Variations in production rate and future tie-ins were two factors that influenced the design of large OD flowlines for carrying gas ashore from subsea-completed deepwater fields in the Mediterranean Sea, about 90 km (56 miles) off Egypt (Fig. 1).
At the recent Offshore Technology Conference in Houston, Tom Choate, Intec Engineering project systems manager for Scarab and Saffron fields, said "Flow assurance and operability under these changing conditions are critical."
The design integrates flow assurance and operability of the wells, reservoir, subsea equipment, control system, flowlines, and onshore facilities.
Choate indicated production rates in the system will vary between 8 and 100% of total system capacity, and therefore the design required a lot of front-end planning and innovation to avoid unacceptably high transient liquid flow rates. He added that elements of the flow assurance strategy include effective use of hydrate inhibitors, including glycol, which the operator will inject continuously into each subsea well, and the installation of state-of-the-art production monitoring systems to accommodate the varying production rates and gas plant requirements.
Intec manages the detailed planning and installation of the subsea equipment and pipelines for the operator, Burullus Gas Co., a joint venture of BG-Egypt SA, 25%, Edison International SPA, 25%, and Egyptian General Petroleum Co. (EGPC), 50%.
Project overview
The 56 mile tie-back is not a record length, but this is the first long tie-back with large OD lines. Previous long tie-backs, such as in the Gulf of Mexico, have 12-in. or smaller pipe.
Installation of the lines is under way and Burullus expects first gas to flow in 2003 from the Scarab and Saffron fields.
The $700-million development (Fig. 2) calls for eight initial subsea wells in Scarab and Saffron in water depths up to 2,040 ft, increasing eventually to about 12 wells. The wells will flow through 2-4 mile, 10-in. lines to one of two subsea production manifolds in about 1,300 ft of water. Each manifold handles four wells, and a crossover spool links the two manifolds. An additional manifold would be required if more wells are drilled.
Two 20-in. lines connect the production manifolds to a pipeline end manifold (PLEM), about 12.5 miles closer to shore in 312 ft of water. A crossover, normally open, allows for the commingling streams from the two production manifolds.
Between the PLEM and onshore gas plant are 24 and 36-in. lines.
Burullus plans for future fields to tie in at the PLEM and it has sized the system to handle future production of about 1.8 bcfd. It expects the Scarab and Saffron fields to produce about 600 MMscfd through the 24-in. line for the first 4 years. As reservoir pressure decreases, it will flow the gas through the 36-in. line. The design allows the system to operate at sustained flow rates as low as 150 MMscfd.
Simian and Sienna fields will be the next subsea development to tie into the PLEM. These fields will have a 70-mile total tie-back length (Fig. 3). Burullus says it initially will produce these fields with 6 wells, eventually increasing to 18 wells, in water depths up to 3,600 ft. Burullus expects the field to start up in mid-2005. The development includes a shallow-water controls platform.
The Sapphire field is the third development that will tie into the PLEM, with production starting in 2006.
Burullus will sell the Scarab and Saffron gas to the local Egyptian market, while the gas from the other fields will feed future LNG plants.
OGJ, May 20, 2002, pp. 20-23 provides more details of the development and exploration activities in the East Mediterranean area.
Operations
A presentation by Steven W. Cochran and Amrin F. Harun at the recent Offshore Technology Conference explained some of the complexity involved in designing the flowline system.
It says transient multiphase hydraulic models simulated the operations and helped define operational boundaries.
The presentation described the gas from Scarab and Saffron as relatively lean (2.5-5 bbl/MMscf) and saturated with water at reservoir conditions. Individual gas wells have the potential for producing more than 100 MMscfd although the operator expects typical flow rates of 75 MMscfd/well, with minimum rates of 25-35 MMscfd/well.
The operations involve injecting glycol with entrained corrosion inhibitor continuously at each subsea tree to prevent hydrate formation, while methanol injection will inhibit hydrate formation during well start-up and shutdown.
The onshore facilities include all gas and liquid processing and treating facilities for water handling, methanol and glycol (MEG) reclamation, and MEG-corrosion inhibitor injection that will be sufficient for expected liquid production in early years and will be expanded as needed by increasing water production in later years.
The plans include adding compression onshore to maintain production rates as reservoir pressure declines. During early operations, Burullus expects a 1,275 psi arrival pressure at the plant.
The subsea production control system is onshore and integrated with the overall plant control system. Two umbilicals, one electrical and one hydraulic, and a 4-in. glycol line deliver the power, control functions, and chemicals to a subsea distribution assembly (SDA) adjacent to the production manifolds.
Infield umbilicals and flying leads transport power, controls, and chemical injection from the assembly to wells and manifolds.
Because Scarab and Saffron reservoirs are poorly consolidated sandstones, the development minimizes reservoir drawdown by completing each well with an openhole single-zone gravel pack. Wells generally have 7-in. tubing, although some wells have 5.5-in. tubing.
The wells have downhole venturi meters for monitoring gas production and sand detectors on each tree for detecting sand production. Burullus plans to restrict a well's production rate or shut in the well if it detects sand.
The design anticipates the condensate-gas ratios and water production to change significantly with reservoir depletion. Intial 0.25 bbl/MMscf water production may double in a few years. The system's design can handle 20 bbl/MMscf of produced water from each well but expects only 2 bbl/MMscf water production.
Burullus considers the potential for salt and scale deposition from formation water production to be low, and it is not concerned with asphaltene or wax deposition, and foam or emulsions.
The system design can handle up to 1.0 mole% CO2, although less is expected. The fields are expected not to produce any H2S, although Burullus indicates the materials used can tolerate some H2S.
The presentation indicates that ramp-up procedures have been carefully developed to prevent exceeding the onshore slug catcher and liquid-handling system capacity. It adds that the other principal driver of the operating envelope is the prevention of hydrate formation.
Liquid handling is another concern because during early operations the gas density, at high pressure, will be high and the resulting gas velocities will be low, causing high liquid holdups. Later in life, the lower flowline pressures will result in lower gas densities and higher gas velocities.
