Foams are used for mobility control in enhanced oil recovery operations. However, a typical oil-field application of foam suffers from such problems as early CO 2 breakthrough, poor sweep efficiency, and inefficient oil recovery due to viscous fingering resulting from a low gas-phase viscosity and an unfavorable mobility ratio. The objective of this experimental investigation was to study the use of additives to enhance foam properties and to improve the in situ generation of foams for enhancing the gas-flood sweep efficiency. Foam generation was achieved by flowing nitrogen, surfactant, and various foam-enhancing additives through a sandpack. Some of the parameters affecting the foam performance were the polymer concentration, type of surfactants and their concentrations, aqueous-phase salinity and pH, and effect of flow rate (or shear rate). The performance of polymer-enhanced foams (PEFs) was much better than that of conventional foams. Poly(acrylamide) polymers were used as an additive. Higher foam resistance and longer foam persistence were achieved by using relatively low concentrations of polymers. The studies also showed that the foam performance was significantly improved over a broad range of polymer concentrations. A number of other investigators have shown that foams are severely affected in the presence of oil. This is especially true of lighter or less viscous oils, and the destabilizing effect is magnified with a higher salinity aqueous phase. PEFs with a low-salinity aqueous phase showed improvement in foam stability. The effective viscosities of PEFs were higher than those of conventional foams with a high-salinity aqueous phase and the presence of lighter oils. Further, PEFs reduced the negative impact of oils on foam mobility. Of the surfactants studied, R-olefin sulfonates were found to be stable with high-salinity brines as well as compatible with polymer additives. Other surfactants, including amine oxide surfactants, were also studied and showed unusually high foam resistance and stable properties.
Summary 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. Introduction 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 CO2 addition 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 Bay Unit 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. The Prudhoe Bay field contains approximately 27 × 10(12) scf of natural Prudhoe Bayfield contains approximately 27 × 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 CO2 addition 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 although CO2 with steam increases the rate of recovery significantly, the overallrecovery is dependent on oil viscosity and hence the API gravity. Stone and Malcolm carried out high-pressure steam/CO2 coinjection experiments in a 1D physical 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 CO2 addition to steam for stimulating bitumen-containing hydrocarbon solution gasunder partially depleted reservoir conditions. The study concluded that adding CO2 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 by Clark et al., combustion exhaust gases were injected into a viscous reservoir. Increased oil production rates were attributed to decreased oil viscosity from CO2 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.
Summary This paper presents a method where fluid flow units are used in reservoir description. We developed the proposed method using core and well-log data from the Endicott field on the North Slope of Alaska. Sedimentary intervals of the cored wells are divided into major zones on the basis of core description information. The major zones are further subdivided into subzones to allow less variation in geologic and petrophysical properties within each subzone and more variation between the subzones. On the basis of the transmissibility, storativity, and net- to- gross-thickness data, the subzones are classified into four distinct fluid flow units by use of the statistical method of cluster analysis. We use a regression relationship established between the core and well-log data in the cored wells to estimate the permeability of the uncored wells, allowing for extension of flow units to these wells. We present stratigraphic cross sections to illustrate areal variations of the petrophysical properties in the Endicott field. Introduction Reservoir description is an important step in reservoir evaluation. A thorough description of reservoir heterogeneity leads to an accurate design of a reservoir simulation model and is essential for effective reservoir management. Reservoir heterogeneity is a predominant factor that affects oil recovery, especially during EOR production. Prediction of reservoir production performance is very sensitive to the method used in the representation of the reservoir geology in the simulation model. It is important to pay considerable attention to both the accuracy of the reservoir description and its representation in the simulation model. The prediction of reservoir performance depends, to a great extent, on the technique used to subdivide the production interval into subunits and on the characterization of these units. These units constitute the base for reservoir description. Thus, an important step in reservoir description is the definition of the subunits within the sedimentary interval. Several methods have been proposed for subdividing a sedimentary interval for reservoir description purposes. Using permeability data from a sedimentary interval, Testerman proposed a statistical reservoir "zonation technique" to identify and to describe naturally occurring zones in a reservoir. First, the interval was divided into two zones and then divided into three zones. The subdivision into additional zones continued until the zones had minimum variation in permeability internally and maximum variation between zones. Cant proposed the "slice technique" in which a sedimentary interval is subdivided into arbitrary slices, either of constant thickness or of thickness proportional to the thickness of the entire interval. Earlier, Bishop had described the slices of an arbitrary thickness within a rock body as "operationally defined units." The limitation of this technique is that the arbitrary selection of slices may cut across facies and depositional units. Cant also presented the "sequence analysis" technique in which the distinctive log patterns, such as the fining- or coarsening-upward sequences commonly observed in gamma ray logs, are recognized and correlated from well to well over a wide area. However, the application of the sequence analysis method is limited because the sequences may cut across the lithologic boundaries.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission. A .l Data from capillary pressure experiments 88 A .2 Core # 1 1.0 cc/m in drainage displacement data 89 A.3 Core # 1 0.5 cc/m in drainage displacement data 91 A.4 Core # 2 2.0 cc/m in drainage displacement data 93 A .5 Core # 3 0.2 cc/m in drainage displacement data 95 A .6 Core # 1 1.0 cc/m in Imbibition displacement data 97 A .7 Core # 1 steady-state relative permeability data 99 Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
The feasibility of a pilot production project on the North Slope of Alaska was computed to determine the production potential of a hydrate accumulation. The production of gas from a 1 mile by 4 mile reservoir block containing hydrate underlain by an accumulation of free gas was simulated and the resulting production profiles were analyzed. Results of the simulations indicate that depressurization of the free gas zone reduces the pressure at the gas-hydrate interface below that necessary for hydrate stability and causes the hydrate to dissociate into methane gas and water.
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