Subsea Tie-Back Development
Subsea developments only made sense for big reservoirs before, because the CAPEX and OPEX costs are high and it is difficult to justify the return versus the risk. So, in some cases, the small marginal oil fields are normally ignored. In recent years, subsea tie-backs were set to become popular in the development of marginal oil and gas reserves in an effective and economical way. Operators began to realize that the overall capital expenditure can be decreased by utilizing the processing capacity on existing platform infrastructures, rather than by continuing to build new structures for every field. Thus much smaller accumulations can be developed economically. Generally subsea tie-backs require significantly lower initial investments, compared with developments using FPSOs or other fixed installations. The economics of having a long tie-back are governed, however, by a number of factors specific to that field:
- Distance from existing installation;
- Water depth;
- Recoverable volumes, reservoir size, and complexity;
- Tariffs for processing the produced fluids on an existing installation;
- The potentially lower recovery rates from subsea tie-backs versus standalone development, due to limitations in the receiving facility’s processing systems;
- The potentially higher recovery rates from platform wells, due to easier access to well intervention and workovers. The host of subsea tie-backs can be categorized as follows:
- Tie-back to floating production unit;
- Tie-back to fixed platform;
- Tie-back to onshore facility.
Tie-Back Field Design
A subsea tie back system generally includes a subsea wellhead and a flowline to an existing production platform for example. Some serious limitations of flow assurance are expected with a longer subsea tie-back, such as hydrate formation induced plugging of the flowline due to the heat loss to the environment and therefore a decrease of temperature along the flowline.
The conventional remedial methods include thermal insulation of flowlines or injection of chemical inhibitors to prevent the formation of hydrates (refer to Part II, flow assurance part of this book). Such chemicals can be transported from the host platform to the subsea wellhead with an umbilical, and can be injected into the flowline at the wellhead. The umbilical can also be used to control the subsea wellhead.
The cost of such umbilical is typically very high, and the economics of a subsea tie-back is often threatened by the excessive umbilical cost for tie-back distances greater than 30 km. An alternative development scenario of flow assurance consists of providing a small offshore platform near the wellhead with remote control from the host platform and injection of chemical stored on the small offshore platform via a short umbilical connected to the subsea system.
The presence of a platform directly above the wellhead enables pig launcher capabilities and well logging tools support. When multiphase hydrocarbon flow is expected in the flowline, the tie-back distance is limited because of flow assurance problems. Current technological developments are aimed at providing subsea separation facilities on seafloor to separate the fluid into hydrocarbon liquid, gas and water, allowing hydrocarbons to flow over a longer distance.
Subsea equipment such as subsea pumps may be required to increase the pressure of fluid and assist flow assurance over the tie-back length. Such pump system also requires power which can be provided by a surface facility.
Dual-flowlines are used widely in the subsea tie-back system to provide a circuit for pig to start from the production platform, go through the flowlines to remove the solids in the flowlines, such as wax, asphaltene, sand, and return to the production platform.
Tie-Back Selection and Challenges
Advances in flow assurance and multiphase transport now allow the use of tie-backs over much longer distances, while the introduction of subsea processing will strengthen the business case for subsea tie-backs in future field developments. However, we can try to choose the best development plan, based on an overall consideration of the following factors:
- Cost: Lowest life-cycle cost (i.e. lower CAPEX and OPEX);
- Safety: Safety of personnel and other stakeholders in construction and operation;
- Environment: Impact of development on the environment;
- Technology innovation or transfer: Trial of new technology or transfer of existing technology and know-how;
- Capacity utilization: Use of existing infrastructure, facilities, and elongation of useful life;
- Recoverable volumes, reservoir size, and complexity;
- Tariffs for processing the produced fluids on an existing installation;
- The potentially lower recovery rates from subsea tie-backs versus standalone development, due to limitations in the receiving facility’s processing systems;
- The potentially higher recovery rates from platform wells, due to easier access to well intervention and workover. Many marginal fields are developed with subsea completions and with the subsea tie-back flowlines to existing production facilities some distance away. Subsea tie-backs are an ideal way to make use of existing infrastructure. Long tie-back distances impose limitations and technical considerations:
- Reservoir pressure must be sufficient to provide a high enough production rate over a long enough period to make the development commercially viable. Gas wells offer more opportunity for long tie-backs than oil wells. Hydraulic studies must be conducted to find the optimum line size.
- Because of the long distance travelled, it may be difficult to conserve the heat of the production fluids and they may be expected to approach ambient seabed temperatures. Flow assurance issues of hydrate formation, asphaltene formation, paraffin formation, and high viscosity must be addressed. Insulating the flowline and tree might not be enough. Other solutions can involve chemical treatment and heating.
- The gel strength of the cold production fluids might be too great to be overcome by the natural pressure of the well after a prolonged shutdown. It may be necessary to make provisions to circulate out the well fluids in the pipeline upon shutdown, or to push them back down the well with a high-pressure pump on the production platform, using water or diesel fuel to displace the production fluids.
Subsea long tie-back developments will be utilized widely in the future with the advent of new technology such as subsea processing and subsea electrical power supply and distribution.
References
[1] C. Claire, L. Frank, Design Challenges of Deepwater Dry Tree Riser Systems for Different Vessel Types, ISOPE Conference, Cupertino, 2003.
[2] M. Faulk, FMC ManTIS (Manifolds & Tie-in Systems), SUT Subsea Awareness Course, Houston, 2008.
[3] R. Eriksen, et al., Performance Evaluation of Ormen Lange Subsea Compression Concepts, Offshore, May 2006.
[4] CITEPH, Long Tie-Back Development, Saipem, 2008.
[5] R. Sturgis, Floating Production System Review, SUT Subsea Awareness Course, Houston, 2008.
[6] Y. Tang, R. Blais, Z. Schmidt, Transient Dynamic Characteristics of Gas-lift unloading Process, SPE 38814, 1997.
[7] DEEPSTAR, The State of Art of Subsea Processing, Part A, Stress Engineering Services (2003).
[8] P. Lawson, I. Martinez, K. Shirley, Improving Deepwater Production through Subsea ESP Booster Systems, inDepth, The Baker Hughes Technology Magazine, vol. 13 (No 1) (2004).
[9] G. Mogseth, M. Stinessen, Subsea Processing as Field Development Enabler, FMC, Kongsberg Subsea, Deep Offshore Technology Conference and Exhibition, New Orleans, 2004.
[10] S.L. Scott, D. Devegowda, A.M. Martin, Assessment of Subsea Production & Well Systems, Department of Petroleum Engineering, Texas A&M University, Project 424 of MMS, 2004.
[11] International Standards Organization, Petroleum and Natural Gas Industries-Design and Operation of the Subsea Production Systems, Part 1: General Requirements and Recommendations, ISO 13628-1, 2005.
[12] O. Jahnsen, G. Homstvedt, G.I. Olsen, Deepwater Multiphase Pumping System, DOT International Conference & Exhibition, Parc Chanot, France, 2003.
