Direct Electrical Heating (DEH) Provides New Opportunities for Arctic Pipelines

Abstract

Abstract Direct Electrical Heating (DEH) of flowlines is a flow assurance technologythat facilitates development of fields in arctic regions, fields with longsubsea tiebacks, fields with heavy oil, and marginally profitable offshorefields. By allowing for operation in conditions outside of the hydrateregion and/or above the wax appearance temperature, DEH opens up areas ofdevelopment not otherwise considered viable by production companies and cansignificantly reduce CAPEX and OPEX for already-viable fields. It isproposed for Arctic field development, where a colder subsea temperaturecompounds typical flow assurance difficulties and where traditional chemicalinjection becomes difficult or cost prohibitive to manage. This paper provides an explanation of Electric Flowline Heating (EFH), bothDirect and Indirect Electrical Heating, including how the technology works, thedifferent types of systems, and the modes of operation. A listing ofcurrently installed systems is also provided. The purpose and benefits ofDEH are discussed, including prevention and remediation of hydrate and paraffinformation, improving the flow of heavy oil, extended shutdowns without the useof chemical injection or hot oil circulation, reduction of infrastructure forsuch chemical injection and hot oil circulation, the handling of high water-cutduring tail end production periods, and planning for third-party tie-ins withpoorly-defined composition. A case study is presented to illustrate some ofthese benefits. As awareness of DEH's benefits grows, so does interest in applying it to thechallenging environment of the Arctic. This paper discusses some of thechallenges of designing and installing an Arctic DEH system, as well as othertechnology-stretch applications such as whether DEH can be used for hydrateplug remediation (after the plug has formed), whether it can be used incontinuous flowing conditions, and how to maximize the length of a DEH-heatedsegment. Introduction The potential for hydrate and/or wax formation is often a limiting factor indevelopment of arctic fields and fields in deepwater and ultra-deepwater. In the North American Arctic, production facilities are relatively close toshore, allowing for the option of either a tie-back or export line to shore, depending on produced fluid properties and overall field developmentplans. Fields further from shore may require additional measures toensure a reliable level of flow, and even further from shore in deeper waters, concepts regarding all-subsea completions without a host facility are beingconsidered for the future. So tie-back lengths are on the rise, transporting the production stream greater distances from the subsea field toan existing near-by host or to a new host shared by a number of reservoirsspread over a large area. These greater distances result in highertemperature drops along the length of the flowline, resulting in a topsidesarrival temperature that is relatively cool compared to the reservoir andwellhead temperatures. Similarly, in arctic and deepwater developments, the heat lost from the production flow to the cold seawater can cause a verylow arrival temperature even in shorter flowline lengths.