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.