Deep High-Pressure Completions: A Case History Offshore Gulf of Mexico

Topics: HP/HT Offshore

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A Gulf of Mexico case history is presented describing the successful delivery of two deep high-pressure high-rate-designed oil wells in an ultradeepwater environment. Well conditions, coupled with challenging production requirements (depletion of 10,000 psi), posed an arduous design challenge. More than two dozen firsts for the operator, and indeed for the industry, were required to deliver the final completion designs.

Introduction

The Gunflint field is located in five Mississippi Canyon blocks in approximately 6,100 ft of water. The discovery well (MC948 2) was drilled in 2008. The field contains stacked Middle Miocene age reservoirs between depths of 23,800 and 27,000 ft true vertical depth subsea. A mixture of black oil, rich gas condensate, and dry gas has been penetrated in seven reservoirs. Only three oil reservoirs, Green B, Green C, and Blue E, are considered commercially viable for development. Reservoir pressures and temperatures range from 17,000 to 19,000 psi and from 210 to 240°F, respectively. Petrophysical analysis determined that the primary reservoir sands are high-quality sandstones with good permeability.

The development plan consists of two subsea wells tied back to the Gulf Star I platform. The first well (G4, the “Blue” well) is a twin to the original discovery well in the top of the structure and targets the Blue E horizon as a single completion.  The second well (G2, the “Green” well) is a sidetrack of the original discovery well targeting the Green B and C reservoirs in a dual commingled smart completion.

Initial well productivity was designed for 15,000 BOPD for the Blue well and 20,000 BOPD from the commingled Green well. Instantaneous initial total oil potential is expected to be between 30,000 and 35,000 BOPD, and each well will have a dedicated 6-in. pipeline for flowback to the host facility. However, the expected total field plateau rate is 25,000 BOPD owing to capacity limits at the remote host. Specifically, the project’s statement of requirements stipulated that G4 was to deliver a production capacity of 15,000 BOPD at a skin (production efficiency) of less than 3, while G2 was to deliver a production capacity of 20,000 BOPD (combined) at a skin (production efficiency) of less than 3.

Completion-Delivery Process

This project used a field-proven ­completion-delivery process comprising four sequential phases: right design, detailed engineering, equipment integrity, and flawless execution.

Right Design. A project-level diagram (Fig. 1) summarized technology challenges. Red indicates a design that is not available but is less than 2 years away. Orange indicates a design that is available but has no run history, and yellow indicates a design that is available but has a history of no more than three runs. The engineering objective was to eliminate the red and orange by in-depth analysis and qualification of the equipment design.

Fig. 1—Completion technical assessment and design challenges (initial and final). SCSSV=surface-controlled subsurface safety valve.

 

Detailed Engineering and Equipment Integrity: The Detailed Design Review (DDR). The DDR is a bridge between the second and third steps. It is captured under equipment integrity but often requires a significant presence in the detailed engineering phase. For the project presented in the complete paper, the DDR is considered to be the single most important contributor to the success of the project. A DDR can take many forms, but, in general, it is a comprehensive and in-depth process of evaluating equipment on a component-by-­component basis to ensure that each part is fit for purpose.

A DDR was performed on every part of the permanent downhole equipment. Approximately 14 DDRs were performed and a total of 59 changes were made. Every piece of equipment had at least one change when compared with the originally proposed setup. The only downhole equipment failures and the two highest nonproductive-time (NPT) events occurred, in fact, on service (rental) tools upon which DDRs were not performed.

Lower Completion. Perforating. The perforating-tendering process revealed that most vendors did not offer equipment rated to Gunflint’s high-pressure requirements. After significant technical analysis, the perforator with the largest area open to flow was selected. With low skin as a significant driver, considerable technical analysis was conducted to determine methods to mitigate formation damage and debris plugging of the perforations. Ultimately, underbalanced perforating (1,000 psi) on an open choke and flow (surge=25 bbl) was recommended.

Frac Pack. On the basis of a review of fields analogous to Gunflint, it was determined that the expected surface treating pressure would exceed 11,000 psi for Well G4. An effective mitigation for high surface pressures is to use a weighted fracturing fluid. By selecting an 11.5-lbm/gal sodium bromide base fluid vs. the conventional 8.7-lbm/gal sodium chloride fluid, the surface pressures were reduced by approximately 4,000 psi. Extensive testing was performed to confirm formation and fluid compatibilities, to avoid damage.

The results of the G4 acid job were very encouraging. Several pressure break-backs were realized, and the pump rate was increased for diversion. The final rate at the end of the acid job was 15 bbl/min at 6,500 psi. It was later determined that fluid was being distributed over the entire interval on the basis of the interpretation of the downhole wash-pipe gauge data. The fracturing gradient was determined to be 0.770 psi/ft (less than expected). Therefore, a conventional base fluid was used on the next two intervals in Well G2.

Interface. The extreme completion depth and pressure posed numerous engineering challenges. One example was the risk of failure of the gravel-pack (GP) packer as the Blue sand depleted. The purpose of the GP packer is to ensure that the annular pack stays in place during production. The GP packer for this application had a maximum differential rating of 10,000 psi. To ensure well integrity, a bona-fide production packer was positioned above the GP packer. The authors’ engineering analysis indicated that this would trap a hydrostatic pressure of approximately 19,000 psi above the GP packer, thus creating a significant differential load across the GP packer as the reservoir depleted. This could lead to a mechanical failure and loss of reserves.

Selection of the Burst Disk. This option was risk-assessed, and the team decided it was worth the cost of testing to determine if the rupture disk and drain sub were fit for purpose. The testing confirmed that the disks did not burst during the forward pressure cycle. The testing further confirmed that the disks ruptured during the reserve pressure cycle at an average pressure of 6,122 psi (well below the packer rating) and within a tolerance of only 1.32%. Because of the positive results, the disks were incorporated into the completion design. The cost savings were estimated at USD 2.1 million as a result of the use of a USD 172 rupture disk.

Upper Completion. Control-Line-Routing Drawing. The objective of a control-line-routing drawing is to align all the control lines to ensure correct clamp designs and to ensure that the tubing-hanger (TH) makeup is as simple as possible. Even though this process is simple, it is often not performed or is performed incorrectly. Common mistakes include looking at bottom-up vs. top-down orientations of control-line clamps as compared with the TH design. All of the detailed engineering performed ahead of time ensured that the running of the upper completion was a smooth and efficient process. 

Control-Line Bypass Slots. A DDR was performed on the control-line slots, which align the control lines with the lower intelligent control valves of the packer. An outcome of the DDR was a change of the slot orientation. The consequence of this orientation change was not revealed until shop assembly makeup, at which point it was found that a control line passed directly over a flow port. Four options were considered for correcting the issue; ultimately, a “dog-ear” clip was selected to reposition the line to the far side of the slot, thereby rerouting the control line away from the flow port. The modification was made to all equipment before deployment. This finding highlights the fact that DDRs must be holistic.

Flawless Execution. Well G4 was completed in 52.6 days. The overall efficiency of the operation was 52% productive time, with 25.4 days (48.3%) of NPT. However, the bulk of the NPT was the result of waiting on loop currents. Evaluating the well without weather and loop currents, the overall efficiency was, in fact, 97% productive time, with only 0.8 days (2.8%) of NPT. The Rushmore Review database was used for benchmarking the execution of the Gunflint completions. The wells selected for benchmarking met the following criteria:

For the purposes of benchmarking and performance analysis, the selected data considered only the completion phases. Rig mobilization and demobilization and the running and pulling of the BOP stack were not included. On the basis of the Rushmore Review database, Well G4 is the fastest single-GP completion with the lowest NPT for all wells.

Well G2 was completed in 38.9 days. The overall efficiency of the operation was 79% productive time, with 8.3 days (21.4%) of NPT. When evaluated without weather-related or rig-equipment issues, the overall efficiency was 85% productive time, with only 5.2 days (14.5%) of NPT. On the basis of the Rushmore Review database, Well G2 is the fastest single-selective-GP completion with respect to well depth. On the basis of comparisons in Fig. 18 of the complete paper, Well G2 was the second-fastest completion; normalizing for depth makes G2 the fastest completion of those shown, on the basis of days per 1000 ft MD.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 181557, “Pushing the Completion Design Envelope in Ultradeepwater: Design, Installation, and Performance of Deep High-Pressure Completions—A Case History of the Gunflint Development, Offshore Gulf of Mexico,” by Jack Sanford, SPE, John Healy, SPE, Tim Hopper, SPE, Josh Fink, SPE, Ladd Grammer, SPE, James Koy, SPE, Jocelyn Perroux, SPE, Ian Magin, SPE, Kevin Williams, and Tom Seeley, Noble Energy, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.

Deep High-Pressure Completions: A Case History Offshore Gulf of Mexico

01 September 2017

Volume: 69 | Issue: 9