Understanding injectivity is a critical element to ensure that sufficient volumes of water are being injected into the reservoir to maintain reservoir pressure, to ensure good reservoir sweep and minimize well remediation. It is, however, challenging to describe the large injectivity changes that are sometimes observed in injectors operating under fracturing conditions. This study presents a field case study with the following objectives: 1) explain the complicated injectivity changes caused by fracture opening/closure with injection-rate variations, 2) define a safe operating envelope (for injection pressure and rate) that ensures fracture containment and injection into the target zone, and 3) prescribe how the injection rate should be changed to achieve higher injectivities. Injector operating conditions are developed using results from a full 3-dimensional fracture growth simulation to ensure fracture containment in a multi-layered reservoir. We present field injectivity observations, a comprehensive simulation workflow and its results to explain injector performance in a deep-water turbidite sand reservoir with multiple splay sands. Understanding the impact on fracture propagation and containment allows us to make quantitative suggestions for the operating envelopes for long-term injection-production management. Strategies for high-rate injection to sustain the injection well performance long-term are discussed. Simulation results show that, at injection rates over 5,000 bwpd, injection induced fractures propagate. Fracture closure induced by injection shut-down is used to compute the bottom-hole pressure decline as a function of time. The fracture opening/closure events and the thermally induced stress were the primary factors impacting injectivity. The simulation results suggested several ways to improve the injectivity while ensuring fracture containment. Injection under fracturing conditions into a single zone at a high rate is shown to be feasible and this allows us to support a substantial increase in injectivity. This must, however, be done at pressures that will not cause a breach in the bounding shales. The 3-dimensional fracture simulations identified the operating pressure and rate envelope to maximize the injection rates while minimizing the risk of breaching the cap rock and inter-zone shales.

This study explains the large injectivity changes observed in the field, how to remedy it, and how to ensure fracture containment in channel sand reservoirs. The case study field is located offshore Ghana and is a channel sand reservoir. Water injection was initiated for pressure maintenance and waterflooding under fracturing conditions. The injection wells are designed to ensure high and sustainable injection rates while maintaining the integrity of the cap rock. The injection bottom-hole pressure (BHP) was history-matched to investigate the impact of stress profiles, reservoir shapes, injection water quality, poroelastic and thermally induced stress changes. The injectivity decline was found to be a result of changes in stresses caused by the channel boundaries and, to a lesser extent, near-wellbore formation damage. The rapid increase in pore pressure and the resulting decrease in injectivity is unique to these kinds of channel sands. Once the origin of the decreasing injectivity was identified, remedial actions were recommended and predictions for future injectivity were made ensuring containment of fractures.

Most deepwater high rate wells are completed with sand control to avoid sanding issues, especially for a subsea development. However, sand control adds significant Capex to the development besides causing additional pressure drop across the completion. In addition, experiences to date have shown that sand control completions tend to increase in mechanical skin over time due to solids plugging or scaling leading to additional Opex required to stimulate these wells. This paper describes the key steps taken for two major subsea deepwater developments in Ghana, in order for a paradigm shift towards Cased and Perforated (C&P) completions for full field implementation. Oil production and water injection in both fields are primarily from sand facies associated with Clustered Frontal Splays and Confined Channel Complex. All completions deployed initially were equipped with downhole sand control (mainly Frac and Packs), but driven by well impairment issues early in field life, a thorough review of completion type was initiated which lead to a staged implementation and move towards C&P design for all high rate oil producer and water injector wells. Modified API RP 19-B Section IV tests were performed using core material from the fields for catastrophic sanding risk evaluation over well lifecycle, and examination of sanding under steady state flow conditions with varying fluid type. Laboratory test results and simulation data were then used to determine safe operating envelopes for the designs. A staged implementation commenced with C&P completions in two wells with the use of High Set Screens (HSS) with capability of bypassing the screens if required and ‘real-time’ downhole gauges to monitor pressure drop across the screens over time. Based on the confidence attained from the sand free production data from both these wells, HSS were removed altogether from subsequent completions. Well performance data have demonstrated the successful application of C&P completions in typical deepwater turbidite setting. C&P completions have significantly lower skin than other completion types applied in the same fields and are capable of delivering more than 20,000 stb/d oil rates and more than 50,000 b/d water injection rates.