In onshore Middle East, local practices for matrix stimulation of openhole horizontal carbonate water injectors consist of spotting hydrochloric acid treatment via coiled tubing (CT) along the uncased section using a specific fluid dosage per unit length of the pay zone. Thus far, that approach has delivered inconsistent results in wells completed across tight carbonate rock, most often leading to a rapid decline in injection rates following the treatment. An alternative workflow was implemented to take full advantage of real-time downhole measurements and the presence of fiber optics in the CT for telemetry. The approach leverages distributed temperature sensing (DTS) to evaluate the original water injection coverage across the reservoir. Results enable segmenting the open hole into intervals requiring different levels of stimulation. Each section benefits from a customized treatment that increases injectivity and improves uniformity of injection. A high-pressure jetting tool, controlled with the help of real-time downhole pressure data, is key to that workflow because it enhances penetration of acid into the targeted intervals. Previous studies showed that energized acid is key to a successful stimulation of tight carbonates. However, the use of CT to convey and pump acid along the open hole often limits the rate at which fluid is pumped, and customized nozzles may fall short of expectations if the downhole conditions are not favorable to their proper actuation. The introduction of real-time downhole readings and DTS surveying into the stimulation workflow helped overcome those limitations and get the most out of equipment and fluids. DTS offers a visualization of high- and low-intake zones along the open hole throughout the operation, thus enabling informed decisions on design adjustments for each stimulation stage. Downhole pressure measurement is instrumental in determining whether downhole conditions are favorable for the use of the high-pressure jetting nozzle, which has a direct impact on the exact pumping sequence, with the potential addition of stimulation stages to bring the openhole in optimum conditions. Downhole pressure reading also allows optimal operation of the jetting nozzles within the designed range. The engineered workflow has been successfully implemented delivering injectivity improvements of nearly 8,000 B/D in the intervened wells, with the DTS survey confirming significant gains on injection coverage along the openhole section. This advanced matrix stimulation workflow, brings reliability and flexibility to the acidizing of tight carbonate water injectors. Use of the full array of downhole parameters not only yields unprecedented injection coverage in complex reservoirs, it also eliminates uncertainties associated with wellbore conditions and helps in keeping injection under the fracturing gradient, thus eliminating the risk of differential sticking events.

New green field development projects require pre-commissioning of oil producers and injectors to establish the potential of the wells in order to ensure the mandated production and injection targets before handing over the wells for tie-in activities as part of commissioning operations. In addition pre-commissioning activities are required for data gathering to confirm the reservoir properties and further to optimize the long term development strategy. However, the challenge is to deliver the wells to EPC contractor before the mandated timeline with the given constraints of limited resources, simultaneous operations (SIMOPS), remote location and sour fluid environment. Therefore, the objective is to optimize the pre-commissioning duration without compromising the reservoir data gathering requirements along with minimizing the capex with an aim of maximizing the project NPV. This paper describes about a case study of systematic optimization process being adopted in one of the newly commissioned green fields to minimize the duration of wells pre-commissioning to be able to meet the project milestone. During planning stage minimized the overall duration considering interfaces required among the activities including PAD drilling, EPC tie-in, rigless unit plan and SIMOPS requirements. Further data gathering planned as part of pre-commissioning activities were customized considering the availability of appraisal wells data. The important optimization process was implemented during actual execution stage to reduce the duration and cost by creating task force team to make real-time decisions. Customized approaches were implemented including rigless unit lay out optimization, utilization of temporary flow lines to reinject the produced oil to the existing appraisal wells and operating ESP’s instead of nitrogen kick off to minimize the resources and duration. Trucking option was not selected due to HSE concerns and remote location. Overall this optimization process implemented within the limits of reservoir guidelines, HSE requirements & environmental limitations. In general each well takes around 1.5 months to complete the pre-commissioning activities based on remote location and sour fluid environment. Successful completion of pre-commissioning activities, ensured meeting the business plan mandated profiles and optimized the surveillance plan. Overall, this optimization process ensured delivery of 45 wells required as part of first oil, within mandated time line of one and half year. Capex corresponding to rigless jobs was reduced by 50% and pre-commissioning activities were completed adhering to 100 % HSE requirements and minimized the gas flaring requirements. This optimization process will be further used in coming years for the next phase of planned development in the same field. Optimization process described in this paper will add value in reducing the capex and pre-commissioning duration of marginal fields, producing sour fluid at remote location and require simultaneous operations due to PAD drilling.