Production Report: Multiphase pumps replace conventional heavy oil facilities

Sept. 24, 2001
Multiphase pumps (MPPs) offer a potential for reducing environmental risk, improving project cycle time and reducing life cycle costs for some properties in the Midway Sunset field.

Multiphase pumps (MPPs) offer a potential for reducing environmental risk, improving project cycle time and reducing life cycle costs for some properties in the Midway Sunset field.

Texaco California Inc. (TCI) first applied multiphase pumping (MPP) technology as a means for maintaining production from the Midway Sunset diatomite project until regulatory permits were obtained for permanent facilities. But performance results since March 2000 indicate that these pumps are competitive with conventional production shipping facilities for some of TCI's Midway Sunset thermal heavy oil projects.

These pumps compared to some conventional production shipping facilities offer potential for improving project cycle time, reducing life cycle costs, and reducing environmental risk.

At the end of July 2001, TCI had three Bornemann MW series MPPs in operation in the area. These pumps boost production from flowing diatomite wells and lower back pressure on rod pump well stuffing boxes and flowlines.

Diatomite applications

The Midway Sunset field is in a hilly area, with elevation differences varying up to 350 ft (Fig. 1).
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TCI first applied multiphase pumping in the Section 21 South diatomite project in Midway Sunset field, about 40 miles southwest of Bakersfield, Calif. The project area is hilly, with elevations varying by as much as 350 ft (Fig. 1). Production is from a diatomite formation that has high porosity and low permeability and requires cyclic steam fracturing to produce.

The 40 producing wells in the project are first fractured with steam and then flow oil, water, and gas through lead lines to central automatic well test facilities (AWTs) for gathering and testing.

The system allows four wells per AWT site to be steamed concurrently. The remaining wells flow at different stages in their production cycles.

Production shipping facilities include pumps to pump produced fluids from the AWT sites to dehydration facilities, which have vapor recovery systems.

TCI initially produces individual diatomite wells into portable tanks, but after a 6-month test period, the wells must be tied into permanent permitted facilities, having vapor recovery systems.

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Typical diatomite wells initially flow at high pressures, rates, and temperatures and adjustable chokes control the production rates from individual wells. After several days, well production rates, pressures, and temperatures decline (Fig. 2).

In early testing, TCI determined that diatomite wells were sensitive to back pressure towards the end of a production cycle. These wells at the end of their production cycle have unloaded up to 100 bbl of oil into portable tanks over 1 night..

The multiphase pump replaced the conventional production shipping facilities that were never used (Fig. 3).
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TCI's first permanent diatomite facility design included a fin-fan heat exchanger to cool fluids before the fluid entered three permanent tanks (Fig. 3). From there, duplex pumps would pump produced fluids to dehydration facilities. But TCI decided not place such a facility in operation after its success with MPPs.

During summer 1999, portable tank test periods expired for one of two Section 21 South diatomite AWTs (AWT 156). Because TCI had not received tank permits for a permanent facility, it made attempts with limited success to pump directly from the AWTs to the facilities, having vapor recovery systems, using duplex and later progressive cavity pumps.

The duplex pumps had problems with gas locking, and suction pressure (back pressure on wells) had to be maintained above 100 psig. In an attempt to handle the gas, TCI installed a progressive cavity pump (PCP) but found that the PCP stators could not handle the high fluid temperatures, greater than 250° F.

The temporary tank test period expired for Section 21 South AWT 189 during December 1999. AWT 189 was removed from the temporary tanks and tied into the Section 21 South diatomite production shipping facilities, where both AWT 156 and AWT 189 production tied in directly with the duplex pump inlet. Fig. 4 shows the production rate decrease caused by this arrangement.

After a Texaco surplus Bornemann MPC208 multiphase pump became available, TCI installed it during March 2000 to replace the duplex pumps. Although the manufacturer recommended a MW model pump for heavy oil, high-temperature applications, the MPC208 allowed TCI to test multiphase technology and possibly increase production rates from the project area for the short-term while waiting for tank permits.

The MPC208 pump screws and motor were changed to meet the following operating conditions:

  • Production-1,500 bo/d, 1,500 bw/d, 30 Mcfd of gas, and 40% oil cut.
  • Pressure-15 psig suction and 300 psig discharge.
  • Temperature-Maximum 300° F.
  • Oil properties-13° API gravity, and viscosity of 6,155 cp at 80° F. and 38 cp at 210° F.

The multiphase pump installation had to meet the following four criteria to be competitive with a tank installation:

  1. Handle a wide range of production rates, water cuts, pressures, and temperatures.
  2. Maintain low back pressure on the AWTs (20 psig).
  3. Be reliable and simple to operate.
  4. Be cost competitive with conventional facilities.

Several early control tuning problems caused pump shut downs over the first several weeks that the MPC208 operated. One problem caused mechanical seal damage.

After TCI resolved the control problems, the MPC208 pump performed satisfactorily for about 6 months before another seal failure. TCI believes the cause for the last seal failure was a result of a combination of the following:

  • Repeated starts and stops during the summer electrical power curtailments allowed solids to collect near the seal face.
  • The MPC design allows dirty produced fluids to contact the seal face while the pump is operating.
  • The MPC design places pump discharge pressure on mechanical seals, while the MW series places suction pressure on mechanical seals.
  • After operating at 460-500 rpm for over 5 months, TCI increased the pump speed to 1,200 rpm after changing pipelines.

TCI recognized the environmental benefits of operating a closed system such as the MPP and decided to use MPPs instead of convention facilities for the project. The MPP installation had almost no potential for a spill of oil, water, or gas, while the conventional system had tanks that could over flow or leak, fin fans with pressure relief valves that may open during upset conditions or tubes that may leak, and tank vapor recovery systems that could break down.

The MPP pumped the diatomite oil, water, and gas production from the production shipping facility to the nearest dehydration facility with an operating vapor recovery system. Initially a 6-mile, 8-in. production shipping line was used. This existing line went through hilly terrain and had several high points where gas accumulated.

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High pipeline pressure limited the MPC208 rates for a 5-month period (Fig. 4). During September 2000, production was switched over to a closer plant, 1.5 miles from the site, where vapor recovery had been installed. Rates increased slightly but continued to be limited by the pipeline (Fig. 4). The MPC MPP experienced a seal failure about the same time and was shut down.

Based on the benefits and results of the MPC208 test, TCI replaced the MPC208 with an MW series pump during November 2000. The MW series pump is designed for foamy crude oil. It has an internal API 32 seal flush system, improved bearing cooling for high temperature applications, and mechanical seals that are not exposed to produced fluids.

TCI installed the new MW pump and switched production to an existing 1.5 mile, 6-in. line. The 6-in. line crossed only one hill and gently sloped downward to the dehydration facilities. Pump discharge pressures fell from 300 psig to about 220 psig, pump suction pressures fell to as low as 20 psig, and production rates increased threefold (Fig. 2).

With the exception of planned shut downs, the MW pump has operated 24 hr/day and 7 days/week to July 2001. Pump rates averaged 2,500-3,000 b/d.

TCI installed a second MW MPP in parallel with the first pump during June 2001 and this pump also has been in operation 7 days/week and 24 hr/day. Rate increased to about 4,000 b/d oil and water (Fig. 2), but the rate was lower than the objective 6,000-b/d oil and water capacity.

The gas volume fraction (GVF) appears to increase as more diatomite wells at the end of their production cycle respond to lower back pressure from the MPP installation. Additional work is in progress to assess GVFs from the Section 21 South diatomite project and sizing of future MPPs.

Other MPP

TCI also installed a multiphase pump at its Indian and Colonial site (Fig.5).
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TCI installed another MPP at the Indian and Colonial site, about 1 mile south of the Section 21 South diatomite project. At this other site, three flowing diatomite wells required pumping facilities. The site also had three non-thermal AWTs facilities with pressures exceeding 160 psig.

This high back pressure on the rod pumped wells increased the potential for stuffing box and flowline leaks.

During April 2001, TCI installed a MPP in a geographically low area that took advantage of the hilly terrain with the objective of reducing back pressure as low as possible on the three diatomite wells and the three non-thermal AWTs. Cooler non-thermal production from the three AWTs was pumped with the hot diatomite wells. TCI applied the same type pump, controls, and operating philosophy used at the Section 21 South project..

To the end of July 2001, the pump has been operating 7 days/week and 24 hr/ day. The pump reduced back pressures on the diatomite wells to 0 psig. Back pressures on the non-thermal wells ranged from 0 psig to a maximum of 20 psig.

MPP Benefits

TCI's application identified several benefits of MPPs. These benefits can be broken down into three groups, environmental, capital, and operational.

The environmental benefits include:

  • Improved project cycle time by reduced regulatory permitting requirements.
  • Reduced spill potential by eliminating tanks, fin fans and lowering pressure on flow lines and stuffing boxes.
  • Smaller footprint that disturbs the natural habitat less and lowers location construction costs.

The multiphase pumps saved capital costs. For example, for the Section 21 South MPP site with one pump, the total installed cost was about two-thirds of the cost for a site with fin-fan heat exchangers, tanks, duplex pumps, vapor recovery system, and gas line.

Heat savings contributed to operating cost savings. TCI's Midway Sunset dehydration facilities uses heat as part of the process and heater treaters require the purchase of natural gas. In comparison to the fin-fan-tank-pump system, the MPP does not require fluid temperatures to be cooled prior to pumping.

The MPP can pump over 300° F. fluids to the dehydration facilities compared to less than 200° F. fluids for the fin-fan-tank-pump facility. This additional heat saves fuel at the dehydration facilities.

Other operational benefits of MPPs include less major equipment to operate and maintain, low shear of produced fluids, ability to pump 100% gas for up to about 15 min, ability to handle high temperature fluids, and less occurrence of leaks than with progressive cavity or duplex pumps.

Future applications

TCI at the Midway Sunset field plans for additional lease consolidations by abandoning several of its small dehydration facilities that separate oil, water, and gas. Associated production will be sent to larger more efficient dehydration facilities. MPPs may be installed at sites that require high pressures to pump fluids to the central facilities.

TCI also plans to eliminate or down size the casinghead-gas gathering systems in mature areas. These systems at Midway Sunset are mature and will require repairs. The systems lose heat to the atmosphere from the fin-fan heat exchangers. Alternately multiphase pumps would transfer this heat to the dehydration facilities and reduce fuel used in the plants.

MPPs also can be used to lower back pressure on other Midway Sunset AWTs and wells. Many of these wells produce against back pressures as high as 160 psig. Results from the Indian and Colonial MPP application indicate that MPPs have the potential to reduce these back pressures with the following benefits:

  • Reduced stuffing box leaks.
  • Extended useful life of lead lines and flowlines.
  • Extended life of downhole rod pumps, under evaluation.
  • Higher production rates, under evaluation.

Acknowledgments

The author thanks the following for help in preparing this article: D.E Korn, F. Ornelas, D. Hoyt, R. Newly, and J. Fuson of TCI, J. Kinser of Bornemann Pumps Inc., and F. Bullentini of Bay Tech Associates.

The author

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R.J. Corless is a senior operations engineer for Texaco Worldwide Exploration & Production Inc.'s Texaco California Inc., Bakersfield, Calif. He has worked for Texaco since 1977 in various domestic and international engineering positions. Corless has a BS in mechanical engineering from the University of Houston.