Intelligent Completion in Water-Injector Well Improves Field Development
Authors: Carpenter Chris 
Published: March 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192850, “Improving Field Development Through Successful Installation of Intelligent Completion in a Water-Injection Well,” by Eglier Yanez, Mattheus Uijttenhout, Maher Zidan, Rail Salimov, Salem Al-Jaberi, Al Anoud Al-Shamsi, Amnah Al-Sereidi, Mohamed Mostafa Amer, Yousef Al-Hammadi, Abdullah Abdul-Halim, Giovani Caletti, Mustapha Adli, Yousif Hasan Al-Hammadi, and Fahad Mustafa Al-Hosani, ADNOC, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed.

The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. The objectives were to improve reservoir management, reduce well-construction complexity, and achieve cost optimization. This paper covers the overall aspects of well performance in commingled injection mode.

Introduction

The offshore field was discovered in 1971 in the Arabian Gulf. On the basis of results from exploratory wells, three main reservoirs were proposed for further development (A, B, and C). The commercial phase of the field started successfully, with first oil in 2015 provided by the two first wellhead towers as part of the Phase I development plan.

The completion design described in this paper is aligned with an optimized field-development plan (FDP) resulting from a study initiated in 2017. The main objectives of the study were integrating new acquired data to upgrade static and dynamic reservoir models to identify any opportunity for extra production and cost optimization.

Early water breakthrough caused by the initial elected well pattern and the associated oil-producer-to-water-injector spacing is a significant risk. Therefore, accessibility and selectivity to control inflow are strongly recommended for the upper reservoir (A) to mitigate the breakthrough risk and secure long well life and maximize reserves. The initial dual completion, with two horizontal laterals targeting Reservoirs A and B, and a nonaccessible upper drain was removed, and a single controlled completion was placed. 

Field-Development Plan Pattern. The FDP consisted of two phases. Phase 1 consisted of an early production scheme from two wellhead towers and export of untreated crude to nearby facilities. This phase contained an intensive data-gathering program to reduce reservoir uncertainties and identify future risks and opportunities clearly. Phase 2 is the full field development, containing the bulk of the oil producers and water-injector (WI) wells drilled from new wellhead towers and newly installed offshore treatment facilities.

The overall reservoir performance of Reservoir A was significantly better compared with the original basis of assumption. Consequently, the original line-drive development scheme between oil producers and WIs had to be revised in order to avoid early water breakthrough. As a response, the injector wells were placed outside the oil pool.

The behavior of Reservoir B met expectations; for that reason, the line-drive well pattern was maintained in this reservoir.