Direct Electrical Heating of Flowlines - A Guide to Uses and Benefits

Abstract Direct Electrical Heating (DEH) of flowlines is a flow assurance technology that enables development of fields with heavy oil and fields in arctic regions, fields with long subsea tiebacks, and marginally profitable offshore fields. By allowing for operation in conditions outside of the hydrate region and/or above the wax appearance temperature, DEH opens up areas of development not otherwise considered viable by production companies and can significantly reduce CAPEX and OPEX for already-viable fields. This paper provides an explanation of Electric Flowline Heating (EFH), both Direct and Indirect Electrical Heating, including how the technology works, the different types of systems, and the modes of operation. A listing of currently installed systems is also provided. A case study is used to illustrate the purpose and benefits of DEH, including improving the flow of heavy oil, prevention and remediation of hydrates and paraffins, extended shutdowns without the use of chemical injection or hot oil circulation, elimination of infrastructure for such chemical injection and hot oil circulation, reduction in associated CAPEX and OPEX, handling of high water-cut during tail end production periods, and third-party tie-ins with poorly-defined composition. Finally, considerations for expanding the applications of DEH are discussed. As interest in and usefulness of Direct Electrical Heating grows, the applications considered for DEH as a flow assurance solution become more challenging, such as whether DEH can be used for hydrate plug remediation, whether it can be used in continuous flowing conditions, and maximizing the length of a heated segment. All of these are questions and opportunities that are being addressed as the technology evolves. Introduction The potential for hydrate and/or wax formation is often a limiting factor in development of deepwater and ultra-deepwater, heavy-oil, and arctic fields. Many " marginally profitable?? oil and gas fields become economically viable only if the costs of a local host can be avoided. So tie-back lengths are on the rise, transporting the production stream greater distances from the subsea field to an existing near-by host or to a new host shared by a number of reservoirs spread over a large area. These greater distances result in higher temperature drops along the length of the flowline, resulting in a topsides arrival temperature relatively cool as compared to the reservoir and wellhead temperatures. Similarly, in deepwater and arctic developments, the heat lost from the production flow to the cold seawater causes a very low arrival temperature even in shorter flowline lengths. Although pure oil or pure gas flows would be less challenging to manage, the reality is that most reservoirs produce a multi-phase product (a combination of oil, gas, and water). At the low temperatures of deep and arctic waters, and over the long tie-back lengths of marginal fields, as the temperature of the production flow drops, the gas and water form hydrate crystals, similar to ice flakes. For reservoirs with heavy oil, the temperature of the product along the flowline and riser must also be maintained to ensure suitable flow. Wax content in the production fluid can also cause flow assurance concerns, and in this case, the temperature in the production flow must be maintained above the wax appearance temperature to avoid wax deposits coating the flowline walls and eventually restricting flow.

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