Cyclic gas injection processes have been primarily restricted to the use of pure CO2 or CO2 that has been slightly contaminated with reservoir gases. However, it is difficult to employ CO2 in certain circumstances due to transport, economic, or corrosion problems. This paper presents the results of laboratory investigations of the cyclic gas injection process using methane, nitrogen and mixtures of these gases with CO2. Cyclic gas injections were performed at immiscible conditions in consolidated sandstone cores that contained waterflood residual oil. Cyclic CO2 injections were performed under analogous conditions for comparative purposes. Pure methane recovered approximately the same amount of waterflood residual oil as CO2, whereas pure nitrogen recovered about half that amount. Pure CO2 was more mobile in porous media than pure CH4 or N2. Certain CO2/N2 and CO2/CH4 mixtures yielded outstanding results, recovering 2-3 times the waterflood residual oil produced by pure CO2. Maximum recovery was obtained with mixtures containing 10-25% CO2. Introduction Cyclic gas injection is a single-well enhanced oil recovery (EOR) process which involves the injection of a slug of gas into a well. After gas injection, the well is shut-in for a "soak" period to allow time for equilibration. Then, the well is reopened and production is resumed. Cyclic CO2 injection, which is also known as CO2 huff 'n' puff, is the most common cyclic gas injection process. Although the process was originally proposed as an alternative to cyclic steam injection for the recovery of heavy crude, it has primarily been used for the recovery of light oils. Numerous field tests have been performed and the results revealed that the process is economically feasible in diverse reservoir environments. Although field results indicate that cyclic CO2 injection may be successfully implemented under a variety of conditions, application of CO2 processes offshore, and in certain isolated locations onshore, are limited due to CO2 transportation costs. Offshore application of CO2 is additionally restricted due to difficulties in isolating CO2 contamination, and the resulting corrosion. Gases other than CO2 have been employed to a wide extent in full-scale EOR processes that involve well-to-well flooding. The gases that have been used include methane, rich gas, nitrogen, and flue gas. Methane and rich gas are non-corrosive, and are frequently available from production streams. Nitrogen is also non-corrosive, and there are inexpensive procedures available for extraction of nitrogen from air. Flue (or engine exhaust) gas is primarily nitrogen mixed with 10-20% CO2. It is a product of combustion and is generated by combustion facilities such as power plants. Despite the widespread use of these gases in well-to-well processes, only a limited number of reports concerning the use of gases other than CO2 have appeared in the cyclic injection literature. Haines and Monge examined the feasibility of cyclic natural gas injection for the recovery of light oils. The natural gas employed in the study was primarily methane contaminated with less than 2% nitrogen, CO2, and ethane. Coreflood and numerical simulation results indicated that the natural gas injection process was a technically and economically feasible EOR option, and that repressurization and gas relative permeability hysteresis were the most important recovery mechanisms. Shelton and Morris utilized cyclic rich gas injection to improve production rates in viscous oil reservoirs. The rich gas employed in the field tests consisted of methane enriched with propane. P. 95

Laboratory corefloods were performed to investigate the effects of CO2 injection rate, reservoir dip, and the use of a drive gas on the cyclic CO2 stimulation process. Experiments were conducted in 6 foot long Berea sandstone cores using Timbalier Bay, a light oil, under immiscible conditions (500 psig and 78 °F). Process performance was maximized at moderate injection rates. Oil recovery efficiencies and gas utilization factors were poorer at very high or low injection rates. The inclination of the core and the site of injection substantially influenced oil recovery efficiencies and gas utilization factors. Process performance was favored when CO2 was injected into the lower end of a core tilted at a 45 or 90 degree angle. The use of a horizontal core or injection into the top of a tilted core yielded a poorer response. The benefits of a nitrogen drive (or chase) gas were evaluated by comparing the results of injecting CO2 followed by nitrogen with injection of CO2 or nitrogen alone. First cycle injection of a certain mass of CO2 followed by nitrogen yielded over twice as much oil as injection of that mass of CO2 alone. In the second injection cycle, the drive gas experiment recovered over three times as much oil as recovered by CO2 alone.

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This paper presents an analysis technique for characterizing reservoirs from production performance. Unique to this technique is the incorporation of the instantaneous bottomhole flowing pressure (BHFP) to both the production rate and to the cumulative production for a well depleting a reservoir. This allows a single rate/cumulative analysis for wells producing with constant BHFP, constant rate, and wells with variable rate or variable BHFP (including wells with shutins). This solution provides a powerful diagnostic type- curve which can be generated with almost any wellbore/reservoir situation encountered. Extension of the method to gas reservoirs through use of pseudopressure and viscosity- compressibility normalization allows these wells to be analyzed using the slightly-compressible fluid solution. Well performance during transient flow and depletion flow are examined. Simulation results are compared with the analytic solution. The use of spreadsheets to perform well test analysis is also demonstrated. Introduction Recently, decline-curve analysis has expanded to permit engineers to analyze a petroleum reservoir directly in regard to its fluid-flow characteristics and its volumetric extent using rate-time type-curves of the constant terminal pressure solution of the diffusivity equation. This analysis is of enormous value to reservoir managers whose goal is to maximize oil and gas production from a petroleum reservoir. Reservoir extent, continuity, and flow capacity are paramount characteristics that are considered when developing models. that predict reservoir performance while using alternative depletion strategies, such as during fluid-injection projects or enhanced recovery. Reservoir producing conditions to which this technique can be readily applied are those whose actual bottom-hole flowing pressure (BHFP) closely approximates a constant value. Most wells, however, produce with variable BHFP. The work presented here focuses on an alternative rate-cumulative type-curve format whereby variable BHFP is incorporated into dimensionless variables containing both the production rate and the cumulative production providing. a unified approach that can be applied to any reasonable variability in the producing rate or flowing pressure history. The proposed method, with application to single phase and multiphase flow, provides the practicing engineer a better method for decline curve analysis and therefore propagates better reservoir characterization from production data. Pressure Normalization One advancement in decline-curve analysis presented here includes pressure normalization of cumulative production. Like pressure normalization of production rate, variations in bottom-hole flowing pressure (BHFP) are accounted for by dividing cumulative production by the pressure difference between initial and bottom-hole flowing pressures. The technique of combining pressure-normalized production rate (PNR) and pressure-normalized cumulative production (PNO) is an improvement over rate normalization alone in the analysis of reservoirs based on production data. To apply this technique, determination of BHFP from surface-measured flowing-tubing pressure (FTP) is required along with determination of the original static reservoir pressure. Data can then be presented by plotting PNR versus PNO. This technique is then extended for use with gas reservoirs by further incorporating changes in viscosity and compressibility during reservoir depletion. This technique relies heavily on either measured BHFP or FTP. P. 947

Flow behavior studies were conducted to determine if complex organic wastes can be adequately modeled using representative compounds. The complex organic waste used was a sample from the Petro-Processors Superfund Site. The model compound was 1,1,2-trichloroethane (TCA). Waterfloods were performed in uniformly packed sand columns using different flow scenarios. Recovery efficiencies and flow characteristics of the waste sample and TCA were compared. Samples of recovered waste were analyzed for priority pollutants to determine if any components were preferentially recovered by waterflooding. Our studies showed that: the waste displaced water from water-saturated sand more effectively than did TCA, considerably more water-influx (and a longer flow time) was required for the displacement of waste as compared to TCA, and substantially more water effluent was 1105 Copyright © 1995 by Marcel Dekker, Inc. Downloaded by [University of Arizona] at 07:12 03 February 2015 1106 THAKURETAL.collected during the displacement of waste as compared to TCA. Flow differences were attributed to viscosity and mineral wettability effects. Chemical analyses indicated that passage through the sand pack altered the composition of the waste.