Technology Update Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology. Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications. IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system. Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well. Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead. Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.

The drilling records of Extreme Reservoir Contacts (ERC) like Extended Reached Drilling (ERD) and Multi-Lateral wells(ML) continue to be broken. From the initial limit of MD 10,000ft to now almost 50,000ft with extended reach depths and from dual-lateral to quad-laterals’ with 40,000-50,000ft reservoir contact. Completions rule of engaging with this type of wells continues to play ‘catch-up’. As a result, getting the full potential out of these extreme wells with limited completions options had always been a challenge. Recent innovation in "wireless electric connect/disconnect" technology combined with all electric integrated intelligent completions architecture has addressed these challenges. The well completion design is an all electrical system that provides a multi trip connect/disconnect system enabling seamless communication between upper and lower completions enabling permanent downhole monitoring and control, at the sand face. The highlight of this digital edge solution and deployment architecture enables completions to deploy in ERC wells meeting targeted drilled depths and achieving reservoir goals. The digital enablement provides real time downhole data for permanent production logging and zonal well testing capability while producing. Production and reservoir management is at finger tips of the end user. A new innovative down hole electric telemetry enabled data transmission and power to be distributed across multiple sensors like pressure, temperature, water cut and electric flow control valve. Run on a single electrical cable, this digital completion technology with its induction coupling capability continue to complete record-drilling wells and makes today's completions limitations a history. It is now a reality for fully-digitalized Intelligent Completions solution, which can support any well type scenarios; multi-zones, horizontals, multi-laterals and extended reached drilling (ERD), including subsea completions. Each zone can be equipped with a permanent downhole infinite position valve-control, flowmeter, water-cut sensor and/or pressure/temperature gauges. This allows real-time reservoir measurement and supports ‘Dial A Rate’ flow control. Conventional flow control valves depend on hydraulic actuation system, although the technology has worked for decades, it has some inherent limitations such as need for multiple control lines limiting the number of zones, maximum depth of deployment as well the response time of hydraulic systems for very long completions. Electric valves are free from these limitations by design and provides lot more flexibility in the hands of the completion engineer. The multiple sensors measurement and data integration is achieved with a single surveillance, monitoring, diagnostics and valve-optimization production software to ensure real time data streaming, management and bringing insights to production and reservoir engineers for production optimization through remote valve control. This digital solution of Intelligent Completions technology can finally claim that completions is no longer the limiting factor, effective reservoir management with intelligent completions can follow wherever the drill bit can go. It has been deployed worldwide from the Middle East to the open Sea in Pacific to enable zonal production-control and reservoir management. Its borderless completions architectures and standardization of modular system is the answer for Digital Oilfield and Data driven continual production optimization and reservoir management without intervention. For the first time in Completions history, extended drilling records are matched with completing the entire well to Measured Depth (MD) with fully digitized solution of multi-zone measurements, infinite-control valves and real time data enabled production optimization system.

Monobore wells have been a staple of the oil and gas industry for many years due to their simplicity and flexibility for common intervention techniques. One downside comes when a producing interval or intervals start depleting, compromising lift performance. Velocity strings have been successfully deployed in monobore gas wells to improve lift performance. Retrofitting oil wells, such as presented here, with a gas lift string can significantly enhance the productive life of a well. Performing this retrofit rig less offers additional opportunities in maintaining field production from more marginal wells not especially suited to full work over operations.Retrofitting completions rig less presents a number of technical and operational challenges. Gas lift utilizing a coiled tubing (CT) dip tube and the associated valve sizing, setting depths, and lift gas optimization are discussed in the context of the reservoir conditions and well parameters. The mechanical aspects associated with the hanging of the dip tube, thermal effects, and corrosion inhibition present specific challenges similar to conventional completions, but with the complexity of deployment under live well conditions. Well control aspects associated with deployment, retrieval, and production are important considerations both technically and operationally. The Pressure Control Equipment (PCE) stack must be suited to the dip tube completion components, while providing effective barriers to secure well during deployment and emergency scenarios. The ability to connect, test, and deploy several gas lift mandrels suitably spaced with coil tubing "tubing" are operationally challenging. The deployment aspects are thus fundamental to the success of the concept.During a job in Thailand, a corrosive, high-CO2, nonproducing monobore oil well was revived using a corrosionresistant CT dip-tube gas lift completion. The project successfully restored well production from zero flow to 900 B/D. Conceptual design, tool selections, key technical decisions, and operational aspects are discussed.

Static inflow control devices (ICDs) have been designed to provide a more even inflow across production zones by adjusting the completion pressure differential to balance reservoir drawdown. Unwanted fluids are delayed, oil production is enhanced. Recently, companies have offered "intelligent" completion products that include fully addressable downhole electric control of annular flow control valves (AFCVs) whose inflow cross-sectional area can be dynamically changed in response to variations in production (e.g. to control water ingress or increase oil production). This paper examines the use of surface-controlled AFCVs to improve wellbore cleanup, and both AFCVs and ICDs to improve production. Open areas of the AFCVs, positioned at the edge of reservoir compartments, are employed as optimization variables in a simulation study of wellbore and near wellbore cleanup. Similarly, AFCV areas and ICD settings are adjusted to optimize the subsequent production cycle. The study focuses on a lower cretaceous carbonate rock reservoir with tight facies where a single horizontal wellbore traverses three distinct compartments. Long multi-lateral wells are typically employed in this region and wellbore cleanup, and thereby productivity, can be a key component in the success of the well. Introduction Following a review of recent literature on this topic, the AFCV used in this simulation study is discussed. A brief overview of the reservoir simulator and well model is then given. A new, sophisticated wellbore cleanup simulator that was used for optimization of this process, is described. Details of the case study, loosely based on a middle-eastern carbonate reservoir with tight facies and a gas cap, bottom water, and three distinct compartments through which a long horizontal wellbore has been drilled, are presented. The body of this work first examines various methods to optimize the cleanup phase and discusses the best way to achieve uniform productivity along the entire length of the well. Next, during the subsequent production cycle, AFCV area settings are periodically optimized, the frequency and nature of these updates being specified by the operator. Finally, a comparison is made with ICD settings which are fixed at the beginning at the production cycle and optimized to achieve either (i) a best Net Present Value (NPV) or (ii) an improved conformance in compartments with less productivity. Following a discussion of results from these studies, conclusions are presented including recommendations to improve both wellbore cleanup and production. Review A brief review of recent literature concerning optimization of ICDs and ICVs is as follows. Fu et. al. (2014) discuss a simulation study wherein static ICDs were optimized to achieve long term well productivity. They propose the target objective for optimization given well BHP, daily production and no-water production period constraints. A comparison was given between production cycles utilizing open-hole, constant ICD and optimized variable ICD completions. Akbari (2014) analyses correlations for various ICD designs in order to optimize ICDs along a horizontal wellbore. A number of key parameter indicators, including number of ICDs and length of intervals to equalize the inflow, are included. Rodriguez et. al. (2014) talk about the impact of intelligent completions, including a sliding sleeve and concentric dual completions, on potential productivity in the Shushufindi-Aguarico oil field, Ecuador.

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