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Application of Multizone Water Injection Downhole Flow Control Completions With Fiber-Optic Surveillance

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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 nonstandard 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.

ACG Injector Design Evolution

ACG has evolved over several water-injection design iterations: commingled C&P, commingled openhole gravel pack, commingled expandable screen (ESS), ESS with DHFC, and single-zone ESS (Powers et al. 2006). Over the years of operations and surveillance, these completion designs have experienced two main issues:

  • Poor conformance: Water exits at casing shoes or high-perm layers only.
  • Well sanding is due to crossflow in commingled completions.

The DHFC C&P completions with automated shut-in control algorithms designed into the surface control panel solved both of the two major issues. Scaling up for two-, three-, or four-zone designs without traditional sand control, the challenge of mitigating crossflow and sand management required an integrated approach across subsurface, wells, topsides, and operations.

  • Subsurface: The fracture propagation concept is applied individually to each zone, with stable injection conformance regulated via DHFC. With DTS across each zone, surveillance and control of fracture propagation, conformance, and zonal integrity is achieved.
  • Well Design: Tubing-convey perforation techniques have been switched to overbalanced (dynamic underbalanced) perforating with managed well losses. The ACG DHFC design has been upgraded for 10,000 psi and can be expanded to four independently controlled zones. Each zone annulus volume offers nominal sand sump for potential sand ingress and determines zonal “life” based on empirical sanding data from ACG single-zone logs.
  • Topside: A dedicated platform-surface hydraulic system (SHS) is responsible for providing the hydraulic power and all logic controls needed to drive the ICVs downhole. The SHS automatically instigates timely closure of all but one ICV when a planned or unplanned shutdown occurs—the first line of defense to isolate zones from crossflow, minimizing sand ingress and improving well reliability. The automated logic controls and smart interlocks minimize human error, reduce workload, and improve operation reliability and safety.
  • Operation: Training sessions were conducted to implement this new operational capability. Simplified illustrated procedures along with a web-based module have helped Operations to quickly and easily become familiar with the system. Procedures are tailored to a specific task to ensure they can be easily followed, enabling offshore operators to utilize the system successfully and effectively. With subsequent platforms being introduced to this MZWI design, a continuous-improvement process has naturally developed across the offshore and onshore teams.

MZWI Well-Completion Design

The DHFC equipment for the MZWIP wells was selected and customized, considering the long-term goals of the project: life-of-well reliability, multisensor monitoring, scalability (>two zones), and rate conformance (choke design). Additionally, the design of the DHFC system must be well understood for its limitations, operating principles, and functionality in order for the operator to realize the full potential and maximize the asset value. This works most effectively when both service company (Halliburton) and operator (BP) work as a team and can trust each other, share lessons learned, and be open to new applications.

To meet the requirements of the project, several DHFC technologies were selected, including variable-choke HS‑ICVs for high-differential pressures, HF1 multiline feedthrough packers, multiple ROC downhole sensors packages (tubing/annulus pressure and temperature and choke positioning), and a turnaround sub for pumpdown fiber cable. Each technology was also required to be “plug and play” for two to four zone completions.

Special focus was given to the following design aspects for the ACG DHFC system:

  • 10,000-psi all-around pressure rating
  • 40–275°F qualified
  • Custom discrete choke with the AccuPulse control module
  • HS ICV radial metal-to-metal (MTM) seal capable of up to 5,000-psi differential opening (Fig. 1a)
  • HS ICV choke-position sensor communicating in real time to deliver zonal flow allocation
  • HF1 V3 rated 10,000-psi production packer with seven-line feeds (Fig. 1b)
  • Control-line vibration—plumbed lines reconfigured away from ICV flow paths, packed, and no MTM contact allowed to maximize line integrity for life of well
  • Erosion-resistant alloys and a proprietary erosion-simulation study to ACG requirements
  • ROC hybrid pressure and temperature gauges with multiline bypass slots
  • HS ICV capability to quickly move to a closed position in a single-pressure pulse
Fig. 1—(a) HS ICV and (b) HF1 packer.

 

If not protected, high-rate water injection will induce significant mechanical and flow-induced vibration on control lines and connections. The placement of fittings, bare control lines, and flatpack across the completion is critical to the success or failure of the downhole equipment. For example, ICV deflectors, installed to protect for casing blast erosion, point the flow downward at a 90° change in direction toward the perforations. Placing bare control lines, or fittings, near this high-energy area is a recipe for failure. Thus, the MZWI DHFC completion design was reconfigured in such a way that only intact flatpack is now exposed to flow, and bare control lines close to the ICV exit are removed from the flow path and packed with Teflon.

Survivability of the completion string was determined, analyzing each component at the weakest wall section and performing proprietary erosional limits method calculations. This modeling, that considers both sand concentration and complex geometries, confirmed all components capable of handling produced water reinjection with a sand content of 3.5 lb/1,000 bbl for a minimum of 15 years injection at 35,000 BWPD.

Thereafter, a well-performance study was undertaken to identify the required controlled-rate range of the ICV choke trim that would effectively balance injection between several reservoir layers. Multiple P10-P50-P90 injectivity scenarios were used to test the ability of various discrete choke trims to manage injection uncertainties and offered good choke resolution across the entire ACG field. Once the ICV choke design was selected, an additional study was conducted to determine overall ICV system performance adjustment due to choke and flow-deflector frictions, enhancing zonal flow-allocation calculations with a less than 15% error vs. surface flow metering.

DHFC installation started in 2016, planned as a four-well trial targeting only two zones. On the first two wells, a lower packer and intermediate completion was installed to mitigate ­anticipated brine losses, and the stacked DHFC upper completion was installed without DTS facility. With post-perforation brine losses deemed manageable, and large-bore drilling de-risked, a third well was drilled with 9⅝-in. casing installed across the reservoir. This enabled the inline-type DHFC completion with DTS to be installed without lower/intermediate completion runs. Successfully installed with precise fluid-loss monitoring, all subsequent completion installations are run as inline and increased in functionality to four-zone access in 2019; as of June 2020, two 4-zone DHFC completions have been installed successfully in ACG.

The next phase of the MZWI project will be tailored for slot recovery and sidetrack workovers. To meet the needs of slot-constrained platforms, a slimhole inline 10,000-psi DHFC design is required in a 7⅝-in. liner size and will require a new, qualified multi-feedthrough packer and a slimhole ICV design for up to four zones with DTS.

References

SPE 196231. Application of Multizone Water Injection Downhole Flow Control Completions with Fibre-Optic Surveillance in Soft Sand Reservoirs by D. Nguyen, I. Macleod, and D. Taylor, et al., BP; and D. Booth, Fircroft Consultant, et al.
SPE 98146. A Critical Review of Chirag Field Completions Performance–Offshore Azerbaijan by B.S. Powers, BP plc, B.M. Edment, Schlumberger, and F.J. Elliott, BP plc, et al.

Jonathon Joubran is the global product manager of intelligent completions for Halliburton. He holds a BS in mechanical engineering from Kettering University.

Application of Multizone Water Injection Downhole Flow Control Completions With Fiber-Optic Surveillance

Jonathon Joubran, Halliburton

01 August 2020

Volume: 72 | Issue: 8

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