| Popis: |
As more and more water is being co-produced with hydrocarbon, saltwater management has become an important enterprise. Out of many available tools in water management, saltwater disposal through Type II wells is critical to handling large quantities of produced brine. Since the produced water usually contains impurities such as solids, oil and grease, and bacteria, the well's injectivity deteriorates over time as the skin factor develops. Injecting over the formation parting pressure (FPP) gradient may lead to a matrix bypass event and other geohazards; accurately determining the FPP of the target formation is needed to maintain safe injection operations. However, using the step rate test (SRT) doesn't warrant an accurate result. As the target formations can have multilayers with distinct properties, we often find that SRT is often misused. SRT is often recommended based on oil field operational experience because it is easy to execute and interpret. One fundamental assumption for SRT is that the target formation is a single layer with relative isotropic properties; however, this isn't always true for saltwater disposal wells (SWDs), which usually penetrate through multilayers with very heterogeneous properties. To illustrate our concept, we present a case study using SRT results from an active SWD well located in the Anadarko Basin. We recommend a geomechanical model to determine the operating surface pressure in this paper. The geomechanical model considers the original stresses, variation of geomechanical parameters, injection pressure, and temperature. To consider the uncertainties of these parameters, we demonstrate how to use Monte Carlo simulation to determine the maximum operating surface pressure. We recommend several analyses for the collected data to determine the well's injectivity variation. The Monte Carlo simulation result yields a possible fracturing gradient and presents the probability of each fracturing gradient. Probability is crucial in decision-making as different operators/fields may have different risks, tolerance, and uncertainties. The recommended practice is an integration of data sets and analysis that yield the maximum injection pressure to maintain the well and formation integrity with different risk tolerance levels. |
