Subsea separation shortens cycle for deepwater, long offset production

FMC/Kongsberg Offshore is working with Aker Maritime on a flexible modular subsea separation system to meet a wide range of customer needs. The system is flexible enough to incorporate 2, 3, or 4-phase separation modules, including subsea water removal and disposal, multiphase or single phase pumps, subsea power supply distribution. The subsea processing configuration (number of modules, functionality) depends highly on field and reservoir parameters.

The following is an example concept for a subsea separation system specifically for 2-phase gas/liquid separation, providing integration with existing standard subsea field development "building blocks", relatively compact size, modular design, easy installation and retrievability, and a high degree of reliability.

For this 2-phase gas/liquid separation concept, "life-of-field" economic analysis has been performed for a "generic" West Africa case to illustrate the benefits and costs associated with such a system. Depending on reservoir characteristics, the concept could potentially be applied for other deepwater regions.

To realize the full benefits of this concept for a target field application, preliminary engineering should be performed based on site-specific information followed by operability analysis, prototype construction and testing, and field testing.

Flow enhancement

There are several methods available to enhance the flow of oil and gas in subsea production systems. These methods include:

• Seabed separation and pumping
• Downhole separation and pumping
• Seabed multiphase booster pumps
• Downhole multiphase pumps or electric submersible pumps
• Gas lift (downhole, seabed, at/near the wellhead, or base of riser)
• Re-injection of produced water or disposal injection into the reservoir (water, gas or alternating water/gas).

In a comprehensive analysis of field development approaches, all or most of the above options should be evaluated on the basis of capital expenditures (capex), operating expenditures (opex), and impact on net present value (NPV), in addition to other considerations. This paper focuses primarily on one type of seabed separation and pumping that may have wide application.

Separation options

A brief review of the literature indicates several types of subsea separation and pumping systems. In general, there are four possible phases that could be separated: oil, gas, water, and solids. Types of separators include 2-phase, 3-phase and 4-phase. The separated phases can be pumped or they may flow naturally under wellhead pressure to a host processing facility. While the processing methods for 4-phase separations are technically feasible, there are significant issues related to solids and water handling.

• Solids: After removing the solids from the multiphase flow stream, the solids would ideally have to be cleaned sufficiently to be discharged to the sea. The author is not aware of current or field-proven methods for performing this task in a subsea processing system. Another option is to mix the solids with the hydrocarbon stream and transport them to the surface.
• Water: Two options are available to handle separated produced water. The water can be injected for disposal into a shallow formation, injected into a reservoir for pressure maintenance, or it would have to be cleaned sufficiently to discharge to the sea. None of these options is very attractive considering the current status of the associated technologies. Downhole injection requires the drilling of an additional well, which would be expensive.

Produced water discharge to the sea requires reducing the oil-in-water concentration to a very low level (currently less than 40 ppm) to meet regulations. This approach may require a large gravity separator and/or multiple separation devices (cyclones or centrifuges) to achieve the water quality level. Furthermore, a reliable oil-in-water sensor and system shut down and/or by-pass system is required to prevent accidental discharge of high oil-content water. Considering these issues, discharge of produced water at a subsea-processing site may not be practical based on current technology.

This paper presents a "building-block" ap proach to achieve 2-phase gas/liquid separation. While the processing technology for 3- or 4-phase subsea separation and solids/water handling are rapidly maturing, for the purpose of illustrating the features and benefits of compact separators, a 2-phase gas/liquid separation process has been selected as an example.

As described above, this approach is economically attractive, simple, and the components are relatively mature technology for subsea application. As the technology matures for oil/water/solids separation and handling, additional devices could be integrated into the concept proposed here to achieve improved system performance.

Concept description

A simple concept consisting of a compact 2-phase separation system requires two additional equipment elements inserted into a typical subsea production system - a 2-phase separator and a liquid booster pump. It is assumed that the flowing wellhead pressure is sufficiently high to push the gas through the flowline. The liquid is boosted by a single-phase (liquid only) pump through a separate line. 3-phase or 4-phase separation is possible by adding other components into this system.

There are several potential benefits from using a 2-phase gas/liquid subsea separation system compared to a conventional surface separation system. Such a system reduces flowing wellhead pressure and produces fluids at a higher rate (increases net present value and/or recoverable reserves). Initial installation of a subsea separation system can result in increased per-well rate and potentially eliminates some wells to reduce overall field development costs. This approach depends greatly upon reservoir characteristics.

Flow assurance requirements can be reduced. This system can avoid hydrates in the gas line, eliminate insulation on the gas line, minimize corrosion in the gas line, reduce the size of topside facilities, and reduce liquid slugging potential. Subsea separation installation in an older field could extend its life and defer abandonment, which may be a feasible approach for those cases where incremental reserves justify the increased capex.

Separation allows freedom to route gas/liquid or separated streams to different hosts, as appropriate, considering tie-in to gas/oil trunk lines, processing facilities, and other factors.

Some disadvantages of this concept are that the offset distance will be limited, considering that gas has to be vented (no subsea gas compressor). Also, two separate flowlines are required. 2-phase separation requires oil/ water separation in a separate subsea device or at the host facility.

Separation components

A typical 2-phase subsea separation and pumping system consists of the following sub-systems and components:

• Subsea components: separator; manifold with associated piping for inlet/outlet headers; pumping system including pump, motor, and lube oil system; connectors for inlet/outlet streams, electrical supply, instrumentation, hydraulics, and chemical injection; power umbilical; instrumentation/sensors; flowlines; umbilical (power, control and instrumentation); and power supply and distribution.
• Topsides components: power supply; variable frequency drive; transformers; and control system.

Depending on the field architecture, the variable frequency drive and transformer may have to be installed subsea to minimize power losses in the power umbilical and to minimize overall cost.

Almost all of the components presented in this concept are proven for "land" or "offshore/topsides" applications. Marinization is the technical challenge for subsea applications. Most of the above components are standard building blocks proven in subsea field development applications with the exception of the separator device, pump, power distribution (if subsea transformers and similar units are required) and certain instrumentation and controls. The following section describes the options available for the separator and the liquid booster pump.

Compact separator options

For the separation device, several options are available. Either 2-phase or 3-phase separators are available. Important criteria for the selection of a separator vessel for a subsea application are compactness, weight, dimensions, flow rate capacity, separation efficiency (purity of each effluent stream), 2-phase (gas/liquid) or 3-phase (gas/hydrocarbon liquid/water) separation.

A compact, vertical orientation separator offers a convenient approach to satisfy these criteria for integration into a subsea system. In addition, this approach allows easy installation and removal of the equipment or device in case of a potential failure.

There are several devices currently available in the industry that have the above features. Most of these devices use centrifugal and/or gravitational forces to perform the separation. These separators can potentially be combined with other inlet or outlet devices to improve separation efficiency.

Pump options

Several options exist for a liquid booster pump including conventional centrifugal pump, electric submersible pump, and a positive displacement pump. The fluid section of the pump could be a fairly simple design assuming that the gas and solids content in the liquid stream are relatively small (less than ~2% by volume).

While the electric submersible pump has been proposed for subsea applications, typically it is more suitable for a vertical orientation, particularly in a wellbore. While there may be variety of options for a subsea single-phase liquid pump, a compact centrifugal pump with an electric motor is likely the best candidate for a seabed application because of its relatively compact size. Furthermore, subsea multiphase pumping is a field-proven "building block", as demonstrated by installations in the North Sea, offshore Southeast Asia, and an upcoming installation in West Africa.

Compact separation

A sample compact subsea separation system integrated into a subsea manifold consists of two trees integrated with an FMC/Kongsberg Offshore hinge-over subsea template system (HOSTTM). The remaining slots on the template are used to install a pair of compact vertical separators and a liquid booster pump. Piping, valves and connectors are provided to facilitate individual retrieval of each of the two separators and the pump.

With this configuration, if any of the components requires servicing, they can be retrieved individually. Dual separators provide 100% backup in case of a failure of one separator. While redundancy is not absolutely required, this option could be provided at a low cost since a relatively compact separator is used.

With this configuration, a failed separator does not require immediate replacement. The separator can be replaced once a vessel becomes available in the field for other intervention activities. All of the individual components such as separator, pump, control pod, etc. can be installed by a diving support vessel or equivalent, since each module is relatively small.

Life-of-field analysis

To illustrate the economic value of the compact subsea separation system described above, a generic West Africa case study was defined and evaluated with and without subsea separation. Depending on reservoir and field characteristics, this example could apply to other regions such as the deepwater Gulf of Mexico or Brazil. The following are parameters for the base case (no separation):

• Number of producing wells = 16
• Water depth = 2,000 ft
• Recoverable reserves = 100 million bbl
• Low reservoir pressure; depletion drive
• Gas lift and water injection needed
• Peak rates = 60,000 b/d; 50 MMcf/d
• Productivity index = 15 b/d/psi
• Waxy crude with potential to form hydrates during shutdown.

This case study focuses on the production from the initial six wells completed from the two HOST manifolds located in the southwest region of the hypothetical field. The remaining two wells would be completed in a later project phase as the initial wells are depleted. The six wells can produce at a combined capacity of 30,000 b/d through dual 6-in. flowlines. Assuming a similar production strategy, the north and east manifolds would each contribute 15,000 b/d. This results in a total peak rate of 60,000 b/d for the field.

Three options

Potentially, there are three options to use a subsea separation and pumping system to reduce overall field development costs and increase project net present value (NPV).

One is to install subsea separators at the start of field development. By using subsea separators, the per-well rate can be increased substantially. The number of wells can be reduced and yet maintain the same field-wide production rate. The seabed flowlines and surface facilities processing capacity will be the same. By eliminating some wells, the total drilling and completion costs can be reduced. This approach is highly dependent on reservoir characteristics. If an operator chooses to install the subsea separators at the start of field development he will increase the initial peak production rate. This will result in accelerated production/revenue.

Furthermore, lowering the abandonment reservoir pressure can increase field life. However, this option will require large process and larger diameter flowlines and risers to accommodate the high initial peak rates. Increased capex associated with subsea separation equipment, the larger flowlines and the large surface facilities, have to be compared with the increased NPV associated with accelerated production.

Installing the subsea separators at mid- to late-life conditions to extend field life, will increase recoverable reserves by reducing abandonment pressure. This approach will improve project NPV. The initial capex does not increase significantly. The cost of the subsea separators is not incurred until mid- to late-life periods thereby improving project economics. Modular subsea equipment design is desirable to accommodate future addition of the subsea processing equipment without substantial impact on pre-installed packages.

This paper provides an evaluation of only the first option listed above. This approach is perceived to require the least capex for introducing the subsea separation system.

For this example, assume a subsea 2-phase separator and pumping system at the start of the field development, as described above. The inflow performance shown represents the production from two wells. The inflow productivity performance of the reservoir and the wellbore are assumed to be the same as the base case (no separation).

With the separator operating at 450 psi, the two wells can produce at a combined rate of 30,000 b/d. The per-well production rate with the subsea separation and boosting is significantly higher than the base case since the flowing welhead pressure is lower with separation. The separated liquid has to be boosted to approximately 1,600 psi in order to flow through a single 6-in. line to the host facility on board the floating production, storage, and offloading (FPSO) vessel. The pump horsepower requirement is estimated to be 700 kW.

The gas is vented through the other 6-in. flowline without any compression. The liquid line will likely require thermal insulation to prevent excessive wax deposition. The gas line will not need any insulation since the separator would have removed a large fraction of the liquid. As the gas stream cools to the seabed temperature in the uninsulated line, a small amount of water will condense and potentially form hydrates. Methanol can be injected continuously downstream of the separator into the gas stream to avoid hydrate formation.

There are additional performance benefits gained by using a subsea separation system for the two daisy-chained HOSTs. The base case described requires six wells to initially produce 30,000 b/d. The seventh and eight wells would be drilled and completed later in field life as the production declines from the initial six wells.

Higher flow

With subsea separation and pumping, an equivalent production rate of 30,000 b/d can be achieved by only two wells. An additional two wells are assumed to be required to fully drain the field. This approach requires only four producers instead of eight (a 50% reduction in well count, and cost). Note that this approach assumes that the reservoir is continuous between the group of wells at each manifold (no natural boundaries such as faults, traps or seals).

The reservoir rock is assumed to have reasonable permeability. Furthermore, it is assumed that the drainage efficiency in the reservoir is not compromised significantly by reducing the number of wells. This is likely if the reservoir is continuous between the well groups at each of four manifolds.

The modified layout for the entire subsea separation and pumping module is integrated into three of four HOST manifolds. The production from the two wells located on the southwest side could be commingled through a simplified two-well manifold/sled, resulting in further cost savings. The modified field development consists of the following characteristics:

• Number of producers: 8
• Flowlines: same as base case
• FPSO: same as base case
• Peak production rate: 60,000 b/d; 50 MMcf/d (same as base case)
• Recoverable reserves: same as base case
• Subsea separation modules: 3
• Each module has: two separators to process 30,000 b/d each (100% backup), a liquid booster pump, dedicated control pod, umbilical to supply power, (all integrated into a subsea manifold).

The topsides supporting equipment includes a power source/generator for operating the pump, topsides control equipment, transformer, and variable frequency drive.

Cost/benefit analysis

The estimated capital cost for the three modular separation and pumping modules is $31 million. This includes the subsea and topsides supporting components including the power umbilical and offshore installation.

The operating costs for the subsea separation and pumping module have been estimated based on several assumptions. It will be necessary to clean and service all separators every four years by retrieving each module to the surface and re-installing. Chemicals, solvents, and other materials will be used to clean and remove any deposits such as wax, asphaltene, sand, or scale periodically. Assumed frequency is every six months. The subsea pump will be refurbished every two years, and replaced every four years. Power generation will require some fuel cost and operating expenses. A diving support vessel or equivalent vessel will be used for intervention.

Based on the above assumptions, the estimated total operating expenses for a field life of 15 years is $44 million. The NPV equivalent cost of the expenses is $22 million, based on a discount rate of 10%.

The cost savings resulting from eliminating eight wells is estimated to be $144 million ($18 million/well times 8 wells). Elimination of each well reduces the cost associated with drilling and completion, tree, controls and associated tubes in the umbilical. While this concept could result in some savings in topside facilities (use of smaller slug catcher, simplification of process elements since bulk gas/liquid separation is performed subsea, and other), these savings are not quantified here. The net savings are as follows:

• Savings from reducing well count = $144 million
• Capex for subsea separation = $ 31 million
• Opex for subsea separation (NPV) = $ 22 million
• Net savings = $ 91 million
• Net savings ($/bbl) = $ 91 million/100 million bbl = $0.91/bbl

In today's market environment, $0.91/bbl net reduction is substantial. Other savings include:

• Topside facility capital and operating cost can be reduced since pre-separation of most of the gas will be performed in the subsea separators.
• If insulated flowlines are needed to control paraffin or hydrates in the multiphase flowlines, insulation could potentially be eliminated in the separated gas line. The liquid line may still need insulation to control wax deposition.
• By eliminating multiphase flow, liquid slugging can be eliminated. This could reduce the need for a large topside slug catcher.
• Use of the subsea separation system will extend field life by lowering the abandonment pressure. This could increase the volume of recoverable reserves.

The above benefits are more difficult to quantify and enumerate, and therefore are not presented in this paper. However, their impact should further increase the net benefits from using the 2-phase subsea separation and pumping system.

Several types of subsea separation systems are possible. Even simple, 2-phase gas/liquid subsea separation and pumping can provide significant commercial benefits.

Compact, vertical separators provide significant merit for deepwater field developments in terms of low cost, acceptable process capacity, separation efficiency, retrievability and reliability.

Crucial system components are separators, pumps and controls. A rigorous reliability and availability study of these components should be made in order to optimize their performance. As illustrated in this paper, if these components are modularized and integrated into a subsea production system such as a manifold, each module can be retrieved individually in case of failure. This approach reduces intervention time and costs and improves system availability.

Based on a generic West Africa case study, significant economic benefits can be achieved by using a compact 2-phase separator inte grated into an FMC/Kongsberg Offshore HOST system.;

References

"Subsea Separation: A Perspective", Singh, B., presented at Deep Offshore Technology Conference 1999, Stavanger, Norway.

Author

Janardhan Davalath is Multiphase Flow Systems Manager for FMC's Offshore Integrated Developments group, he is responsible for leading FMC's efforts in flow assurance, subsea processing, subsea flowline/pipeline design in fully integrated flow systems. He has 15 years experience in design, research and development in areas of multiphase flow, flow assurance, and thermal systems. He holds a BSME from Lamar University and an MSME from Rice University.