Geomechanical Integration Maximizes the Value for Polymer Full Field Decision for Clastic Reservoir Field in South of Oman
Authors: Zadjali R. , Rawahi Z. , Riyami O. , Rawahi A. , Mandhari N. , Hadhrami A. , Ghannami M. 
Published: November 2023

Integration between different disciplines is a key to the success of any field development plans (FDP) and well, reservoir and facility management (WRFM). For a proposed waterflood development, the injection strategy is to inject under matrix conditions (i.e. below fracture pressure limit) at an optimal rate to improve sweep efficiency and hence maximize oil recovery. Therefore, injection rate was constrained at maximum operating injection Tubing head pressure (THP) based on analogue data and correlation. After several years, the reservoir pressure showed significant depletion. As a consequence, the field experienced drastic oil rate drops with a gas development in localized area. In addition, moving to polymerflood, it was realized through simulation that economical injection rates can only be achieved under controlled fracture injection. Therefore, for both developments understanding the fracture pressure, depletion impact on fracture pressure gradient and fracture growth is a key. This paper demonstrates Geomechanics key role in integration with subsurface and surface discipline to optimize waterflood performance and land on key project decisions of polymerflood full field development project for a clastic reservoir field in south of Oman. The current injection strategy in the field is to inject under matrix condition and to maximize injection by injecting up to the fracture pressure. The downhole pressure should not exceed the fracture pressure to avoid inducing fractures. Step rate tests (SRTs) were available for this field but did not provide a conclusive interpretation. A mini-frac test was conducted later, in the most depleted area, which provides reliable estimate of fracture pressure. The selected candidate well covers the reservoir two main units (A) representing the depleted case and (B) close to virgin pressure. As a follow up surveillance monitoring, more recent SRTs were planned, executed, and monitored through a Fiber Optic (FO) data acquisition consisting of Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS). For polymer flood on the other hand fracture growth was estimated using analogue field data in absence of actual long term polymerflood fracture injection data.

Analysis of available old Step Rate Tests (SRT) indicated injectivity improvement at THP ~4000 - 6000 kPa at rates varies between 200-500 m3/day. However, the SRT data could be influenced by near wellbore condition and added wellbore skin due to near wellbore damage and/or due to fines plugging the wellbore. A mini-frac test was conducted in 2019 which is in the most depleted area. This provided reliable estimate for fracture pressures for input to optimal injection pressure. Fracture pressure for the A/B intervals was interpreted to be in the range of 13500 to 15100 kPa (15 – 16 kPa/m at ~ 900 mTVDbdf at a reservoir pressure of~ 4000 kPa in unit A). From this data the interpreted safe THP limit for the field injectors to operate under matrix condition was 60 bar.

In 2019, the asset team re-analysed the injection data and realized that there is huge potential to increase injection throughput given the gap to the THP limit. The result of the mini-frac data indicated that increase in water injection pressure by 3000 kPa would not increase the risk of induced fracturing and allowed increase in Voidage Replacement Ratio VRR. The immediate implementation improved VRR and the recovery of the field by more than 22% within 6 months of implementation. This resulted in an incremental increase in total injection rate ~ 7000 m3/d for the period between 2019 and 2021.Hence this injection pressure is not sufficient to induce fracture during polymer injection. The same source of data was also used to decide on required surface facility pressure to meet subsurface requirements.

This paper demonstrates the value of integrated team effort on optimizing waterflood performance and the close loop on landing in one of the key polymerflood project decisions.