Effects of CO2 Addition to Steam on Recovery of West Sak Crude Oil
- M.W. Hornbrook (BP Exploration (Alaska)) | Kaveh Dehghani (U. of Alaska) | Suhail Qadeer (Stanford U.) | R.D. Ostermann (U. of Alaska) | D.O. Ogbe (U. of Alaska)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- August 1991
- Document Type
- Journal Paper
- 278 - 286
- 1991. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.10 Microbial Methods, 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating, 5.6.4 Drillstem/Well Testing, 5.4.6 Thermal Methods, 5.2.1 Phase Behavior and PVT Measurements, 5.4 Enhanced Recovery, 5.4.2 Gas Injection Methods, 4.6 Natural Gas, 5.7.2 Recovery Factors, 5.3.2 Multiphase Flow
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A high-pressure 1D laboratory displacement study evaluated the effects ofadding CO2 to steam on the recovery of West Sak crude oil. Results of thelaboratory experiments indicate that the simultaneous injection of CO2 andsteam increases recovery, reduces injection temperatures, and reduces the heatinput required.
A high-pressure 1D laboratory displacement study was undertaken to evaluatethe effects of adding CO2 to steam on the recovery of West Sak crude oil. Inaddition, a run was made below the bubblepoint pressure to assess the effectsof a free-gas phase on steam-flood recovery of West Sak crude. Experiments wereconducted in an unconsolidated sandpack 2 in. in diameter and 4 ft long. Thesandpack was saturated with West Sak crude oil (19.2 degrees API) thatpreviously had been saturated with methane at a bubblepoint pressure of 1,690psig. The volumetric flow rate was held constant pressure of 1,690 psig. Thevolumetric flow rate was held constant to focus the study on the effects of CO2addition to steam. The temperature profile and pressure drop along the lengthof the sandpack were recorded in addition to ultimate recovery and effluentproperties. properties. The West Sak reservoir is on the North Slope of Alaska,about 250 miles north of the Arctic Circle and to the west of the Prudhoe BayUnit in the Kuparuk River Unit. The reservoir is estimated to contain 15 to 25billion STB of crude oil at 16 to 22 degrees API. The presence of a 2,000-ftpermafrost layer and a reservoir depth that ranges from 3,000 to 4,500 ftresults in an average reservoir temperature of 45 to 100 degrees F.Lower-than-expected temperatures for these depths result in a viscous in-situcrude oil. Alaska is also the site of a large reserve of natural gas. ThePrudhoe Bay field contains approximately 27 x 10(12) scf of natural Prudhoe Bayfield contains approximately 27 x 10(12) scf of natural gas that isapproximately 12.5 % CO2. Because of the large reserves of heavy oil and thepotential use of natural gas to generate steam and CO2 as an additive, it wasdecided to study the effects of adding CO2 to steam on recovery of West Sakcrude oil. While a considerable amount of work has been done in the area ofsolvent addition to steam, only a small percentage of this work deals with CO2addition to steam. The reported laboratory work on physical models, thepublished works on numerical studies, and field studies indicate a strongpotential for the success of such a process. process. Laboratory Studies.Pursley conducted experiments on a cylindrical model to investigate the effectof injecting air, methane, or CO2 on steam stimulation. His results show adramatic improvement in the oil/steam ratio as a result of injecting methane orair. He reported that addition of CO2 was somewhat less effective because ofits high solubility in water. Redford studied the effects of adding CO2 andethane to steam in a 3D physical model. His results showed that adding CO2 orethane to steam greatly improves the recovery of Athabasca tar sand over thatrecovered with other additives. Redford attributed the increase in recovery toimproved sweep efficiency, solution-gas drive, swelling, and viscosityreduction. Harding et al. presented results of a physical model study ofsteamflooding with nitrogen and CO2 additives. The tests were conducted in alinear porous medium saturated with a moderately viscous refined oil and water.It was found that the simultaneous injection of the gases with steam resultedin a significant improvement in the ultimate recovery of the crude oil. Briggset al. studied the effects of CO2 and naphtha addition to steam in acylindrical 1D physical simulator with Athabasca tar sand. Their resultsindicate that the use of CO2 with steam improves recovery primarily byproviding additional drive energy on the depletion portion of a cyclic process.Paracha studied the effects of CO2 addition to steam in a 1D physical model on15, 20, and 26 degrees, API oils. On the basis of physical model on 15, 20, and26 degrees, API oils. On the basis of this study, he concluded that althoughCO2 with steam increases the rate of recovery significantly, the overallrecovery is dependent on oil viscosity and hence the API gravity. Stone andMalcolm carried out high-pressure steam/CO2 coinjection experiments in a 1Dphysical model with Athabasca tar sand. The results from the physical modelwere compared with results from a numerical model study. Both models indicatedthat coinjection of CO2 and steam increases ultimate recovery. Frauenfeld etal. conducted physical model experiments to study the effects of coinjection ofsteam and CO2 into "dead" heavy oil and into an oil saturated withmethane. For "dead" oils, the coinjection of CO2 With steam improvedoil recovery. When the oil was saturated with methane, however, the coinjectionof CO2 was not beneficial. Most sensitivity studies in these laboratory workson CO2/Steam showed that there is an optimum CO2 concentration where the oilrecovery is maximized.
Numerical Studies. Bader et al. and Fox et al. published comparativesimulation studies of steamdrive and a steam/gasdrive. Results from thesesimulation studies showed that recovery occurred more quickly and theproduction rate history curve peaked about 30% earlier than in the steam case.Claridge and Dietrich used a 3D numerical model to study the effects of CO2addition to steam for stimulating bitumen-containing hydrocarbon solution gasunder partially depleted reservoir conditions. The study concluded that addingCO2 decreased the bitumen recovery expected from the application of steamalone. Leung conducted a numerical simulation study of steam stimulation andsteamflood for simultaneous injection of steam and CO2. For an Athabasca oilsand reservoir, a 36% increase in recovery over steam stimulation was achieved.He also found that in a 3D steamdrive simulation, CO2 injection with steam didnot improve the recovery significantly for a California-type reservoir, wherethe stripping effect of steam was the main recovery mechanism. The injected gaspromoted vertical gravity override, and steam breakthrough occurred slightlyearlier than in the case with steam only. The CO2 was seen to concentrate atthe leading edge of the steam zone.
Field Studies. In one of the early single-well field tests described byClark et al., combustion exhaust gases were injected into a viscous reservoir.Increased oil production rates were attributed to decreased oil viscosity fromCO2 absorption in the crude and to increased reservoir energy from the injectedgases. Shelton and Morris reported results from a field test of a huff 'n' puffprocess where rich gas was used to increase production rates in process whererich gas was used to increase production rates in viscous-oil reservoirs.
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