Summary Field experience in 28 Texas CO2 huff ‘n’ puff projects is presented and discussed. In the absence of mechanical problems, CO2 huff presented and discussed. In the absence of mechanical problems, CO2 huff ‘n’ puff can recover oil from 23- to 30 degrees API [0.92- to 0.88-g/cm3] Texas gulf coast Miocene reservoirs. Shorter soak times (10 to 17 days) recovered as much oil, or more, as longer soak times for 2- to 3-cp [2- to 3-mPas] crudes. Injection of larger volumes of CO2 (8 MMscf [230 × 10(3) m3] instead of 4 MMscf [110 × 10(3) m3]) resulted in greater incremental oil recovery of a 33-cp [33-mPas] crude. Oil-cut response can guide in the selection of wells to receive multiple cycles of CO2. Two simple predictive methods are presented for estimating incremental oil recovery from CO2 huff ‘n’ puff. One is from the literature and the other was developed for the Texas reservoirs, where oil swelling and viscosity reduction are important oil recovery mechanisms. Although predictions from both methods show modest agreement with field production, predictions from both methods show modest agreement with field production, the method developed specifically for the Texas cases has the advantage of being based only on fluid properties, which are easy to measure or to estimate accurately. Introduction Although most of today's CO2 EOR projects involve large-scale continuous injection of CO2 solvent, there is increasing interest in cyclic CO2 injection into single wells. Typically, the rapid injection of CO2 (or CO2/hydrocarbon blends) is followed by a shutin period. The well is then returned to production and the response monitored. In reservoirs with poor interwell communication, this single-well approach may afford the only means of recovering tertiary oil by a CO2 process. In reservoirs where interwell communication is not a problem, CO2 huff ‘n’ puff offers a fast, inexpensive alternative to traditional EOR methods. The engineer faced with designing a CO2 huff ‘n’ puff project can find only a limited amount of prior experience in the literature. Laboratory studies in two different 14 degrees API [0.97-g/cm3] crudes have indicated that CO2 huff ‘n’ puff will recover oil. The addition of nitrogen or methane as contaminants to the CO2 is not desirable because it reduces oil recovery. The optimum number of cycles is reported to be two or three, judging from field experience in Arkansas and a simulation study of California crudes. Bottomwater reservoirs and vertical fractures through which CO2 migration can occur should be avoided. Numerical simulation has been used to design and to interpret projects. This is appropriate but is cost-effective only for large projects. This is appropriate but is cost-effective only for large projects. Low-cost predictive methods based on minimal input data projects. Low-cost predictive methods based on minimal input data are more suitable for the small field with a brief project life. To increase our data base of field experience, this paper presents the results of 28 Texas wells stimulated by CO2 huff ‘n’ puff. The effects of reservoir parameters and design variables are discussed. Two simple predictive methods, one developed by Patton et al. and the other developed by us, will be evaluated.
The characterization of surfactant candidates for a given reservoir can be improved by the use of linear coreflood residual-oil-saturation profiles measured along the core after chemical flooding. A surfactant formulation's functional relation of oil recovery to slug size can be calculated from a single coreflood with the assumption of a relaxed scaling law. A volumetric linear scaling approach is developed from laboratory coreflood data. Residual-oil-saturation profiles measured in reservoir material with a microwave absorption instrument support this approximate scaling relation. Analysis of 32 linear surfactant-slug corefloods is presented as additional verification. The limits of this scaling law are defined, with emphasis on the role of mixing and dispersion. The procedure for using saturation profiles to calculate oil recovery as a function of slug size is developed and a test case is presented. A recovery relation derived from a single coreflood saturation profile is compared with that determined by multiple conventional corefloods. Introduction Many techniques and instruments are now available for noninvasive measurement of oil/brine saturations along linear cores during secondary and tertiary displacement experiments, these are reviewed briefly in Ref. 1. The most popular recent method is based on the microwave absorption properties of water. Such saturation- profile measurements provide much more information on a given chemical-flood experiment than can be collected merely from effluent material balance. This abundance of data can be used in two ways: to determine relations that would otherwise have to be developed laboriously from many separate conventional corefloods and to develop predictive capability for estimating surfactant- flood performance in new situations. Both applications are possible as an outgrowth of the concept of volumetric linear scaling for chemical flooding proposed by Parsons and Jones. This relaxed scaling technique is supported by the data of Ref. 6 and a wide variety of conventional and scanned corefloods presented in this work. A process can be defined as volumetrically linearly scalable if the fluid compositions and saturations at any point in the matrix at any time are functions only of the PV of fluids injected relative to that point with respect to the injection point. This can be stated simply for a single slug of surfactant: a given-PV slug of surfactant will produce the same compositions and saturation distributions in a core of any physical shape and size. Moreover, a 0. 10-PV slug injected into a 2-m core will produce the same composition and saturation distribution in the first meter of that core as would be produced over the entire length of a 1-m core that had seen a 0.20-PV slug. This is a trivial-but not an obvious-view of the recovery process. Limitations to this relative-sizing concept are discussed in the following paragraph. SPEJ P. 511^
A laboratory quarter five-spot pattern chemical flood was conducted in a consolidated, homogeneous porous matrix for comparison with standard linear core floods. In addition to the routine material balance information, quantitative areal oil saturation isometric and contour plots were obtained from microwave attenuation measurements made during the flood. The microwave instrument provides the actual observation of oil banking and movement in a laboratory pattern chemi ca 1 flood.Pattern fl ood oil banki ng characteri st i cs are compared wi th those observed in linear floods.A volumetric linear scaling approach was used to predi ct the behavi or of the pattern chem; ca 1 flood from linear flood data. First, a stream tube model was assumed for the quarter five-spot flow pattern. The oil saturation distribution in each tube was computed from scaled linear core flood oil saturation distributions obtained by microwave attenuation. Details of this procedure are given. The comparison between predicted and observed pattern flood behavi or is most encouragi ng. The average tertiary residual oil saturation and the tertiary oi 1 breakthrough time were very accurately predicted. The observed tertiary S contours in the or pattern flood did show slightly more cusping toward the producer than predicted by the simple model. An i nterpretat i on of the pattern fl ood response is proposed in terms of the scaling theory, its assumptions and its limitations.
The concept of volumetric linear scaling was developed to provide a simple oil recovery prediction procedure that adequately described the important aspects of chemical flooding for single and multiple slug systems. This approach has been used successfully to model several chemical flood systems in both field cores and synthetic rock.1,2 When coupled with a flow description, linear flood oil saturation data have also been used to predict oil recovery performance of laboratory pattern floods.3,4 This simple scaling approach will be used here to describe chemical flood performance in a novel unconfined laboratory flood monitored by a microwave saturation scanner. An unconfined two-well geometry was chosen for study because it provided a severe test of the simple streamtube flow description employed. A two-well pattern also represents the simplest of the class of small isolated patterns sometimes employed in field pilot tests. Interpretation and modeling of these isolated patterns has historically been difficult. Extension of the scaling theory to a two-well pattern would provide the engineer with another tool for analysis of such floods. Ten curvilinear unit mobility streamtubes were employed to describe flow in the laboratory experiment. Predictions of 2-propanol saturations measured during miscible injections in the two-well model were compared to observations to check the validity of the streamtube net. Expected effects of the two-well geometry on oil recovery from the laboratory model are discussed in light of the large variation in size of the individual streamtubes in the flow description. Oil saturation profiles were measured during a linear chemical flood involving injection of a small surfactant slug followed by a small polymer slug and continuous drive brine. These So profiles were then scaled along the unit mobility streamtube net. Oil saturation contours, endpoint conditions, oil breakthrough time, and oil production history predictions were made. Comparison of these predictions to the observed performance of the eight day chemical flood carried out in the large two-well model indicate that the scaling concept can be used to model this type of flood. The fixed streamtube description served as a useful first approximation for the unconfined pattern geometry even in the presence of observable crossflow between stream-tubes.
of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. ABSTRACTThe screening and design of chemical flood processes requires an understanding of the effects of each chemi ca 1 slug on oil recovery. The concept of volumetric linear scaling can be extended to processes involving the injection of multiple chemical slugs as long as the relative ratios of slug sizes are held constant. This allows fast development of the relation between oil recovery and slug size requirements for each chemical injected based on only a fe~1 laboratory linear floods.
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