Flow Assurance and System Engineering
System engineering discipline activities are broadly classified into three primary service areas:
- Production system design;
- System integration;
- Equipment application and development.
Contents
Subsea Operations
After the production system has been installed, numerous operations are in place to ensure safe and pollution-free operations and support the continued flow of hydrocarbons. The following are typical of postinstallation operations:
- Commissioning and start-up (start-up could be “cold” or “hot”);
- Normal operations;
- Production processing;
- Chemical injection;
- Routine testing;
- Maintenance and repairs (remotely operated vehicle [[[ROV]]], routine surface);
- Emergency shutdown;
- Securing facilities (e.g., from extreme weather events);
- Intervention.
In many cases the technology and techniques applied to support production activities in deepwater are similar in scope to developments in shallow water. Deep water does add a level of complexity to the project, particularly subsea developments, since the facilities may be located remote from the control (host) facility and not readily accessible. For example, a workover may require a dedicated riser and control system, as well as a deepwater capable rig and all of the support that comes with the drilling unit or even a specialized intervention vessel. A significant amount of work is necessary for proper planning, simulations (steady-state and transient), design, testing, and system integration before the deepwater development moves forward.
Commissioning and Start-Up
Operations typically begin with systems integration testing (SIT) at a shore base or vendor or manufacturer’s facility. Particularly for subsea projects, the remote tools installation that will be used to make connections (for example, ROV) will perform tests that simulate the actual installation. Mobilization to and the start-up of installation at the offshore location can involve a large number of vessels, including the drilling unit, support boats, derrick barge, transport barges and tugs, pipelay vessels, ROVs, and divers. Production from the well at this point will include completion fluids and reservoir fluids. These may be flared/burned, treated, and discharged overboard, or transported to shore for disposal at an approved location. The cleanup phase of bringing a well/field on line typically last 2 to 5 days.
Production Processing
Production processing equipment is generally the same for the both shallow and deepwater developments. The production system may involve several separators, a series of safety valves, treaters, compressors, pumps, and associated piping. For deepwater facilities, the production system may be designed to process higher rates of flow. These could include production from multiple developments commingled at a common host facility. The main surface production processing system components might involve crude oil separation, water injection equipment, gas compression, chemical injection, control systems for subsea production equipment, and associated piping. The processing system varies little from other development concepts (for example, a fixed platform serving as a host for subsea development). One area that does differ is the need to account for vessel motion that can be induced by environmental forces on these floating production facilities. In these conditions, production separators require specialized designs.
Chemical Injection
Fluid problems in deepwater are critical issues (such as colder seabed temperatures, produced water, condensates, paraffin, and asphaltene contents in the oil) that can compromise the viability of a development project. To remedy that concern, chemicals are being increasingly relied on for production assurance. The use of chemicals in offshore oil production processes is not a new approach. Some of the chemicals used are corrosion inhibitors, workover/packer fluids (weighted clear fluids, bromides, chlorides, etc.), hydrate and paraffin inhibitors, defoamers, solvents (soaps, acids), glycol, and diesel. These chemicals are typically used for batch treatments, small-volume continuous injections, and remedial treatments such as workover operations. Material safety data sheets are required for all chemicals used offshore. Corrosion inhibitors are used to protect carbon-steel components of the production systems that are wetted by the produced fluids. Material selection is a critical factor in the proper design of a production system, requiring information about the composition of the produced fluids.
Hydrate Inhibition
Hydrate inhibition is normally associated with batch treatments for the processes of start-up and shut-down (planned or unplanned). Continuous injection also occurs when there is induced cooling likely due to chokes and the natural cooling of pipelines by the cold ambient temperatures of the seabed. Methanol is one of the most common hydrate inhibitors used, particularly for subsea wells and in arctic regions where rapid cooling of the produced fluid flow (gas and water) can cause hydrate formation. Methanol is injected into the tree and sometimes downhole just above the subsurface safety valve while the fluids are hot. Some subsea developments in the deepwater GoM area inject methanol at rates of 20% to 40% of the water production rate.
Paraffin Inhibitors
Paraffin inhibitors are used to protect the wellbore, production tree, and subsea pipelines/flowlines from plugging. The injection of these chemical inhibitors is dependent on the composition of the produced fluids. Injection can occur continuously at the tree, pipeline, manifold, and other critical areas while the production flow is hot, and to batch treatments at production start-up and shut-down processes. The wax content, pour point, and other factors are determined prior to beginning production to determine the chemical(s) needed, if any, and the best method for treatment. For a 10,000-BOPD (Barrels of Oil Per Day) well, the paraffin inhibitor could be injected at a rate of 30,000 gal per year (enough to ensure a 200-ppm concentration in the produced fluid flow).
Asphaltene Inhibitors
Asphaltene inhibitors are injected in the same manner as other inhibitors, but on a continuous basis. Asphaltenes can form in the production system as the pressure declines to near the bubble point. Most development projects require one or all of these chemical inhibitors to avoid produced fluid problems. Efforts are under way to improve the performance of the inhibiting chemicals and to reduce the toxicity of the chemicals.
Well Testing
Flow testing is done to confirm the producibility of the reservoir and to locate any boundary effects that could limit long-term production. In some instances, an extended well test may be necessary to confirm the development potential. A well test could last for several days to a month. For an extended test, the actual production time (well flowing) is typically less than one-half of the total test time. Significant data are gathered about the system from the pressure build-up stage of a well test. Oil recovered as part of the well test will be stored and reinjected, burned, or transported to shore for sales or disposal; gas is normally flared during the test.
Inspection and Maintenance
Facilities and pipelines require periodic inspections to ensure that no external damage or hazards are present that will affect the system’s integrity. Unlike the shallow-water platform and subsea completions where diver access is possible, a deepwater system requires the use of ROVs for surveys and some repairs. For floating systems such as the TLP (Tension Leg Platform), the survey would examine the tendons as well as the hull and production riser. Inspections of other systems would investigate the mooring system components as well as the production components (trees if subsea, pipelines, risers, umbilical, manifold, etc.). Many of the components of subsea equipment are modular, with built-in redundancy to expedite retrievals in the event of a failure. Mobilization of a drilling rig or specialized intervention vessel would be required for intervention into any of the subsea systems. If the production equipment is surface based, the maintenance, retrieval, and repair would be similar in scope to the conventional fixed platforms.
References
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[2] C.W. Burleson, Deep Challenge: The True Epic Story or Our Quest for Energy Beneath the Sea, Gulf Publishing Company, Houston, Texas, 1999.
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[4] Minerals Management Service, Deepwater Gulf of Mexico 2006: America’s Expanding Frontier, OCS Report, MMS 2006-022, 2006.
[5] J. Westwood, Deepwater Markets and Game-Changer Technologies, presented at U.S. Department of Transportation 2003, Conference, 2003.
[6] FMC Corporation, Subsea System, http://www.fmctechnologies.com/en/SubseaSystems.aspx, 2010.
[7] H.J. Bjerke, Subsea Challenges in Ice-Infested Waters, USA-Norway Arctic Petroleum Technology Workshop, 2009.
[8] International Standards Organization, Petroleum and Natural Gas Industries-Design and Operation of the Subsea Production Systems, Part 1: General Requirements and Recommendations, ISO, 2005, 13628-1.
[9] International Standards Organization, Petroleum and Natural Gas Industries-Design and Operation of the Subsea Production Systems, Part 6: Subsea Production Control Systems, ISO, 2000, 13628-6.
[10] M. Faulk, FMC ManTIS (Manifolds & Tie-in Systems), SUT Subsea Awareness Course, Houston, 2008.
[11] C. Horn, Flowline Tie-in Presentation, SUT Subsea Seminar, 2008.
[12] S. Fenton, Subsea Production System Overview, Vetco Gray, Clarion Technical Conferences, Houston, 2008. [13] P. Collins, Subsea Production Control and Umbilicals, SUT, Subsea Awareness Course, Houston, 2008.
