Abstract
In the recent years there has been considerable focus on value creation from downhole instrumentation within oil and gas production wells, specifically in deep water assets where cost of production logging is significant. As a result, injector wells are often overlooked from an instrumentation perspective during development of deepwater fields. As critical as reservoir sweep and pressure maintenance can be to achieving the expected ultimate recovery (EUR), monitoring the injection profile, formation damage, and fracturing through the full well life cycle is often overlooked. This paper shares a study exploring the potential surveillance benefits of deploying downhole pressure gauge arrays in injection wells.
Well, reservoir and injection data were collected for a representative offshore horizontal injection well with a stand alone screen, inflow control device (ICD) completion. Low count, pressure gauge arrays were selected as a potential alternative to fiber optics for injector performance monitoring. A calibrated pseudo steady state well model was created to evaluate gauge array design parameters against ability to measure flow. Downhole pressure gauge array measurements were evaluated against the models predicted injection behavior. Optimum number of gauges to decipher well injection flow distribution, skin build up over time, fracture creating in both longitudinal and transverse directions, and flow blockage in tubing were assessed.
An application of pressure gauge arrays was identified as a potential viable alternative to fiber optic monitoring. The use of pressure gauge arrays in injection well exhibited promising results with accuracy greater than 95% in predicting injection flow distribution. Furthermore, the predictability improves as gauge -to-gauge spacing is optimized. Additionally, localized buildup of formation skin on injectors over time was measurable with high degree of accuracy as the gauge separation was reduced. Hydraulic fractures initiated in injectors showed distinct pressure signature to identify the possible transverse or longitudinal fracture initiation. However, the location of a transverse fracture generated in the near wellbore beyond the screen was more difficult to identify due to the discrete nature of pressure gauge measurements. Well blockage and injectivity index reduction was easily detected by pressure gauges ported to measure inside of the tubing.
Currently, not many case studies exist for deepwater injection well surveillance in the literature. However, as relatively newer surveillance techniques such as fiber optics evolve, this study provides a view into a robust and cost-effective technology that could be a useful tool in solving the questions around well and reservoir surveillance for improved management and proactive response in reservoir maintenance, data handling, interpretation and implementation of insights generated.
