The well, flowline, and midline hardpipe jumpers utilized for the Troika subsea production system represent a significant and challenging engineering and construction effort. The system was designed using a horizontal connection method, which is common to all three jumper types. Each of the two 10–3/4 in. OD flowline jumpers that connect the flowlines to the cluster manifold system incorporates a load-limiting joint. Additionally, the flowline and midline jumpers have to allow for significant thermal elongation of the flowlines. The 5-9/16 in. OD well jumpers used to connect the subsea trees to the manifold include not only a production conduit, but hydraulic and chemical injection lines. The production pipe is also insulated. The effect of vortex-induced vibration (VIV), insulation design, flexibility, and rig installation of the jumpers will also be discussed. Introduction The Troika subsea production system is a cluster-type development in 2,700 ft of water in Green Canyon Block 200 in the Gulf of Mexico.1 The manifold is tied-back to and controlled from Shell's Bullwinkle platform, which is approximately 14 miles to the northwest. The two are tied together by means of two 10-3/4 in. OD flowlines and separate hydraulic and electrical umbilicals (Fig. 1). The two flowlines, were installed as a four-part towed bundle.2 Each section is approximately seven miles long. The four flowline sections were connected approximately at the midway point with the midline jumpers. The decision was made to utilize the GC-200 #1 delineation well previously drilled by Marathon, so the template/manifold would have to be located so as to allow completion and connection of that well to one of the system's eight slots. Since the GC-200 #1 well did not encounter any shallow water flow problems, it was felt that locating the remainder of the Troika wells in close proximity to that well would maximize the probability of the same results. Well spacing was driven primarily by the desire to eliminate gyroscopic surveys of the shallow portions of the wells, thus creating the need to separate the wells and template piles enough to prevent magnetic interference. A minimum separation of fifty-five feet was needed, so the proposed well locations were set at a separation of 60 ft ± 2.5 ft. Additionally, the well locations were chosen so as to provide a clear area adjacent to the flowline end of the template/manifold for jumper connections to the flowlines, and to minimize the possibility of impacting a well if a flowline were to be snagged and pulled loose. These same considerations were given to the area adjacent to the pigging loop end of the template/manifold due to the possibility that the Troika system would be expanded into another area. This possibility was, however, given less weight in that a more restricted access corridor was preserved for the pigging loop end than for the flowline end. Common components of all three jumper types are the hub termination assembly, the hub support alignment structure (HSAS) and the jumper pipe itself (Fig. 2). The hub termination assembly contains the hub used to seal the various conduits and is manufactured from a solid forging. The well jumpers were designed using stainless steel since they were on the upstream side of the manifold corrosion inhibitor injection points.

The Troika flowline system consists of two 10.75-in. outside diameter 14 mile long pipe-in-pipe insulated oil lines installed by the bottom tow method. The pipe-in-pipe configuration was selected to achieve the required flowline insulating properties. The thermal performance of the flowline system did not meet design expectations. As a result, the risk of hydrate formation at the onset of produced water may negatively affect operability of the flowlines. This paper addresses the evaluation and testing performed to identify the problem and the proposed plan to remediate the Troika flowline insulation system. Introduction Troika is a deepwater (2700-ft) oil development located in the Gulf of Mexico approximately 150 miles south of New Orleans, Louisiana. The reserves are being recovered through an 8-slot manifold cluster subsea production system in Green Canyon (GC) 200 tied back to the Bullwinkle platform in 1,350 ft. water depth in GC 65. Commingled flow from the wells is being produced to Bullwinkle through two 14-mile long 10.75-in. diameter pipe-in-pipe insulated flowlines. Well control is maintained with an electrohydraulic control system through separate electrical and hydraulic/chemical umbilicals. The two 14-mile long flowlines were installed by the bottom tow method in four, 7-mile long segments. Each 7- mile segment was fabricated at a beach makeup site, laterally launched, bottom towed 400 statute miles through a maximum water depth of 3,200 ft., positioned in the field and connected. Connection to the Bullwinkle platform entailed lifting the riser end to the surface and securing it to the jacket leg in a catenary configuration. Insulated steel pipe jumpers were used to join the 7-mile sections at the midline and subsea manifold locations. An overview of the Troika flowline system is shown in Fig. 1. Further details on the Troika system can be found in Refs. 1 and 2. The flowline system was installed during the summer of 1997 with first oil on November 11, 1997. After startup it was discovered that the arrival temperature of the produced fluids at the host platform was about 50?F lower than expected. An investigation into the cause of the low arrival temperatures was carried out in 1998. The investigation included analysis, field measurements and land tests of an 80-ft. section of the Troika flowline bundle. In addition to evaluating the cause of the poor thermal insulating properties of the flowline system, a remediation plan was developed. Flowline System Description The Troika flowline system is depicted in Fig. 1. The upper part of the figure shows the field layout and the lower part shows the various components along the flowline bundle. The Steel Catenary Risers (SCRs) at the Bullwinkle Platform are a pipe-in-pipe configuration with a 10.75-in. × 1.024-in. production line inside a 18-in. × 0.5-in. outer casing pipe. The 10.75-in. production line is surrounded by a 2-in. thick layer of 2-pcf open cell polyurethane foam. The foam consists of 6-ft long half shells that are secured to the 10.75-in. production pipe using tape and plastic straps.

Troika is a deepwater (2,700 ft) oil development located in the Gulf of Mexico approximately 150 miles south of New Orleans, Louisiana. The reserves are being recovered through an 8 slot manifold cluster subsea production system1,2 in Green Canyon (GC) 200 tied back to the Bullwinkle platform in 1,350 ft water depth in GC 65. Commingled flow from 5 initial wells will be produced to Bullwinkle through two 14mile long 10-in. diameter pipe-in-pipe insulated flowlines. Well control is maintained with an electro-hydraulic control system through separate electrical and hydraulic/chemical umbilicals. The two 14 mile long flowlines were installed by the bottom tow method in four 7 mile long segments. Each 7 mile segment was fabricated at a beach makeup site, laterallylaunched, bottom towed 400 statute miles, positioned in the field and connected. Connection to the Bullwinkle platform entailed lifting the riser end to the surface and securing it to the jacket leg in a catenary configuration. Insulated steel pipe jumpers were used to join the 7 mile sections at the mid and subsea manifold end points. This paper presents the design, fabrication and installation of the Troika flowlines. Introduction The Troika subsea development is depicted in Fig. 1. Two identical 14 mile long pipe-in-pipe insulated flowlines deliver the well fluids (37° API oil with a Gas-Oil-Ratio of approx. 1800 scf/bbl) from the subsea manifold to the Bullwinkle platform. Each 14-mile flowline is comprised of two 7-mile bundle segments connected together with a midline jumper. The first 7-mile segment consists of the 2,400 ft long steel catenary riser (SCR), flowline bundle and midline sled. The second 7-mile segment consists of a midline sled, flowline bundle and manifold sled. The SCR at Bullwinkle is comprised of a lO-in. production pipe inside an 18-in. casing pipe. The flowline bundle is comprised of a lO-in. production pipe inside a 24-in. casing pipe. By use of a pigging valve and well isolation valves on the subsea manifold, the two flowlines can be isolated for selective well flow or made into a continuous loop for round trip pigging from the Bullwinkle platform. The inset view in Fig. 1 shows the cross section of the pipe-in-pipe configuration along the flowline. The pipe-in-pipe design is utilized to achieve the thermal insulation properties needed to mitigate against paraffin deposition and hydrate formation. The Integrated Project Team (IPT) provided the overall project management and coordinated the design, tow route survey, procurement, fabrication, installation, connection and hydrotest phases of the project. Preliminary engineering for the flowlines began in the 1st quarter of 1996 when both lay and tow methods were evaluated. The towed bundle installation method was selected for the flowline installations in August 1996. The first 7 mile bundle was completed and launched 11 months later in early July 1997. All bundle installation, connection and hydrotest activities were completed successfully by the end of October 1997. First oil was produced November 11, 1997. Like all previous tows in the Gulf of Mexico, the flowline bundles were fabricated along the beach on the Matagorda Peninsula. After fabrication, each 7-mile bundle was cradled into the surf and charged with nitrogen.