Offshore Service Companies Prepare Development Concepts For W. Africa's Deepwater Finds

Jan. 18, 1999
With offshore operators recently chalking up a string of major oil and gas finds in deep water off West Africa, engineering contractors have been preparing development concepts in anticipation of big projects ahead. Delegates attending the Deep Offshore Technology (DOT) conference in New Orleans last November heard how service companies plan to cope with flow enhancement and flow line and riser design problems in West African field developments and how the region is a contender for the first

With offshore operators recently chalking up a string of major oil and gas finds in deep water off West Africa, engineering contractors have been preparing development concepts in anticipation of big projects ahead.

Delegates attending the Deep Offshore Technology (DOT) conference in New Orleans last November heard how service companies plan to cope with flow enhancement and flow line and riser design problems in West African field developments and how the region is a contender for the first offshore gas-to-liquids (GTL) floater.

John Westwood, partner at Douglas-Westwood Associates Ltd., Canterbury, U.K., told DOT delegates that West Africa ranks with the Gulf of Mexico and Europe's Atlantic margin among the world's hottest deepwater plays.

Based on recent work in cataloging the world's deepwater potential, Westwood said that the average depth of future deepwater development worldwide is 766 m, and output from the typical fields would be 35,300 b/d (see article, p. 33).

He said that this average would mask considerable variation: While some deepwater fields would produce as little as 20,000 b/d of oil, a typical deepwater West African field would produce an average 95,000 b/d from a floating production system with 30-40 wells in about 300 m of water. This average development would be expected to cost $1.1-2.2 billion.

Flow enhancement

Nicolas Poirier of Doris Engineering, Paris, told DOT delegates that many deepwater finds in recent years have reservoir characteristics which lead to rapid tail-off of production with increasing water cut, unless preventative measures are taken (Fig. 1 [43,445 bytes] and Fig. 2 [42,972 bytes]).

The author said these discoveries are typically characterized by a hydrostatic reservoir with active water drive, rapid water cut increase, and a shallow reservoir below the mud line, in some cases with the water depth of the same order of magnitude as the reservoir depth below the mud line.

He advised that to overcome these problems flow enhancement can be performed either 1) in the wells by electrical submersible pumps (ESPs) or by gas lift or 2) on the seabed, near or inside the riser, taking advantage of the height of the riser and the proximity of the floating production unit to reduce capital expenditure and operating costs (Fig. 3 [127,145 bytes]).

Poirier showed how riser flow enhancement could be achieved in deepwater fields developed with subsea wells and floating production units by using two different principles: addition of mechanical energy by multiphase pumping; and lightening the fluid in the riser by gas-liquid separation, water removal, or gas lift.

The author described the application of these techniques in a case study developed by Doris Engineering for a field development being planned for a deepwater find off West Africa.

The study was carried out to identify the most appropriate flow enhancement solution for an unnamed West Africa field development in 1,400 m of water, to be produced with a floating production, storage, and offloading (FPSO) vessel connected to five subsea manifolds, each with four wells.

Each manifold would be linked to the FPSO by two 8-in. pipelines, with lengths varying from 5 km to 7.5 km including the riser, to allow round trip pigging.

Maximum oil production from each of the 20 wells was reckoned to be 16,000 b/d, while reservoir pressure was 3,915 psi and the reservoir total vertical depth was 2,500 m below sea level.

The reservoir's gas-oil ratio was 170 cu m/cu m, the water cut was expected to be 0-80% reaching 50% after 5 years, and the oil viscosity in the reservoir was 20 cp at 15° C. (Fig. 4 [30,924 bytes]).

The author said three important issues should be highlighted for this West African field, since they are typical for deepwater fields and could have an impact on operating procedures.

First there was the potential for wax formation. The crude oil itself is waxy, and the low ambient temperature and low reservoir temperature require the pipelines to be pigged more than once a month.

There also was the risk of hydrate formation in the production lines, particularly during unexpected shutdowns: "This phenomenon is accentuated in deep water with high pressure and low ambient temperature and requires that the lines be insulated."

Finally there was the need to ensure that the differential between reservoir pressure and bottom hole pressure would not exceed 50 bar to prevent potential damage to the gravel pack and also gas coning.


Poirier said four flow enhancement alternatives were considered-multiphase pumping, subsea separation of gas and liquids, subsea water separation, and injection of gas at the riser base-in terms of equipment required, potential productivity gain, and estimated increase in capital and operating costs.

One disadvantage identified for multiphase pumping was that the injection of methanol by coiled tubing to dissolve any hydrate plugs is not possible through pumps.

Also, sand traps must be emptied with remotely operated vehicles (ROVs), bypasses with remote subsea valves must be installed to allow pigging, and production must be stopped-typically planned once every 2 years-to allow pumps to be retrieved for maintenance.

Furthermore, pump connections must be made with two diverless connectors, which increases capital outlay; the high voltage cable and connectors must be run at 1,400 m water depth; and a deepwater capacity barge must be mobilized for installation of the multiphase pumping station.

Poirier identified these benefits of multiphase pumping in this case: the gas volume fraction decreases as flow enhancement is needed, increasing multiphase pumping efficiency; multiphase boosting would be required only after 4 years of operation, allowing staged investment; and oil productivity would be higher than with gas injection at the riser base.

The disadvantages for subsea separation of gas and liquids: high capital outlay; complexity of control; a thick pipeline wall would be required to prevent collapse at 140 bar ambient pressure; a bypass would be required for pigging; coiled tubing operations would be impossible; a high voltage umbilical would be needed; and a deepwater installation barge would be required.

On the other hand, Poirier said subsea separation of gas and liquids would limit hydrate formation in the production riser, while there would be no need for a high pressure separator on the FPSO, there would be higher oil productivity gain than for gas injection at the riser base, there would be no risk of severe slugging, a high efficiency single phase pump could be used, and gas removal would reduce the temperature drop.

The disadvantages of subsea water separation, according to the authors, would be the high control level required, high capital expenditure, the required low content of oil in water, the bypass needed for pigging, and the impossibility of coiled tubing operations.

The benefits of subsea water separation were said to be that water injection risers would not be required and that efficiency would be better than for gas injection at the riser base.

The disadvantages of injecting gas at the riser base were said to be that productivity gain is less than for multiphase pumping or subsea separation, that gas velocity is a limiting factor in prevention of erosion and annular flow, that gas expansion would cool down produced effluent, that erosion must be carefully controlled at the gas injection point, and that injection lines must be installed with production lines.

"Nevertheless," Poirier concluded, "this method has been retained as the most appropriate solution to enhance flow in the riser for this particular field development."

The author said gas injection inside the production riser would have many benefits. For instance, the efficiency of gas lift would not be strongly reduced by increased friction pressure.

Also, gas would be available on the FPSO because it could not be flared, severe slugging would be prevented at low flow rates, pigging and coiled tubing operations would be possible in production lines, gas lift could be used to flush the production riser, and this solution would require little maintenance and therefore minimal shutdown time.

"The technical difficulties associated with going below 500 m water depth are still to be mastered," added Poirier, "but existing references show that this goal is not too far from reach and that most of the technologies are now mature."

The author said that each of the four solutions they considered in the case study had advantages and drawbacks; gas lift, for example, is simple, elegant, reliable, and relatively cheap but has limited boosting capacity.

Multiphase pumping is technically more difficult, not very power-efficient, with limited boosting capacity and of questionable reliability. Yet it would require small to medium subsea modules and easily sourced marine support.

Gas-liquid separation has the best boosting capacity where water depth is greater than 1,000 m; however, the cost of fabrication, installation, and maintenance of the subsea modules is significant, and the reliability of the pumps has yet to be demonstrated.

Finally, the subsea water removal system was considered to be very profitable for some specific fields.

"Flow enhancement methods for deep water, although challenging," said Poirier, "are a unique chance to improve overall oil recovery and net present value for deep and ultradeep offshore fields. This is possible without going downhole and with good efficiency."

Flow lines and risers

The DOT conference also heard of a cost-effective concept for deepwater insulated flow lines and risers in a paper written by Fran?ois Thi?baud of Doris Engineering; Vincent Alliot of Stolt Comex Seaway Inc., Houston; and Stephen Hatton of 2H Offshore Engineers Ltd., Houston.

Alliot explained that the companies' new concept for flow lines and risers was developed for a spread-moored FPSO to be placed in 1,400 m of water offshore Angola, comprising a hybrid riser tower combining steel and flexible pipes, and subsea flow lines installed by on-bottom tow in a pressure-balanced bundle.

The main drivers for the flow line and riser concept selection were said to be water depth, stringent insulation requirements, and low cost. The authors concluded that the hybrid riser concept provides a number of advantages over both steel and flexible catenary risers.

First was the low vertical tension on the FPSO. For 13 risers of 8-14 in., the total estimated load was estimated to be 150 metric tons compared with about 2,000 tons for catenary risers, eliminating ballast requirements on the FPSO and simplifying the supporting structure.

Similarly, there would be low horizontal tension on the FPSO, negligible in the case of the hybrid concept but in the case of catenary risers requiring additional mooring lines unless risers were evenly distributed on both sides of the vessel and installed at the same time on either side.

The hybrid riser concept would also contribute to an early production rate, because flow lines, risers, and subsea connections could be carried out before the FPSO arrived on site, enabling immediate production from predrilled wells. This was said to be a significant advantage, with catenary risers requiring at least 30-45 days for installation.

The hybrid riser concept was also said to have excellent insulation properties and to provide long durations before fluids cool down to ambient temperatures.

Other pluses were said to include easy installation of piggyback lines, excellent dynamic behavior, no congestion by injection lines near the vessel, no requirement for mobilizing a large pipelay vessel, and less severe slugging requirement.

GTL prospects

Joe Verghese of ABB Lummus Global told DOT delegates that environmental pressures have contributed to the industry's renewed interest in GTL processes.

"The exploitation of fields in deep water increasingly demands the deployment of processing facilities on floating production systems," said Verghese.

"If GTL technologies can be viably applied to FPSOs, several advantages ensue, chief of which is that the envelope of application is enlarged. FPSOs can exploit both gas fields distant from shore infrastructure and gas assets where onshore location poses unacceptable construction, completion, and operational risks.

"Several exploration and production provinces, such as West Africa, have relied on gas flaring as a concomitant to oil production operations.

"Oil companies' focus on environmentally sound policies, legislation, and environmental lobby pressures have combined to bring a sense of urgency to the mission of commercializing technologies that will monetize these prospective gas assets, eliminate or at least minimize gas flaring, and leverage oil prospects in the oil companies' portfolios by facilitating their development with captive solutions for associated gas.

"The momentum generated in the exploitation of deepwater fields can only be sustained if viable and economic gas utilization solutions can be integrated into the field development plans."

Verghese showed how prices affect returns of an FPSO-based GTL system (Fig. 5 [34,602 bytes]). And he outlined the main technologies and players in the GTL process sector (OGJ, June 23, 1997, p. 16). He said gas conversion technologies require proven experience onshore before deployment offshore.

Verghese said FPSOs used for conversion and for liquefied natural gas will need to be "road-tested in relatively benign water environments, for example West Africa, prior to applications in harsh environment provinces."

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