Abstract
The Amin field located in South Oman is one of the PDO's major producing oil fields. The reservoir is good quality sandstone formation with average porosity of 28% and average permeability of 800 mD. Prior to 2014, the field was developed using natural depletion drive during which some parts of the field experienced significant pressure depletion. This depletion was due to combination of high production from the crestal area and the presence of a near field-wide intra baffle (L110), that restricts the aquifer response to the upper layers of the reservoir. The baffle about 2m to 4 m thick is a cemented sandstone with minor shale intercalation that has caused the vertical pressure variation across baffle L110.
To arrest the field pressure depletion, water-injection was implemented since 2014, for further field development. Produced water is injected into the aquifer below the OWC of the field through 38 vertical injector wells. To achieve desired voidage replacement injection is expected with fracturing conditions using untreated produced water with injection rates > 1500 m3/day. Bottom hole pressures are at or above formation fracture pressure and decline in injectivity with time has been observed due to untreated water.
Geomechanical data and modeling results were integrated with WRM activities, trials data and surveillance technologies to optimize the injection strategy for improved waterflood performance. Geomechanical data was acquired to estimate the formation fracture pressure to provide guidance on maximum allowable injection pressure in injectors with perforations closer to OWC to manage the risk of induced fracture growth. A Produced Water Re-Injection (PWRI) fracture modeling and analysis was performed to determine the potential fracture dimensions to provide input to development decisions of injection rate and perforation depth below OWC. Simulations were carried out with estimated range of formation fracture pressure, Petrophysical parameters, injection rate forecasts and expected water quality parameters e.g. TSS (Total Suspended Solids)
The simulation results from the field data calibrated PWRI fracture model indicate that injection higher rates > 1500 m3/day, would result in vertical fracture growth from the injection depth. The rate of fracture growth is primarily influenced by water quality and depth of injection. Formation fracture pressure decreases with depletion therefore once the vertical fracture propagates and enters into the upper reservoir zone, fracture growth will be accelerated. Results indicated that if injection depth closer to OWC can result in short-circuiting as early as 2 years for certain field area.
Higher injection rates to meet the desired voidage replacement ratio has significant impact on the field's waterflood performance. Results provided inputs to reservoir simulations and injection rate envelope for varying perforation depth below OWC. The study benefits the field to minimize risk of injector producer short-circuiting for improved waterflood management.
