The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena. This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below: Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore. The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement. The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.

With extremely challenging and unforgiving ultradeepwater environments combined with those of high-pressure, high-temperature (HP/HT) reservoirs, the costs associated with not understanding each unique dynamic environment could be very high. The complexities of the hardware systems are akin to human beings' internal systems, involving dependent and independent interactions. When these complex systems are deployed into unforgiving environments without appropriate safeguards/assurances, unforeseen adverse issues will eventually occur.To help reduce the likelihood of calamitous failures or well completion issues, prejob perforating and well construction simulations have become industry standard. Notwithstanding the utilization of industry accepted models, issues continue to arise. Assurance models that were previously industry-standard lack the complexity of newer, improved systems on the horizon that are better able to quantify the dynamic events experienced in these extremely challenging environments. In essence the modeling technology has not kept pace with the present environments we perforate in.Understanding and managing stress and shock loads imparted to downhole tools during their full range of operating conditions is critical to the reliability of such tools. In the case of a perforating gun string, the energetic material detonation forces inducesignificant stresses on adjoining tools (Dobratz 1985). This paper discusses the case of a perforating string affecting an adjoining interval control valve (ICV) in the tubing string by a 4 5/8-in. gun system.One of the most significant stresses experienced by downhole equipment is the loading imparted by the release of energetic material detonation forces during downhole perforating. Knowledge of the dynamic response of downhole perforating gun strings during detonation is critical to the development of better performing gun systems, equipment, and optimal job designs with maximum reliability.Numerical simulation is central to advancing this understanding, but available simulation tools have generally been limited to hydrodynamics models focused on optimizing shaped charge perforating performance (Han et al. 2010) and to highly simplified string and wellbore models lacking the fidelity required to capture the full system behavior with sufficient accuracy. Limited value of current models has been attributed to the general lack of relevant data needed for proper model calibration and validation.Approaching the development of a resolute system model that addresses these shortcomings required

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.

This article focuses on the completion design of a multiple-zone water-injection project (MZWIP) that was initiated in 2016 in the Azeri-Chirag-Gunashli (ACG) fields in the Azerbaijan sector of the Caspian Sea. The MZWIP has ultimately proved a unique method of using intelligent completion interval-control valves (ICVs) in place of traditional sand-control completions. Four years after MZWIP implementation, nine wells with a total of 25 zones are injecting at required rates with zonal-rate live reporting across all five ACG platforms. To achieve the 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 and perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world’s first 10,000-psi four-zone inline variable-choke DHFC wells with full surveillance across each zone including pressure, temperature gauges, and fiber-optic distributed temperature sensors (DTS). The development of this MZWI solution has significantly changed the ACG development plan and has been quickly expanded across all five ACG platforms. Accessing up to four 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. This could not be achieved by drilling more single-zone C&P injectors as it would erode business value through platform slot use, additional well costs, and slowing down field development. Multizone injection, therefore, became a necessity.

Currently, ultradeepwater single-trip multizone completions are commonly run (Techentien et al 2016). Looking forward, improvement and progress can be achieved by using run history, lessons learned, and best practices. In the Lower Tertiary of the Gulf of Mexico, multizone completions in which differential pressure ratings of 15,000 psi are necessary, all operational stages should be considered, including stimulation treatments and production depletion. To date, little information is published about specific downhole component design methods or standard qualification processes required by operators and/or service companies. The objective of this paper is to help educate the industry by presenting the approach of one service company to address the 15,000 psi Lower Tertiary challenge. This paper discusses the innovative qualification processes of all subsystems, including the intelligent upper completion, interfacing intermediate completion, and the sandface lower completion. The proven success of the industry-standard 10,000-psi generation IV (Clarkson et al. 2008) multizone frac-pack system (Grigsby et al. 2016) provides an installation and operating standard that is used as a basis for a 15,000-psi pressure-rated multizone system. Operators were interviewed, internal discussions with all stakeholders were conducted, and thorough reviews of current and future regulatory standards were completed to develop this methodology. This paper presents the results of these discussions and reviews the downhole components using a detailed qualification process. It also discusses the test procedures for full system validation to satisfy operator and regulatory requirements. The result is a reliable 15,000-psi differential, single-trip multizone system that incorporates an intelligent completion string for interventionless zonal isolation, control, and monitoring over the life of the well.