Intelligent completions were introduced over a decade ago to address completions and reservoir management challenges arising from highly-deviated, extended-reach, multi-targeted, or multilateral wells. Recent advances in exploration and drilling technology are enabling the oil and gas industry to target reservoirs with stratigraphic and depositional complexities in deepwater, subsalt, arctic, and other extreme environments, resulting in the need to develop a new generation of intelligent completion tools. These reservoirs also may be characterized by HPHT, extreme HPHT, or ultra-HPHT environments with multiple components contributing to the uncertainty of recovery.This paper describes how the requirements of current and future reservoir environments and a decade of operational experience have shaped the functional design and qualification of a new-generation Interval Control Valve (ICV) for intelligent completions. The new-generation ICV has higher pressure and temperature tolerances to cater to the new harsher environments while simplifying its operating mechanism and improving inflow performance and debris tolerance. The qualification program included metal-to-metal seal qualification, life-cycle testing, API 14A SCSSV class II-sand slurry based tests, flow coefficient (C v ) test, seal stack qualification, and erosion testing. Descriptions of each qualification test, acceptance criteria and test results that demonstrate the capability of the new generation of ICV to perform in severe service conditions are presented in this paper.Some field applications of the new-generation ICV are also presented. Technologies, such as real-time ICV position feedback, have further aided in maximizing efficiency. Finally, the paper outlines the operational limits of the current design and discusses the design enhancements planned for the next-generation ICV.

The multiple zone water injection project (MZWIP) was initiated to deliver the following key objectives: deliver zonal injection with conformance control and reliable sand management across the major layered sands of the Balakhany unconsolidated reservoirs in the BP operated Azeri-Chirag-Gunashli (ACG) fields in Azerbaijan sector of the Caspian Sea. Three years after MZWIP implementation, six wells with a total of 14 zones are injecting at required rates with zonal rate live-reporting. To achieve this multizone injection facility, the requirement for a standard ACG sand-control injector design was discounted and a non-standard sand management control technique developed using a cased & perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world's first 10kpsi three-zone inline variable-choke DHFC wells with distributed temperature sensors (DTS) across all target injection zones. The choking DHFC provides flexibility in operations and delivers the right rates to the right zones. The DTS provides conformance surveillance, fracture assessment, caprock integrity and sand ingress monitoring capability. A customized topside logic control system provides an automatic shutin of interval control valves (ICVs) during planned or unplanned shutins to stop crossflow and sand ingress and is the primary method of effectively managing sanded annuli. The development of this MZWI solution has significantly changed the Balakhany development plan and has been quickly expanded across five ACG platforms. Accessing 2nd and 3rd zones in the same wellbore, this C&P DHFC well design is accelerating major oil volumes and will significantly reduce future development costs, maximizing wellbore utility in a slot-constrained platform.

More than 350 multilateral junctions have been installed in the Norwegian continental shelf fields since 1996; currently around 25 junctions are completed annually. The current predominant junction is a TAML (Technology Advancement of Multi-Laterals) Level 5 multi-branch system. This paper discusses the evolution of TAML Level 5 junctions during this period and uses simulations to screen different junction technologies for value determination. This latest generation of sealed multilateral junctions when combined with flow control equipment, including surface-controlled interval control valves (ICV) and autonomous inflow control devices (AICD), enables full production control of the main bore and each lateral independently. The production life of wells in the Norwegian Troll field is limited by early gas and water breakthrough owing to the thin reservoir. Historically, this issue has been mitigated by using multilateral wells to increase the reservoir contact. Intelligent completions were originally adopted to control the flow from a maximum of two laterals. The latest innovation is the multi-branch version, which provides individual control of each lateral in tri- and quad-lateral wells. Using published and estimated well data, this paper provides simulations to demonstrate the incremental benefits of each new multilateral junction configuration. The objective of screening with simulations is to show how evolving junction technology with integrated flow control, improves hydrocarbon recovery, minimises effluents and accelerates production akin to the performance observed in the Troll field over the past 20 years. The multilateral technologies installed over that time period have demonstrated the benefits of having close collaboration between the operator and the service provider. This has enabled the technical advances described in this paper. Analysing well performance with simulations validates specific flux performances associated with each technical improvement and reinforces the benefits of collaboration. Each new junction innovation will be described, and the associated simulation of flux performance will be provided for comparison with prior junction technology. With the current innovative junction and integrated flow control, the operator can optimize the oil production from new and extended-reach multilateral wells. Also, in multilateral operations, dedicated coordinators along with a proactive engineering team have eliminated, or reduced, installation risk to an acceptable level for operators using the technology. In addition, the implementation of multilateral technology (MLT) early in the planning stage enables the addition of production intervals at a cost of 20% or less of the initial well cost, which makes many marginal field developments viable projects. Simulations aid decision making by distinguishing the performance enhancements associated with technology evolutions that optimize well completion. As demonstrated for multilateral technology, this well completion technique can reduce construction costs vs. individual wells to access the same footage of reservoir contact, but the real benefit is the increase in oil production with reduced water production to lower the barrel-of-oil equivalent cost of production or injection.

The criticality and a means of modelling latest generation wells employing Inflow Control Device (ICD) and Autonomous Inflow Control Device (AICD) completions providing solutions to the production constraints encountered in multi-reservoir contact wells is presented in this paper. ICD-AICD wells enable a better-distributed production/injection from/into different reservoir zones/layers by adding a passive and or autonomous downhole restriction. ICD-AICD technology thereby enables more efficient field development by improving sweep efficiency, potentially reducing the number of production/injection wells required and maintaining well longevity and profitability. Modelling the completion interaction with the reservoir is critical to determine the incremental value of applying such technology. This being achieved by coupling the wellbore model, which includes the lower completion, to the reservoir properties. The modelling technique, a grid-based numerical well/reservoir simulation, necessitates knowledgeable personnel and detailed, sometimes uncertain, geological data. The multiple model iterations required when using ICD-AICD technology further increases the reservoir simulators' computing time. A new tool was developed to design and analyse ICD-AICD efficiency, bridging between a simple steady-state inflow snapshot evaluation and a full dynamic reservoir simulation. The new model uses the proven classical method of fractional flow, combined with the performance of specific flow control devices installed in the well. This allows fast forecasting of the production profile and oil recovery, as well as optimizing ICD-AICD configuration at the well design stage. The proposed workflow is implemented as either a production forecast or a diagnostic tool for an ICD-AICD well in an immiscible gas or aquifer-supported oil field. It provides one missing link between today's ICD-AICD design workflows and the long-term value evaluation of a specific design when a full reservoir simulation is either not available or too time consuming. The method's transparency and ease of implementation of its algorithms can make it a useful tool for well and reservoir engineers to design and analyse the value of ICD-AICD devices.

The unique introduction of production screens with mechanically shiftable flow isolation sleeves and inflow control devices for better injection flow distribution (ICD) fit with innovative dissolvable metal plugging rods that allow wash pipe free horizontal completion installation on a deep offshore project in Nigeria. This unique application provides the function of a mechanical selective completion with the incorporation of an ICD solution tailored to the reservoir with wash pipe-free execution. This would allow for selective injection from one zone to a comingled injection activated using mechanical intervention means while maintaining full compatibility with the already designed upper completion and the existing wellhead and topside equipment, as is. The completion was successfully installed following the standard field operations practices used on previous completions within the same field. The Egina development plan, operating with a standardized and simple design, does not provide for an intelligent completion that allows remotely activated zonal selectivity. Two separate reservoir zones, with two panels each, were targeted for water injection to achieve the sweep of by-passed oil in the shallower panels connected to two producer wells and pressure mainteneance in the deeper panels connected to one producer well. Commingled injection from start would result in early water breakthrough on one of the two producer wells connected to the shallower reservoir panels by virtue of both well drains being almost at same level depthwise, TVD/MSL. A solution was selected that would combine the two target reservoir zones on a single well. This would allow for selective injection using screens with mechanically shiftable integral sliding sleeves, maintaining temporary access or isolation on the shallower interval. This solution would allow for drilling one single water injection well instead of two. Incorporating ICDs in the deeper reservoir panels with "a dissolvable plug solution" allowed for a better injection flow distribution as well as the completion deployment, wash pipe free. Fluid compatibility testing was performed with dissolvable metals to establish dissolution rates under existing reservoir conditions with mud, brine, and filter cake breaker at field standard formulations. This provides an additional option for running wash pipe free when running lower completions in deepwater wells offshore West Africa. Drilling one well instead of two and deploying completions wash pipe free, allowed for CAPEX savings in the region of $60 Million. No modification to the existing completion processes was necessary with respect to the procedure for deploying completions, washing down or subsequently placing a filtercake breaker treatment. This paper describes the rationale behind the well design philosophy and the operational procedures that introduced a global first deployment of injection screens with mechanically shiftable integral sliding sleeves and ICDs with dissolvable plugs in deep water openhole horizontal completion. The successful installation, completion equipment functionality, and well injectivity test results are discussed.