High-pressure, ultra-long subsea tieback design: overcoming challenges in deepwater Gulf of Mexico

Luis F. Bensimon
Kerr-McGee Oil & Gas Corp.
Janardhan Davalath
FMC Technologies, Inc.

In a joint effort, Kerr-McGee and FMC Technologies Inc., conceived a subsea architecture that would effectively address technical, economical, and operational challenges typical of a high-pressure, ultra-long subsea oil tieback in the deepwater Gulf of Mexico.

This paper illustrates a hypothetical development scenario that is representative of a typical deepwater, marginal oil prospect in the Gulf of Mexico. The selected development scenario consists of an oil field located in 5,800 ft of water. The field is to produce through a subsea tieback to a host facility located approximately 38 mi away. The reservoir fluid properties, pressures, temperatures, and other parameters used in this design are taken from typical, similar black oil reservoirs in the Gulf.

The scope of the study also includes:

• Basis of design

•Flow assurance analysis and recommendations on flow management

•Subsea system design including equipment selection, sizing, and subsea architecture layout

• Capex estimate

• Level 1 project schedule

• Identification of emerging technologies that have the potential to reduce capex and/or opex.

To design an effective long distance oil tieback, flow assurance issues must be addressed. Traditional design scenarios for prevention of hydrates, wax and other flow assurance challenges might include dual pipe-in-pipe insulated flow lines, an option that is not economically viable for many smaller developments.

The alternate development scenario proposed here incorporates a single, electric-heated and insulated flow line in conjunction with a subsea pig launcher. The electric heating system would be used during cold start ups to mitigate the risk of hydrate formation, eliminating the need for injecting large volumes of methanol or other hydrate inhibitor during transient flow regimes.

The electric heating can be turned off after the flow line reaches a steady-state flowing condition and warms up above the hydrate formation temperature. The subsea pig launching capability provides a remedy to remove wax, scale or other types of deposits that may form in the flow line.

To effectively monitor and control the subsea wells and provide power to the flow line electric heating system, umbilicals and associated hardware need to be incorporated into the system. The power supply umbilical is laid in four sections and has a total of seven subsea umbilical termination assemblies (SUTAs) to facilitate connections to the flow line.

Four of the SUTAs include a subsea step-down transformer, dry-mate electrical connector and two flying leads, one for each phase. The electrical flying leads are pre-installed with the SUTAs in a figure-eight pattern and later connected to the mid-line connectors of the pipe-in-pipe flow line heating system.

The flow line sleds have ROV-operated valves for complete isolation of the jumpers from the flow line. These valves shall close during pigging operations or during jumper intervention. They also allow for jumper removal and replacement if necessary. The flow line sleds and jumpers are designed to accommodate movement caused by thermal expansion of the flow lines.

Mounted onto the flow line sled at the end of the flow line, near well number 2 is a 7-in. 15-Ksi high-integrity pipeline protection system (HIPPS). The HIPPS allows design of nearly the entire length of the flow line plus the riser to a much lower maximum design pressure. This results in significant savings in material and installation costs; reduction of hang-off weight on the host platform and improved deliverability of the wells due to the increased pipe internal diameter.

Three risers connect the subsea system to the host production platform, namely: one 8-in. x 12-in. pipe-in-pipe steel catenary riser (SCR), one production umbilical and one electrical power umbilical.

Other modifications required at the host platform include: 8-in. topside piping for the production SCR; interconnection for the production control umbilical and the electrical power umbilical; pig receiver skid; master control station; hydraulic power unit; chemical injection unit; and connection with the existing production facilities, power supplies, utilities, etc. The topsides power generation system must be able to provide power for the flow line electrical heating system through the power supply umbilical. The electrical heating system consumes approximately 2 MW of power during shutdown and cold startups. Typical power supply is 3-phase, 480 V AC. A topsides 11 kV step-up transformer is also necessary.

Simulating the scenario

Steady-state thermal-hydraulic simulations were performed from the reservoir sand face to the topsides to establish system deliverability, flowing pressure, and temperature profiles and to develop the flow assurance strategy. The analysis also established the required chemical treatment program, which is a key operational requirement.

The base case used in the system deliverability analyses considered an 8-in. flow line (1.27-in. wall) rated to a design pressure of 14,000 psi, which corresponds to the well shut-in pressure. An alternate case considered an 8-in. flow line (1-in. wall) rated to a design pressure of 10,000 psi together with a subsea HIPPS. The HIPPS scenario also assumed approximately a 1-mi-long reinforced section, designed for the well shut-in pressure of 14,000 psi.

The system with HIPPS allows for a 13% increase in initial peak flow rate. The higher flow rates with HIPPS are mainly due to the increased cross-sectional area of the flow line. The combination of HIPPS and the higher flow rate results in a significantly higher project NPV based on the estimated lifecycle production for this development scenario.

Although the system design solution presented here was developed for a specific scenario, it also applies, at least in concept, to other ultra-long subsea tiebacks elsewhere with similar conditions.•