Riser-base gas lift is used in subsea developments for production enhance-ment. It is an effective method to sup-press severe slugging that occurs in flowlines with downhill inclination. In some cases, gas lift can aid blow-down for hydrate prevention. Gas lift is not always needed because its effectiveness depends on reservoir performance, fluid properties, sea-bed terrain, subsea architecture, and flowline and riser specifications. The need for gas lift, optimal operability, and system design should be assessed from various aspects, including flow assurance. A generic set of guidelines was developed on the basis of past experience with riser gas lift applica-tions for different deepwater subsea projects and associated multiphase-flow phenomena.

IntroductionThis paper discusses riser-base gas lift for deepwater subsea oil-production systems. The focus is how flow-assur-ance concerns affect various engineer-ing decisions in designing a gas lift system. Riser-base gas lift is injection of a predetermined rate of gas from the host facility into the production flow-line (riser) at the seafloor. The reasons for gas lifting can vary, but the most important pertain to flow assurance,

production enhancement, flow stabili-zation, and flowline depressurization.

Why Gas Lift Is NeededThe stages of a fields life should be studied to determine when to install and operate the gas lift system. Gas lift is not always beneficial; in some cases, increasing the gas rate may be detrimental to the performance of the subsea system.

Production Enhancement. Gas lift for production enhancement lowers the flowline pressure. Typically, gas lift is needed with high water cuts in the flowlines, low-GOR fluids, and low-to-moderate production rates. The effectiveness is higher in systems with low production-system-inlet pressures. One major advantage of gas lift for production enhancement is that there are no moving parts in the subsea system, apart from valves and chokes. Compression for gas export is almost inevitable in any subsea development; therefore, the supply of lift gas during production is not a major issue.

When to use gas lift for production enhancement should be determined by use of integrated (reservoir/wells/flowline) production modeling. The study also should include the water/gas injection to the reservoirs. Accuracy of flowline/riser pressure-drop and liquid-holdup calculations in multiphase-flow models and the accuracy of pressure/volume/temperature predictions are crucial. This accuracy becomes more important in larger-diameter flowlines with deepwater risers in which the multiphase behavior is different from that in smaller-diameter systems.

Severe-Slug Suppression. The ten-dency of subsea flowlines to exhibit severe slugging at reduced-rate opera-tions should be evaluated over the

fields life to identify when gas lift is needed. Reduced-rate operation of the flowline during startup period and during well tests should be considered. In many situations, gas lift may be needed from first production to sup-press severe slugging in such reduced-rate situations.

Blowdown. Blowdown of large-diam-eter risers with gas lift assist is field proven, especially for low-watercut sys-tems. Gas lift can complete the blow-down in cases for which the flowline size and fluid properties do not provide a successful blowdown without gas lift assist. Gas lift assist can lower flowline pressures below target values.

Systems Suitable for Gas liftHigh Water Cut. Depending on res-ervoir type and reservoir-management strategy, large amounts of water can be produced, especially in late stages of production life. This is especially the case if reservoir-pressure maintenance requires water injection. Water cut in such systems increases quickly, caus-ing the flowline pressure to increase because of the higher density of water and reduced gas production. Without artificial lift, such as gas lift, the wells may not be able to produce against the flowline pressures.

Injecting gas lowers the mixture density in the riser and, hence, the hydrostatic head, which is predomi-nant at lower production rates, when liquid holdup in the riser is greater. In contrast, especially at high production rates, increased gas flow in the riser and the flowline downstream of injection will increase the flowline pressure. If the net result of these two competing mechanisms is a reduction in flow-line pressure, then gas lift is beneficial to production enhancement. Results from steady-state modeling, such as

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18820, The Use of Subsea Gas Lift in Deepwater Applications, by Subash S. Jayawardena, George J. Zabaras, SPE, and Leonid A. Dykhno,Shell Global Solutions, prepared for the 2007 Offshore Technology Conference, Houston, 30 April3 May. The paper has not been peer reviewed.

Copyright 2007 Offshore Technology Conference. Reproduced by permission.

Subsea Gas Lift in Deepwater Applications

DEEPWATER EXPLORATION AND PRODUCTION

The full-length paper is available for purchase at OnePetro: www.onepetro.org.

64 JPT JUNE 2008

Figs. 1 and 2, can be used to identify production benefits from gas lift.

Low GOR. Low-GOR reservoir fluids often require artificial lift. The mix-ture density in the riser is high, result-ing in a higher flowline pressure. The mechanism by which flowline pressure is reduced is similar to that

for higher water cut. With increas-ing GOR, gas lift becomes less effec-tive, and finally becomes detrimental. Therefore, accurate prediction of the GOR behavior over the life of the field may become very important to identify the need for gas lift, especially in reservoirs for which management includes gas injection.

Fig. 2Flowline inlet pressure at different production rates and water cuts for the same flowline; 15-MMscf/D gas lift.

Fig. 1Flowline inlet pressure at different production rates and water cuts; no gas lift.

JPT JUNE 2008 65

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Deep Water. Because production enhancement is related to reducing the density of the riser fluid with gas, it might be expected that the effective-ness of gas lifting increases with water depth. However, other limitations associated with gas lift may become important and limit the applicability of gas lift in ultradeep water. In par-ticular, thermal limitation will appear because the increased water depth will increase the Joule-Thomson cooling effect associated with depressurization of additional gas, significantly cooling the produced fluid and causing other flow-assurance problems (e.g., faster cooldown of the riser).

Long-Offset Flowlines. Unlike short-offset flowlines in which downhole gas lift might be reasonable, long-off-set-flowline riser-base gas lift would have fewer difficulties with delivery of the gas from the host to the injec-tion location. However, very-long-off-set systems may be affected adversely (thermally) by additional cooling from gas expansion.

Downhill Flowlines. Downhill flow-lines are susceptible to severe slug-ging. Often, gas lift is considered for a flowline system with downhill-sloped flowlines, even if gas lift is not required

for production enhancement. Because severe slugging usually occurs at rela-tively low rates (e.g., early and late life, well tests, commissioning, and startup), gas lift may become neces-sary early.

Unlike uphill flowlines, blowdown of downhill flowlines is feasible under a limited set of circumstances. Gas lift during blowdown may remove an addi-tional amount liquid from the riser, assisting complete blowdown in such flowlines. In such cases, need to blow-down downhill flowlines may become a primary factor for choosing the gas lift option.

Uphill Flowlines. In most cases, severe slugging is not an issue for flowlines with uphill topography, even at high water cuts. Blowdown feasibility often depends on details of uphill-flowline topography and depends strongly on water production. Gas lift for blow-down assist may become necessary only at medium-to-high water cuts. In such cases, it may be acceptable to defer the installation of gas lift until it becomes necessary.

Other Factors. Weak-well startup may require gas lift. The flowline pressure can be reduced by gas lift, enabling the flow of weak wells. However, in

flowloop situations, riser-base gas lift may not be the best option to reduce the flowline pressure.

Reservoir-management concerns also may dictate the need for gas lift and when to use it. This is espe-cially true if produced-gas reinjection is a part of the field-development strategy. In such cases, the expected produced-fluid GOR may vary such that gas lift may not be needed. The full-length paper provides detail on gas lift injection location and de-sign considerations.

Case StudiesCase 1. This floating-production-sys-tem-based deepwater-subsea develop-ment is at a water depth of approxi-mately 6,000 ft. Subsea layout has both uphill and downhill flowlines, with two oil flowloops. Water or gas injec-tion for reservoir support is not used in this development.

Downhill flowlines were expected to incur severe slugging, even at a flow rate of 20,000 BFPD, and gas lift was selected for these flowlines to prevent severe slugging. Blowdown assisted by gas lift was not considered because of water-depth issues. Also, the available gas lift injection tie-in location did not favor the use of gas lift during blowdown.

The closest gas lift tie-in for these flowlines was near enough to the clos-est well for one flowline, but not for the other. Thus, one flowline was equipped with a dedicated gas lift injection point, while the gas lift injection to the other flowline was performed at that closest-well location. This decision eliminated some subsea hardware but increased one gas lift riser length by more than 5,000 ft.

Thermal considerations (cooldown times of the subsea system, which depend on arrival temperature while gas lift is used) led to the decision to insulate the shorter gas lift riser. Analysis showed no need for insulat-ing the longer gas lift riser. Also, the cooldown times with cold gas injected through the uninsulated gas lift riser were acceptable in that flowline.

With 6,000-ft water depth, addi-tional pressure boosting was required for lift gas in some conditions. The gas-export-flowline operating pres-sure is not adequate for all situa-tions that need gas lift. However, normal gas lift operations can be con-

Fig. 3Initiation of severe slugging in a flowline with a downhill section near the riser base when gas lift was stopped.

JPT JUNE 2008 67

ducted with the export gas, with no extra compression.

Gas lift for severe-slug suppression in this case performed as expected. However, the production rates required to operate without severe slugging when no gas lift was used were higher than initially expected.

Case 2. This deepwater subsea devel-opment that used a floating produc-tion, storage, and offloading vessel is at a water depth of approximately 3,000 ft. Subsea layout consists mostly of uphill flowlines, with a significant downward dip close to the riser base for some flowlines. Water injection for reservoir-pressure maintenance is used, while gas reinjection is not used.

Reservoir pressures are not expected to drop below bubblepoint. Water cut increased significantly over the fields life, resulting in a gradual decrease in gas/liquid ratio. Integrated production modeling predicted the need for gas lift in middle and late field life associ-ated with the increasing water cut in the flowlines.

Also, severe-slug suppression required the use of gas lift at low production rates for flowlines with a local downward dip. Gas lift is needed at production rates less than 20,000 BLPD for smaller-diameter flowlines in the area of downward dip to prevent severe slugging. For the larger-diameter flowline with down-ward dip, gas lift is needed to suppress severe slugging at production rates less than approximately 35,000 BLPD. These rates depend strongly on the GOR and water cut.

Flowline geometry and the expected fluid composition in the flowlines at different stages of field life required the use of gas lift assist during blowdown for some situations. The larger flow-line size required gas lift for all fluid compositions. Blowdown of smaller-sized flowlines needed gas lift when the water cut increased above 50%.

Heated lift gas is provided by use of dedicated gas lift risers to the base of each production riser, with lift-gas-flow rate controlled at the host. The insulat-ed gas lift risers are designed to ensure a minimum lift-gas injection temperature under normal operating conditions so that produced fluids will not be cooled to an unacceptable temperature. This method ensured maintaining adequate cooldown times.

The design included an integrated electrohydraulic umbilical supplying lift gas, chemicals, hydraulics, and electrical power to the gas lift tie-in points. This design provided a cost saving, but it added operational and installation complications.

Gas lift for severe-slug suppression performed as expected in this case. However, gas lift did not smooth the flow. It removed the wide swings in flowline pressure associated with severe slugging and prevented the very large (riser-volume size) liquid slugs from being produced to the host. For exam-ple, severe slugging was suppressed with 20-MMscf/D gas lift in one of the larger flowlines at 21,000 BLPD. Fig. 3 shows the flowline-pressure fluctuations that indicate the initiation of severe slugging after gas lift was stopped.

Blowdown of a large-diameter flow-line with a downward dip did not reduce the flowline pressure below the target. However, use of gas lift made the flowline pressure drop below the target pressure, making it a success.

Four additional developing cases are detailed in the full-length paper.

ConclusionsIntegrated production modeling (res-ervoir and subsea-gathering system) is necessary to determine the need for gas lift for production enhancement. Gas lift requirements for severe-slug suppres-sion and gas lift assisted blowdown can be evaluated by analyzing the subsea system alone.

Design of the subsea gas lift systems should consider all credible operating scenarios to ensure that the selected system can deliver the lift gas as need-ed. Proposed uses of gas lift, anticipated production forecasts, and any future expansion plans determine when the gas lift system should be ready for a given development. Planning for lift-gas supply during normal production as well as under shut in conditions must be planned in advance.

Whether to use subsea gas splitting with a common gas lift delivery system or to have dedicated gas lift delivery systems for multiple flowlines/risers depends on cost, external constraints, proposed used of lift gas as well as potential for severe slugging. There is no one size fits all design approach for the riser-base gas lift systems. Each system must be designed with a holis-tic approach. JPT

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