Matrix Water Injection in Deepwater West Africa - A Case History

A deepwater development off the coast of West Africa was designed with ten water injector wells to provide matrix pressure support to production well pairs in two separate reservoir units. Success of the water injection scheme was critical to underpin the overall oil production outcomes for the development, with technical uncertainty further magnified by the fact this was the first such development in the region. Alongside the criticality of the water injection wells themselves were separate but related challenges in the two reservoirs. The lower permeability ‘upper sand’ (larger reserves volume requiring proof of waterflood concept to potentially unlock future phases) and higher permeability ‘lower sand’ (critical delivery of efficient pressure maintenance to support early life project economics) both demanded exceptional solutions to deliver the highest practical initial injectivity performance. Their outcomes also needed to be robust over the life of field. Due to partially unconsolidated formations, active sand control was required in all wells and open hole completions were selected for both the producers (a mix of OHGP and SAS-ICDs) and water injectors (SAS-ICDs). The overarching design philosophy adopted for the project was to pursue a ‘matrix injection forever’ aspiration. This drove the requirement for water injectors which would deliver both the highest practical initial Injectivity Index (II) and be robust to the threat of injectivity decline during the long-term production phase. Injectivity decline in matrix injectors is a phenomenon which has long plagued the industry (Dambani, et al, 2014; Shumbera, et al, 2003) and given the high-cost environment with constrained remedial capability (deepwater, subsea, remote location), significant efforts in the well design and execution phases were therefore essential to optimise overall injectivity results. An even more ambitious objective of achieving direct matrix injection (i.e. without the need for flowback), was initially targeted for the higher permeability (lower sand) reservoirs, having previously been accomplished on an earlier project (Eshtewi, et al, 2020). Creating a tailored Reservoir Drill-In Fluid (RDIF) engineered to minimise formation damage while maintaining compatibility with the reservoir mineralogy and completion strategy was essential to this direct injection ambition. Central to this design was the incorporation of a delayed acid breaker system, formulated to activate post-placement and gradually dissolve residual filter cake. From the outset of the campaign however, a welltest spread was strategically carried. The main intent of this equipment was to facilitate flowback for the lower permeability (upper sand) wells where satisfactory direct injection outcomes were perceived to be more challenging, and the broader context for potential future development phases demanded a more conservative approach. Ultimately, the availability of the welltest spread (and some initial difficulties meeting objectives for high performance direct injection on early lower sand wells) drove a position whereby flowback or surging was executed for all wells in the campaign except one. The decision to more broadly implement flowbacks arose through a combination of emerging technical evidence for the II benefit in some wells, supported by a pragmatic business mindset of delivering injection wells ‘right first time’, given the prohibitive cost of future remediation, and comparatively low incremental impact of utilizing the existing welltest spread up front.