With the widespread drilling of gas wells in Marcellus shale, there are high potentials for wellbore instability problems when wells are located in longwall mining areas, which in many areas such as southwest Pennsylvania, West Virginia, and eastern Ohio are being used for extraction of the coal seam overlaying the gas reserves. The ground deformation, caused by coal mining, could generate large horizontal displacement and complex stress change in subsurface rock. This in turn triggers ground movement which can cause casing failure, and thus interruption in the operation of the well that raises safety and environmental concerns. This could result in shutting down the well for repair, or permanent abandonment. Thus, it is critical to characterize the parameters related to the longwall mining process and to propose a general casing design guideline in such areas. In this paper, numerical modeling was utilized to simulate the complex ground conditions and resulting stresses and strains in longwall mining areas. A casing design spreadsheet was then constructed for design of appropriate selection of casings, based on the results of the numerical modeling. Our results were validated with field practices of wellbore design in southwest Pennsylvania. This paper also provides a methodology for investigating potential ground deformations, resulting stress/strain changes, and wellbore stability issues for oil and gas wells drilled in longwall mining areas in Marcellus shale or similar formations worldwide with active coal mining activities.
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.
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.
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