Economic Consideration for Flowline Heat Loss Control

Abstract

Abstract Deep water developments in the Gulf of Mexico have increased the complexity of flow assurance issues due to colder environments, higher pressures, longer well offsets, and increased difficulty of problem remediation. Controlling heat losses is usually the best choice for preventing hydrate formation and paraffin deposition but is often expensive. The commercial and technical trade-offs of various methods for controlling heat losses have to be considered. Heat losses can be controlled by burying non-insulated pipe, using insulated flowlines or heated flowlines. The manufacturing and installation costs of flowline types have to be considered and compared to the cost of chemical injection systems and remediation methods. In addition to capital expenses, operating costs have to be compared for the various options. Changes in production rates during the life of the project have to be considered. System operability related to start-up and shutdown scenarios also have to be included in the design. This paper presents cost and performance comparisons of the flowline options, analyzes the merits of each type and discusses the technical trade-offs and flow assurance risks. These design issues are discussed based on several factors including fluid type, operating pressure, offset distance, and reservoir size. Performance comparisons of various flowline types are based on computer simulation. Ambient temperatures, water depths, pressures, and fluid types are typical of deep water Gulf of Mexico fields. Introduction Deepwater oil is becoming a significant component of total U.S. oil production. By the end of 1998 it exceeded 500,000 BPD and is expected to triple by 2005.1 Preventing problems such as hydrate and wax precipitation is most reliably accomplished by insuring that produced fluid stays above the temperature at which these problems occur. Although there are other methods, such as chemical and mechanical that are effective for preventing flowline blockages, this paper focuses mainly on thermal methods. The costs of chemical injection and pigging programs will vary greatly with the specific fluid type and reservoir performance. Heat contained in the fluid at the wellhead can be preserved by using the shortest possible offset distance, using the smallest pipe diameter possible to reduce flowline residence time and reducing heat loss to the environment. One of the challenges is to design a system capable of preventing problems over a wide range of production rates, pressures and water cuts. Offset distances are becoming longer as new projects are in increasingly deeper water. Some alternatives to shorter offsets are additional platforms or floating production systems. These options are usually cost prohibitive for marginal field developments. Flowline sizes are dependent on the number of flowlines and the range of production rates to be acommodated. Heat losses under flowing conditions can be reduced by insulating and/or burying flowlines. Both flowline sizing and heat loss control methods have a large economic impact on capital costs and operating expenses. Development cost decisions have to be evaluated and considered along with the possible remediation expenses associated with higher risk/lower cost options.