An Electrically Heated Buried Gathering System Transports High-Pour-Point Crude Oil
- R.W. Myers (Continental Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1978
- Document Type
- Journal Paper
- 890 - 894
- 1978. Society of Petroleum Engineers
- 4.2 Pipelines, Flowlines and Risers, 6.5.2 Water use, produced water discharge and disposal, 4.1.5 Processing Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 5.4.1 Waterflooding, 4.2.4 Risers, 4.1.7 Electrical Systems, 4.1.9 Tanks and storage systems, 4.5 Offshore Facilities and Subsea Systems, 7.2.3 Decision-making Processes, 2.4.3 Sand/Solids Control
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This paper describes two electrical heating systems that are being used successfully on buried flowlines transporting crude oil with 70 to 90 degrees F pour points. The electrical systems, insulation, and protective outer jackets are discussed. Installation and operating costs and problems also are presented.
The Dickinson Heath Sand Unit (DHSU) is located about 1 mile north and 1 mile west of Dickinson, N.D. (Fig. 1). This unit has 37 producing wells, one water well, and 14 injection wells located in 26 sections, The wells are completed in the Heath sand at 7,900 to 8,100 ft and produce 33 to 35 degrees API crude oil with pour points produce 33 to 35 degrees API crude oil with pour points of 70 to 90 degrees F.
A waterflood began in Dec. 1973. Production has not peaked. The unit produced 4,409 BOPD and 4,600 peaked. The unit produced 4,409 BOPD and 4,600 BWPD with water injection rates of 9,800 B/D during June 1977.
Before unitization, each well had its own tank battery. The heater treaters were located about 120 to 200 ft from the wellhead. Even with these short flowlines, pressures of more than 2,000 psi sometimes were needed to displace the congealed crude oil.
After the waterflood began, a water gathering system was necessary. Because this system would cost $1,300,000, a total produced-fluids gathering system with one central battery was economically attractive. Therefore, many methods of transporting the high-pour-point crude oil were investigated and evaluated. However, most methods were either too expensive or the flowlines would be plugged after a long shutdown. The only way to remove the congealed oil would be to install pump-out risers about every 200 to 500 ft and displace the oil with hot water under high pressure.
Two methods for electrically heat-tracing insulated lines were found that appeared feasible for the gathering system. These were the Skin Effect Current Tracing (SECT) and the Thermon systems. It was decided to test these systems on four lines in 1974.
The SECT System
Principle Principle The SECT heating element used in our system is a 1/2-in. Schedule 40, black iron pipe that is welded to the carrier pipe. The welds are spaced evenly the entire length of the pipe. The welds are spaced evenly the entire length of the carrier pipe with 2-in. passes separated by 2-in. open spaces. The welding attaches the heating element (or "heat tube") to the pipe and provides a heat path to the pipe. A single, insulated copper wire passes through the pipe. A single, insulated copper wire passes through the center of the heat tube and is connected to the heat tube at the far end (Fig. 2). Alternating electric current flows through the wire and the heat tube and creates heat by the resistive loss of the well known I2R principle (Joule's law). The magnetic fluxes surrounding the current in both the tube wall and the wire concentrate in the inner wall of the heat tube because of the high magnetic permeability of mild steel. The interaction of these two fluxes creates the "skin effect" that causes the current in the heat-tube wall to concentrate near the inner surface (0.005 in.) and be essentially nonexistent at the outer surface.
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