How Marathon is developing its deepwater Gulf of Mexico field
How Marathon is developing its deepwater Gulf of Mexico fieldArnold field uses a multi-well, clustered manifold subsea production system and unique pipe-in-pipe insulated flowlines to produce oil from 1,750 ft watersLee Nirider, Senior Production Engineer, Marathon Oil Company, Houston; and Allen Verret, Engineering Advisor, Texaco North American Producing, New Orleans.
Field Overview Arnold field is located in Ewing Bank Block 963 in about 1,750 ft of water. Marathon Oil Co. and partner, Texaco Exploration and Production Inc., made the discovery in August 1996 with the drilling and testing of well 1. This well test showed the reservoir to contain undersaturated black oil with a 25° API gravity and GOR of 830 scf/stb. Reservoir and bubble point pressures are about 8,200 psi and 4,100 psi, respectively. During the DST, well 1 flowed some 8,000 bopd and had a shut-in tubing pressure of 4,600 psi. Two additional wells were drilled, one of which penetrated oil in commercial quantities. These two wells formed the basis for design of a subsea production system to bring production back to the existing Ewing Bank 873-A platform. This Marathon-operated platform is in 750-ft waters. The Arnold wells are controlled from the platform by a multiplexed, electro-hydraulic control system. Production from each well flows through a single, insulated, rigid flowline jumper into a manifold where ROV-operated valves direct the production into one of two, pipe-in-pipe insulated flowlines. The manifold also contains a removable flowloop that facilitates round trip pigging from the platform and provides a connection point for a future field tie-in. The combined electrical and hydraulic umbilical provides methanol for batch treatment of the trees during transient periods, and batch or continuous downhole chemical injection. The subsea production system is designed for 20,000 bpd. Each pipeline is designed for 10,000 bpd of liquid. Fig. 1 and Fig. 2 show field location and subsea equipment layout. Contracting Strategy The Arnold field development is the first known Gulf of Mexico subsea production system project to use an engineering, procurement, construction and installation (EPCI) contract. A single, multi-national consortium was contracted to provide virtually all the subsea equipment for the project. This contract included the trees, chokes, flowline jumpers, dual insulated pipe-in-pipe flowlines, umbilical, flying leads and control system. This approach leveraged operating company expertise with contractor resources to perform the work. To reduce cycle time, and thus, minimize overall project schedule, existing specifications, quality plans and procedures were adopted where possible. Drawings and procedures were provided for review, but in most cases, not for approval. In summary, the EPCI approach allowed tasks to be worked on simultaneously while maintaining control of critical interfaces. Platform Modifications To accommodate added production from Arnold field, an additional process module was designed, fabricated and installed on the Ewing Bank 873-A platform. Primary added equipment included inlet degasser vessels and heater, primary separator, coalescer / storage vessel, pig launcher / receiver, 2,500-hp sales gas compressor, additional motor control equipment and methanol injection and chemical injection facilities. A dedicated master control station and new programmable logic controllers completed the topside additions. Subsea Wellhead And Tree The Arnold subsea wellhead system is a standard SG-5. Wellheads consist of a 30-in. housing, 18-3/4-in. wellhead, 13-3/8-in. casing hanger and 9-5/8-in. tieback-style upper casing hanger in the middle position in the 18-3/4-in. wellhead. Wellhead tops are about 10 ft above the seabed. After wells were drilled, the drilling guidebase was removed and a corrosion cap installed. Horizontal trees were chosen because they offered advantages in delivery time, cost, simplified installation and workover operations, and absence of a completion riser. The Arnold tree is shown in Fig. 3 and Fig. 4. The main tree valves are 5-1/8-in. and 2-1/16-in. bore for the production and annulus, respectively. The entire tree system is rated for 10,000 psi working pressure. The tubing hanger is designed to suspend 3-1/2-in. tubing for this project, although larger tubing can be accommodated. Tubing hanger, treehead and valves are all weld-overlaid in the seal and seat areas with Inconel 625. All isolation valves, gate and needle, are full stainless steel. The trees were specified to API 17D, PSL 2. The internal tree cap design includes an internal crown plug. This arrangement allows through-tubing access to the wellbore during workover operations without needing a full bore riser to retrieve the internal tree cap. Control of the tree during workover and production modes is provided by two junction plates on the tree. In the production mode, outputs from the production control pod go through the workover plate, into a bridging (crossover) plate and back to the tree functions. In the workover mode, the bridging plate is removed and the workover umbilical connected, thus disabling the production control pod. Tubing installation tools. Tubing hanger installation tooling consists of a slick joint, test tree with two ball valves, hydraulic disconnect and a retainer valve. A dedicated hydraulic power unit and umbilical are provided for controlling the valves and running tool. Surface equipment consists of a lubricator valve and a surface tree head. Flowline jumper connection. Each well is connected to the manifold with a single, 4-in. insulated flowline. The tree-to-flowline interface consists of a vertical mandrel that will receive the mating hydraulic connector on the flowline jumper assembly. The manifold end of the flowline jumper has an identical arrangement. The flowline jumper is a double inverted-U design, Fig. 5. This design provides the flexibility needed to accommodate minor fabrication tolerances as well as movement of the manifold due to thermal expansion of the pipelines. Jumper installation is accomplished by suspending the jumper from a purpose-built lifting frame and lowering the unit over the side of the rig. Guidance is provided by ROV or ADS. Final alignment is provided by funnels on the tree and manifold mandrels. After the jumper is landed, the ROV makes up a hot-stab hydraulic connection and locks and tests each connector in turn. Subsea production choke. Each subsea tree is fitted with a 4-1/16-in., 10,000 psi WP subsea choke fitted with 3-in. trim. The subsea choke incorporates an ROV-assisted retrievable insert and actuator package. The choke is a cage-and-plug design with a balanced stem and contains tungsten carbide and 17-4 PH stainless steel trim components. The choke is pulsed to open or close, but also can be driven closed by a hydraulic motor. The choke can be driven from fully open to fully closed in less than one minute. Remote position indication is by means of a 4-20 mA transducer. Local position indication is by means of a dial and pointer that is mounted for ROV viewing. Instrumentation. Each tree is equipped with three transducers for measuring:
Each sensor is connected to the subsea control module receiver plate by twisted-pair conductors inside a dielectric-filled hose. Each well is fitted with a downhole pressure, temperature and flowmeter (DHPTF) that consists of three pressure transducers and one temperature transducer. Two pressure transducers are located above and below a venturi, just above the production packer. The third pressure transducer is located about 500 ft above the venturi. The lower components measure flowrate as a function of differential pressure. The third pressure transducer provides a means of measuring fluid density and thus water cut. Since reservoir pressure is well above bubble point pressure, this system is expected to provide fluid rate and water cut data for the life of the field. Control System The Arnold subsea production system is controlled and monitored by a multiplexed, electro-hydraulic control system comprised of the following main components. Master control station. The MCS provides the main monitor, display and operator control interface with subsea equipment. In addition to monitoring and controlling subsea equipment, the MCS also provides an interface with the main platform control systems, including process control and emergency shut down (ESD). An uninterruptible power supply (UPS) powers the MCS and the subsea equipment. Hydraulic power and chemical supply. Hydraulic power is supplied to subsea equipment by a dedicated hydraulic power unit. This unit delivers the low pressure (3,300 psi) and high pressure (7,500 psi) supplies required to operate tree valves, pigging valve and surface-controlled, subsurface safety valve (SCSSV). Two dedicated chemical injection skids provide methanol and corrosion / wax inhibitor. Umbilical. An electro-hydraulic control umbilical connects topsides facilities to the subsea equipment. The umbilical is a steel-tube-based design, carried down the platform jacket within an I tube. The subsea end of the umbilical is permanently connected to a subsea distribution unit (SDU) that supports hydraulic and electric flying leads to connect the SDU with up to four trees. Additional connection points are provided for supplying a future field with a similar number of trees. The SDU is shown in Fig. 6. The Arnold umbilical is a combined electric and hydraulic type. The hydraulic tubes are all metal with three, 3/8-in. ID super-duplex tubes and seven, 1/2-in. ID zinc-coated carbon steel tubes. The super-duplex tubes are dedicated for supply of high pressure and low pressure control fluid, plus a universal spare. The carbon steel tubes are used for supplying methanol for hydrate suppression, downhole chemical injection and a dedicated annulus monitoring line. Electric cables consist of two twisted pairs for supply of power, and two shielded, twisted pairs for communications. An umbilical cross-section and line list is shown in Fig. 7. Subsea control module. An SCM is installed on each tree to monitor downhole sensors and tree-mounted transducers and control the actuated tree valves. If necessary, modules can be recovered and reinstalled remotely with a guidelineless system. This system employs a hydraulic running tool and is assisted by an ROV. The module will control the state of all the hydraulically actuated valves on the tree, and the downhole safety valves. It also will monitor wellhead pressures, choke position and downhole flowmeter. There is also a downhole flowmeter interface for monitoring and reporting information from the downhole pressure, temperature and flow system. The SCM also controls the hydraulically-operated pigging valve on the pipeline end manifold (PLEM). The SCM has a single, high pressure (HP) hydraulic supply for operating the SCSSV and a single, low pressure (LP) hydraulic supply for operating all valve actuators. Each hydraulic supply passes through a filter element inside the SCM. The LP supply is manifolded to solenoid-operated directional control valves (DCV) for each of the actuated tree and manifold valves. Two DCVs control the choke's open and close functions. The HP supply is connected directly to the DCV, which controls the SCSSV. The dual electrical power conductors and communication conductors are consolidated inside the SCM. All components after this consolidation, including the subsea electronics module (SEM), are single, high-reliability components. Manifold The Arnold manifold system consists of three main elements — a skirt-founded subbase, a PLEM, integrated with the flowlines, and a retrievable manifold module. The subbase and PLEM are shown in Fig. 8. The subbase and the PLEM are joined with a sliding support, which accommodates thermal expansion of the pipelines. The PLEM incorporates the two main headers, three ROV-operated valves and one hydraulically-operated valve. PLEM valves are arranged as in Fig. 9, which allows the pipelines to be isolated as needed during installation and the manifold to be isolated if the removable flowloop is removed for expansion of the system to another field. The remotely-operated pigging valve can be closed to separate the two flowlines and opened to allow round trip pigging. The manifold is designed to distribute production from each tree into the two, 6-in. headers. Production comes via 4-in. flowline jumpers installed between the tree and the manifold. The manifold is provided with four mandrels pointing upward to accept a hydraulic connector on the end of the flowline jumper. From the mandrel, production flows through a 4-in. manifold system that routes production to either of the two, 6-in. headers. Two, 4-in. gate valves per well are opened or closed by ROV to direct flow into the desired header. The two, 6-in. headers are connected by a removable pigging loop at the back of the PLEM. One of the 6-in. isolation valves on the PLEM is the pigging valve. This valve is hydraulically operated with a ROV override. All other valves on the PLEM and manifold are manually ROV-operated valves. Production piping is thermally insulated to retain heat long enough to allow inhibiting the system with methanol after a shut-down. PLEM And Manifold Installation The pipeline end manifold (PLEM) was installed by pulling the pre-installed, 6-in. pipelines up to surface and welding the 6-in. pipelines to the headers on deck of the installation vessel. This approach eliminated connectors or flanges, thus reducing leak paths, cost and complexity. PLEM and attached pipelines were then lowered to the seabed together. The manifold was installed onto the PLEM from the drilling rig. Manifold guidance during installation onto the PLEM was by two guideposts. Once the manifold was landed, hydraulic connectors were activated by an ROV hot stab to connect the manifold to the PLEM headers. Flowline System The flowline and riser configuration was selected to allow steady state production without the need for continuous injection of methanol at the tree or chemical injection downhole. During the drillstem test of well 1, several downhole and surface fluid samples were taken for lab analysis. About 300 bbl of dead crude also were taken for flowloop experiments at Texaco's Live Flow Loop facility in Humble, Texas. Results of these flowloop tests confirmed flow assurance issues established during the lab analysis. For example, the presence of sufficient wax to require pigging was confirmed. Further, pigging frequency was determined to be unacceptably high for an uninsulated flowline. These results required that a piggable, insulated flowline be designed. A detailed thermo-hydraulic analysis of the entire subsea system was performed to size the pipeline and select the optimum insulation techniques for each segment of the flow path. Three operational requirements governed the design:
Based on these requirements, expected well rates and platform arrival pressure requirements, a 6-in. nominal product carrier (inside) pipe and 10-in. nominal outer pipe were selected, Fig. 10. After studying several insulation materials and techniques, rigid polyurethane foam was selected for its excellent combination of thermal conductivity, cost and ease of installation. Fabrication and installation. Fabrication of the pipe-in-pipe pipeline involved four major steps:
After reeling, the barge sailed to location and performed a J-tube pull onto the platform. The pipeline was then reeled off the barge, through a straightening device and down a stinger in an S-lay configuration. This approach provided advantages over conventional lay methods in terms of cost and time on location. Pipeline route selection. The proposed route from the Lobster platform, in Ewing Bank 873, to Arnold field in Block 963, crosses a large sea floor fault scarp in Block 962. The fault scarp is in 1,600 to 1,750 ft of water, is about 1,800 ft long and exhibits local vertical deviations in the order of 100 ft. There also are several additional smaller faults along the route. Since the resolution of the initial bathymetry data was on the same order as the preliminary, which limited span lengths, a high resolution, center line acoustic bathymetry survey was required. In addition, a geotechnical engineering evaluation of soil data was performed to confirm the viability of the scarp crossing. Ultimately, pipelines were laid successfully across the scarp. Operability Operability tasks for the project were focused on interfacing the operation of the subsea system equipment with the operation of the existing host facility (Ewing Bank 873-A) and providing operating personnel with the basis for effective operation of the subsea wells. Products resulting from this work include:
Other tasks included:
Well Completion And Start Up Both of the Arnold wells are completed with multiple frac-packs and pre-packed screens as shown in Fig. 11. The Arnold field achieved first production with the start up of well 1 on May 25, 1998. This well is producing at 10,000 bopd as expected. Well 2 was commissioned to the platform on June 30, 1998, at a rate in excess of 12,000 bopd. Bibliography
Acknowledgment
 The authors
Allen Verret is currently an engineering resource advisor for Texaco's Offshore Division, serves as the company's E&P senior technical advisor on the DeepStar project and is the co-chairman of the Regulatory Committee of the DeepStar Program. After earning a BS degree in civil engineering from the University of Southwestern Louisiana in 1970, he joined Texaco's Offshore District offices in Morgan City, Louisiana, assigned to the then Civil Engineering department. Mr. Verret has been a supervisor in the Offshore Division Civil Engineering department in New Orleans, district civil engineer and assistant district manager in Morgan City and offshore division process manager. Recently, he has been involved with subsea project teams working on the Texaco-operated Gemini, Fuji and Ladybug projects and the Marathon-operated Arnold and Oyster projects.
Copyright © 1999 World
Oil |
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he Arnold subsea
production system is Marathon Oil Co.'s first operated deepwater Gulf of Mexico (GOM)
multi-well field development. System is a clustered well type, with a discrete manifold and
dual, insulated pipe-in-pipe flowlines. The manifold is a three-piece, mud-mat-supported
system with a moonpool-deployable core. It is capable of accepting production from four
wells locally, plus being expanded for an additional four wells via a removable pigging
loop. While this approach has been used on other projects, Arnold field is notable in the
GOM as having the largest reeled pipe-in-pipe flowlines, the first three-part,
mud-mat-supported separable manifold and one of the first compact gas liquid separators.
Lee
Nirider is a senior production engineer in Marathon
Oil's Drilling and Completion Services department in Houston. This group is responsible for
providing technical service and new technology to Marathon's operating regions, worldwide.
He has drilling and completion experience in the Gulf of Mexico, with emphasis on completion
techniques and sand control. He also has experience with large-bore completion design and
installation in the North Sea and was a staff engineer in the Control Systems group on
Marathon's Central Brae subsea development, also in the North Sea. He was chairman of the
DeepStar subsea completion subcommittee and served as a member of the Regulatory Committee.
Recently, Mr. Nirider was involved with Marathon's Oyster field subsea development. He is
also Marathon's internal resource on advanced coiled tubing applications including coiled
tubing completions. Mr. Nirider holds a BS degree in petroleum engineering from the
University of Texas at Austin.
