CO2 Huff 'N' Puff has been used on a shallow light oil field to add value to existing oil producing wells by increasing the ultimate oil recovery. Testing was initiated in 1985 with a more continuous program starting in 1989. The application of CO2 Huff 'N' Puff has increased oil production 180,000 bbls above the primary recovery with the use of 210 MMCF (12,200 tons). The CO2 treatments have been relatively small with 390 treatments performed on 240 wells. Introduction The Huff 'n' Puff or Cyclic W2 Process is a type of production well stimulation which involves a) injecting CO2 (either as a gas or a liquid) into a well, b) shutting in the well to allow the CO2 to dissipate and dissolve, and c) producing the well back. While each phase of the process is unique, each phase inter-relates mechanically as well as in the reservoir. Field results, reservoir analysis, and computer simulation and matching, indicate that the primary recovery mechanisms in this immiscible CO2 application appear to be 1) a shift in the CO2 saturated water/oil relative permeability, and 2) the forming of a trapped gas saturation, namely within the water phase, which results in a strong decrease of water relative permeability end point. P. 505^
Summary Gas cyclic-pressure pulsing is an effective improved-oil-recovery (IOR) method in naturally fractured reservoirs. A limited number of studies concerning this method in the literature focus on specific reservoirs, yet the optimum operating conditions have not been broadly investigated. In this study, we present a detailed parametric study of the process from both operational and reservoir perspectives. Incremental oil production, discounted incremental oil production, and net present value (NPV) are considered as the important markers for the performance criteria. The necessary analyses are performed using a single-well, dual-porosity, compositional reservoir model. In the first part of the study, parametric studies are conducted to develop a better understanding of the operational parameters affecting the process performance in the shallow, naturally fractured, and depleted reservoir of Big Andy field in eastern Kentucky, USA. These include analyses of various design parameters (e.g., soaking period, cycle rate limit, number of cycles, cycle, and cumulative injected-gas volumes). In the second part of the study, reservoir characteristics are investigated. Comparative discussions are presented between cases with CO2 and N2 as the injected gas on reservoir fluids of different compositions (heavy, black, and volatile oils). Influences of area, thickness, fracture/matrix permeabilities, initial reservoir pressure, and temperature on the process are studied. It is observed that N2, as a lower-cost gas, would be a better choice than CO2 in the Big Andy field. With the oil price used in this study, the cost of injected gas becomes relatively insignificant in economic considerations. Increased income from increased oil production overcomes the increased costs with higher volumes of gas. The way reservoir characteristics affect the process performance is similar in cases with CO2 and N2, but differs significantly with different reservoir fluids. Thicknesses ranging between 20 and 50 ft produced more favourable results than thicker reservoirs. A higher efficiency was observed with smaller drainage areas (5 to 8 acres) in the presence of heavy oil. For the cases with volatile and black oil, it is observed that the process efficiency is not altered significantly by the area. The phase behaviour of the reservoir fluid is important for the performance of the process. Initial pressure/temperature of the reservoir and, therefore, the initial fractions of gas/liquid phases affect the process efficiency in a more pronounced manner.
Gas cyclic pressure pulsing is an effective IOR method specifically for naturally fractured reservoirs. Due to the computational cost of simulating a large number of scenarios, it is an arduous task to determine the optimum operational conditions for the process. In this study, a practical screening and optimization workflow is utilized to determine the most optimum operating conditions for cyclic pressure pulsing applications with N2 and CO2 in a fully-depleted reservoir. Two huff 'n' puff design schemes with variable and constant injection volumes are implemented in a compositional, dual-porosity reservoir simulation model. A set of representative design scenarios is created and run using this model. Then, the collected performance indicators are fed into the neural network for training and two neural network-based proxies are developed:A forward proxy to predict the corresponding performance indicators once given the design scenarios,An inverse proxy to predict the corresponding design scenarios once given a set of desired performance characteristics. Finally, the genetic algorithm is used to search for the best design scenario that would maximize the efficiency of the process for a given time of operation. To evaluate the objective function, the forward proxy is used for computational efficiency. The methodology is tested with a single-well reservoir model of the Big Andy Field which is a depleted, naturally fractured reservoir in Eastern Kentucky with stripper-well production. Predictive capability and accuracy of developed networks are checked by comparing simulation outputs with network outputs. It is observed that networks are able to accurately predict the performance indicators including the peak rate, time to reach the peak rate, cycle flow rates, incremental oil production, and gas-oil-ratio. The proposed methodology is practical and computationally efficient in structuring more effective decisions towards the optimum design of the process. Introduction Cyclic pressure pulsing using different types of gases is an IOR method that is effectively applicable specifically to fractured reservoirs. In low-permeability reservoirs that are dissected by a network of interconnected fractures, solution channels, and vugs, waterflooding and gas flooding are not fully effective, since the injected fluid tends to channel through the high conductivity network and bypass the low-permeability, oil-bearing matrix.1,2 In this type of reservoirs, cyclic pressure pulsing with gas has been found to be effective. Fractures provide a large contact area for the injected gas to penetrate and diffuse through the low-permeability matrix. Also, high permeability of fracture system results in an easy delivery of both the injected gas and produced oil. Because it is a single-well process, well-to-well connectivity is not required. The payback period is rather short as compared to that of field-scale flooding projects. This makes the single-well cyclic pressure pulsing process a low-risk process with a relatively lower initial investment requirement. The process is characterized by three distinct stages: During the injection period, the gas is injected into the reservoir. After the injection period, the well is shut-in to wait for the injected gas to interact with reservoir fluids by diffusing from fractures into the matrix. This period is called the soaking period and its duration is typically 2–4 weeks. After soaking is completed, the well is put on production. Typically, a large amount of gas is produced at the beginning, while the oil production rate starts to rise and reaches a peak rate. After this point, production may continue until the economic limits are reached, and if necessary, another cycle can be initiated. In Figure 1 these stages are illustrated with their impact on the oil flow rate with time.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Big Sinking Field is a mature waterflood in the Appalachian Basin of Eastern Kentucky. The 100 plus million barrel (15.9 million m 3 ) field is primarily a shallow tight oil reservoir at 1,150 feet (350 m). A primary constraint to production is the ability to inject fluid into the reservoir. This project was an effort to increase injectivity by injecting an alkali-surfactant solution to reduce the residual oil saturation with a resultant increase in effective permeability to water. Oil is mobilized away from the injection well bore where a substantial portion of the injection pressure is lost by reducing capillary forces that trap oil. A new well was drilled and cored, and a laboratory program performed prior to field implementation. A variety of mixtures of alkali and surfactant reduced the interfacial tension between oil and water to 0.001 dyne/cm from 23.6 dyne/cm. Injection of a Na 2 CO 3 plus ORS-62HF alkaline-surfactant solution increased the relative water permeability by 425% and a NaOH plus AX-210-6 alkaline-surfactant solution increased the effective water permeability by 310%. Subsequent fresh water injection resulted in a loss of effective permeability to water to 155% times the original waterflood base for the Na 2 CO 3 plus ORS-62HF solution. The NaOH plus AX-210-6 coreflood maintained injectivity at 325% with subsequent water injection. In September 2003, injectivity testing began with injection of fresh water into a newly completed well to establish initial injection rate. A 1,500 barrel (238 m 3 ) injection of NaOH plus ORS-162HF alkaline-surfactant solution followed. Return of fresh water injection showed an increase in fresh water injection from 41 to 75 barrels per day (6.5 to 11.9 m 3 ).
Gas cyclic pressure pulsing is an effective EOR method in naturally fractured reservoirs. A limited number of studies concerning this method in the literature focuses on specific reservoirs and the optimum operating conditions have not been broadly investigated. In this study, we present a detailed parametric study of the process from both operational and reservoir perspectives. Incremental oil production, peak oil rate and net present value (NPV) are considered as the important markers for the performance criteria. The necessary analyses are performed for a single-well, dualporosity, compositional reservoir model. In the first part of the study, parametric studies are conducted to develop a better understanding of the operational parameters affecting the process performance, in the shallow, naturally fractured, and depleted reservoirs of Big Andy Field in Eastern Kentucky. These include analyses of various design parameters such as soaking period, cycle rate limit, number of cycles, cycle and cumulative injected gas volumes. In the second part of the study, reservoir characteristics are investigated. Comparative discussions are presented between cases with CO 2 and N 2 as the injected gas on reservoir fluids of different compositions (heavy, black and volatile oils). Influences of area, thickness, fracture/matrix permeabilities, initial reservoir pressure and temperature on the process are studied. It is observed that N 2 , as a lower-cost gas, would be a better choice than CO 2 in the Big Andy Field. With the oil price used in this study, the cost of injected gas becomes relatively insignificant in economic considerations. Increased income due to increased oil production overcomes the increased costs with higher volumes of gas. The way reservoir characteristics affect the process performance is very similar in cases with CO 2 and N 2 , but differs significantly in different reservoir fluids. Thicknesses ranging between 20 and 50 ft produced more favorable results. A higher efficiency was observed with smaller drainage areas (5-8 acres) in the presence of heavy oil. For the cases with volatile and black oil, it is seen that the process efficiency is not significantly altered by the area. The phase behavior of the reservoir fluid is very important for the performance of the process. Initial pressure/temperature of the reservoir, and therefore, the initial fractions of gas/liquid phases affect the process efficiency in a more pronounced manner.
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