing major fault patterns.
The 10,000-acre field, discovered in 1940, was developed on 20-acre well spacing. Unitization was completed on 1 January 1975 after 536 × 106 bbl of oil production. Before unitization, oil production was supported by gas-cap expansion and aquifer influx in the east. A small gas injection project was used in the west to stabilize the gas-oil contact (GOC) and to prevent oil migration into the gas cap because of the aquifer influx from the north.
Immiscible gas injection
Extensive laboratory testing was conducted on reservoir core samples to quantify the ability of both water and gas to displace oil. The results of these tests are shown in Table 1. These tests showed that gas was more efficient at displacing oil from the reservoir rock than water and that gas would recover at least 10% pore volume (PV) more oil. From the laboratory data, engineers calculated that, in the field, waterdrive would leave a residual oil saturation of 35% PV, whereas gas drive would leave an average residual oil saturation of 12% PV; the difference results from the lower density difference between the oil and water.
Table 1 - Summary of laboratory test results on Hawkins field core samples
The field was unitized to facilitate the implementation of a gravity drainage project using crestal gas injection. Gas injection began in 1975. Two types of gases were injected. All produced gas, less fuel and shrinkage, was reinjected into the gas cap areas, and beginning in 1977, 120 MMcf/D of flue gas (88% N2, 12% CO2) generated at a nearby plant was also injected. More recently, pure nitrogen from a cryogenic nitrogen rejection plant has been injected.
In 1987, a tertiary immiscible gas-drive process was started in the East Fault Block where the aquifer had invaded a large portion of the oil column. This tertiary process has been called the double displacement process (DDP). In this process, the invading aquifer is being displaced to the original OWC so that the gas-drive gravity drainage process can remobilize much of the waterflood residual oil all the way down to this depth. Although the DDP is working, it is working more slowly than expected because of "higher viscosity oil (note the higher viscosity oil downdip discussed above), significant targeted oil volume found in lower-quality rock (in bypassed-oil zones), and lower-than-expected oil relative permeability."  With the success of the DDP in the east, a similar project was implemented in the west.
Overall Hawkins’ recovery efficiency from the gas-drive mechanism is about 87% in the gas-swept areas or > 20% better than estimated for the waterdrive process. Overall reservoir performance resulting from immiscible gas injection is considered excellent.
- Kuehm, H.G. 1977. Hawkins Inert Gas Plant: Design and Early Operation. Presented at the SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, 9-12 October 1977. SPE-6793-MS. http://dx.doi.org/10.2118/6793-MS
- Carlson, L.O. 1988. Performance of Hawkins Field Unit Under Gas Drive-Pressure Maintenance Operations and Development of an Enhanced Oil Recovery Project. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16–21 April. SPE-17324-MS. http://dx.doi.org/10.2118/17324-MS
- King, R.L., Stiles, J.H. Jr., and Waggoner, J.M. 1970. A Reservoir Study of the Hawkins Woodbine Field. Presented at the 1970 SPE Annual Meeting, Houston, 4–7 October 1970. SPE-2972-MS. http://dx.doi.org/10.2118/2972-MS
- Langenberg, M.A., Henry, D.M., and Chlebana, M.R. 1995. Performance and Expansion Plans for the Double-Displacement Process in the Hawkins Field Unit. SPE Res Eng 10 (4): 301-308. SPE-28603-PA. http://dx.doi.org/10.2118/28603-PA
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