Challenges in Designing the Worlds First 15,000 PSI Subsea Completion

Challenges in Designing the Worlds First 15,000 PSI Subsea Completion Dick Grant; Dick Grant ADTI Search for other works by this author on: This Site Google Scholar Greg Sones; Greg Sones ADTI Search for other works by this author on: This Site Google Scholar Steve Speegle; Steve Speegle ADTI Search for other works by this author on: This Site Google Scholar Terrell Clark Terrell Clark Argonauta Energy Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 2001. Paper Number: SPE-71682-MS https://doi.org/10.2118/71682-MS Published: September 30 2001 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Grant, Dick, Sones, Greg, Speegle, Steve, and Terrell Clark. "Challenges in Designing the Worlds First 15,000 PSI Subsea Completion." Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 2001. doi: https://doi.org/10.2118/71682-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search AbstractThis paper describes the challenges confronted and the solutions / conclusions drawn during the completion design and implementation phases of the Gyrfalcon Project, Green Canyon 20, Well #1.OverviewGyrfalcon (JUR-fal-con), Green Canyon 20 Well #1, is the world's first 15,000 psi, subsea, frac pack completion. The well was drilled in 880 feet of water and temporarily abandoned by Shell Offshore Inc. in 1997. Shell believed at the time that the field wasn't large enough to justify immediate development. At a later date Reading and Bates Development Company (Devco) proposed the field could be economically developed using a subsea tieback to the nearby Shell Boxer platform. After a financial agreement was reached, Devco took over as operator to complete the well. (Note: After the well was initially brought on production, Devco sold their interests in Green Canyon 20 to Enterprise Oil Gulf of Mexico Inc.) Applied Drilling Technology Incorporated (ADTI) was selected by Devco to design and implement the downhole completion on a project management basis.This gas well has a bottom hole pressure of 14,752 psi at 17,856 feet md/tvd and a maximum shut-in surface pressure of 12,200 psi. This high pressure required a 16.2 ppg ZnBr completion fluid. The bottom hole temperature of 220° F and a low mudline temperature indicated thermal expansion effects may be significant at high production rates. There were 82 feet of perforations in a relatively straight hole. Associated condensate was expected at 46 bbls/mmcf. There is some CO2 and water production. The well was frac packed and tested prior to the installation of production tubing. The well was completed with 3-1/2", 13 chrome, production tubing. It's a 2.8 mile tieback to the production platform through a 6" flowline.After assignment of project management responsibilities, completion review and analysis began in earnest. As a small independent operator with limited staff, Devco focused on reliability, rather than redundancy or innovation. Although conventional methods are the preferred option, the extreme well pressure presented special design problems. Some of these challenges resulted in unique tools and complex completion procedures.This paper lists some of the technical issues confronted, notes the decision making criteria, and describes the solutions and conclusions.Technical Issues15,000 psi Monobore TreeThe tree design was finalized prior to the initiation of the well completion design. The use of a unique 3–1/16"×15,000 psi "monobore" tree assisted in economic feasibility and enhanced delivery. This tree was adapted from an existing 10,000 psi mudline tree design and was the first of its kind. It was estimated that engineering and manufacture of a dual-bore tree design would take an additional eight to twelve months and incur a 70–100% increase in cost over the "monobore" design.This "monobore tree" presented special considerations in procedures and other equipment design. Due to reduced annulus access when the tree is installed, unique procedures were incorporated relevant to the final packer fluid displacement, the setting of the upper production packer and the venting of casing pressure. Close coordination and cooperation with the tree design team was essential to the success of the project.Tubular Integrity / Thermal Expansion AnalysisEngineering studies revealed potential casing integrity issues resulting from annular pressure build up due to the temperature increase associated with producing the well. Thermal simulations of the anticipated production were initially performed and the resulting temperature profiles were then used as a basis for multi string analysis. This analysis lead to the decision to circulate a gelled fluid behind the tie-back production casing and also to place a calculated volume of insulating gel in the tubing/casing annulus during the final packer fluid displacement. The thermal properties of this gel provide multiple benefits including: reduction of casing pressure build up; reduction of risks related to the formation of hydrates; and reduction of the potential for paraffin deposition in the tubing.When reviewing insulation options, few choices were available due to the limited supply and high cost of some alternatives. The abnormally high well pressure also complicated the issue as the desire to maintain a near "kill weight" annular fluid on top of the production packer could cause too much differential pressure as the well depleted. Ultimately, a heavy and somewhat viscous gelled fluid was selected which was designed to minimize heat transfer due to convection currents.This water based gelled system was compatible with completion fluids and downhole elastomers. It was readily available and cost effective when compared with the alternatives. The displacement procedure was somewhat complex, in part because this gel was one pound per gallon less dense than the fluid below and because the "monobore" tree limited access to fluid paths after the tubing was landed. The gel was displaced to a depth of about 3,800' in the 7-3/4"×3-1/2" annulus and 3,200' in the 10-5/8"×7-3/4" annulus. A spacer of 8.8 ppg ethylene glycol was placed at the top of the tubing/casing annulus as a "bleed off" fluid should annular pressure need to be relieved during. Keywords: society of petroleum engineers, completion equipment, safety valve, proppant, gravel packer, monobore, plug, completion installation and operations, sand control, production packer Subjects: Formation Evaluation & Management, Frac and pack, Drillstem/well testing, Completion Selection and Design, Completion Installation and Operations, Sand Control, Completion equipment, Completion Operations This content is only available via PDF. 2001. 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