ESPS ADD PRODUCTION CAPACITY TO DEEP, HOT, AND GRASSY CALIFORNIA WELLS

W. Jeffrey Dittman, Anthony W. Marino, Keith L. Jones
ARCO Oil & Gas Co.
Bakersfield, Calif.

D.E. Baker
Centrilift
Bakersfield, Calif.

Based on performance to date, electric submersible pumps (ESPs) are a technical and economical option for artificial lift in the Yowlumne field where well conditions include bottom hole temperatures of 260 F., gas/oil ratios over 400 scf/bbl, and water cuts as low as 6%. Also, H2S, CO2, and scale (calcium carbonate and barium sulfate) are present in most wells.

Since November 1989 four ESP systems have been successfully installed to depths up to 11,800 ft. The first pump ran for 516 days while producing more than 1 million bbl of oil.

Hydraulic jet pumps were the predominant lift system before the ESPs.

Special design considerations addressing the unique operating conditions included oversized high-temperature motors, flat lead-sheathed cables, and variable-speed controllers.

Quality control during the installation phase involved witnessing prerun pump tests, on site pressure testing of seal sections, and ensuring adherence to proper running procedures by rig personnel.

The economics for the ESP installations were based only on oil rate acceleration, even though numerical reservoir simulation indicated that ultimate oil recovery would increase as well.

YOWLUMNE FIELD

The Yowlumne field is 25 miles southwest of Bakersfield in Kern County, Calif. (Fig. 1). Production is from the Stevens sand, a Miocene age turbidite deposit at an average depth of 12,700 ft.

The field was discovered in 1974 and unitized in 1982 for pressure-maintenance purposes. ARCO Oil & Gas Co. (AOGC) became field operator in 1988.

Current production rate from the Yowlumne field is 9,000 bo/d from 55 producing wells (Table 1).

Prior to AOGC's first ESP installation in 1989, the primary artificial lift system in the field was hydraulic jet lift.

The previous field operator had tried an ESP in 1985, but gave up after disappointingly short runs.

Although hydraulic units are capable of lifting up to 1,500 bbl of liquid/day, production from the most prolific wells was restricted by jet lift capacity. Moreover, the gas engines for powering the hydraulic units generate air pollutants and the power oil creates a potential safety hazard.

For these reasons, AOGC began equipping several of its new wells with ESPs.

ECONOMICS

The capital cost for an ESP on a new Yowlumne well was about $50,000 less than for an hydraulic installation. However, the operating cost for an ESP was expected to be about 60% higher.

The higher operating cost was mainly due to the ESP using electricity instead of lower cost lease gas. The estimated operating cost was based on 1-year ESP runs.

The main reason for an ESP in a new Yowlumne well was to increase production rate. Reservoir simulation indicated that increased withdrawal rates would increase ultimate recovery. Nevertheless, to keep the economic analysis conservative, the incremental present worth estimate for the ESP was based on rate acceleration alone.

Projected costs and production rates for the alternative lift systems are summarized in Table 2.

The sensitivity of incremental economics to well productivity and ESP run life was also investigated before deciding to run the ESP.

ESP installations proved desirable even if new well productivity was only 70% as high as anticipated. Minimum run life for an ESP to be competitive with hydraulic lift was 100 days.

DESIGN

The initial design of an ESP system for the Yowlumne field proved to be difficult for a number of reasons.

First, very little information was available from the previous ESP attempt by the former field operator. ln addition, high bottom hole temperatures, high gas/oil ratios, low water cuts, and the presence of H2S, CO2, and scale complicated the design.

Finally, because the well was new, no production history existed for designing the first installation.

These circumstances made AOGC take an extremely conservative approach to the design of the ESP equipment. This approach may be the greatest single factor in the success at Yowlumne.

VARIABLE SPEED

It was decided during the early design stage that a variable-speed controller (VSC) would be used on the first installation. A VSC allowed for a wide range of producing rates in the event actual well performance differed from predictions.

From an operational standpoint, reduced mechanical and electrical stresses on start-up as well as programming for gassy conditions were added benefits. VSCs have proven to be cost competitive when compared to an across-the-line (60 hz) service with soft-start capability.

The size of the VSC is based on the maximum anticipated load on the system. This typically is the maximum production rate at 90% water cut.

Once the appropriate data are available actual pump sizing usually is done with the vendor's computer program. The program develops a pump curve superimposed over the well performance curve.

In addition, well performance can be compared to the pump's minimum operating, best efficiency, and maximum operating curves to ensure optimal operation.

The goal of sizing pumps for the Yowlumne wells has been to size the pump such that the system operates midway between the best efficiency and maximum operating curves (Fig. 2). This is done to prevent harmful downthrust wear to the equipment that can occur in the lower flow region.

TEMPERATURE

Motor selection has been based on the manufacturer's recommendation to run a high-temperature design motor rated to at least 350 F. These motors typically contain special epoxy insulation systems which have excellent mechanical properties for winding protection as well as good heat dissipation characteristics to help reduce motor heat rise.

As previously mentioned, high bottom hole temperatures have always been a primary concern.

One way to minimize motor temperature rise is to operate the motor at light loads. The method used takes the maximum possible load (typically maximum rate with a water cut of 90%) and sizes the motor to handle these conditions.

In the initial operation of the system, with low water cuts, the actual motor load can be as low as 50% of rated horsepower. This leads to lower motor operating temperatures and longer run lives.

CABLE

Cable design for the Yowlumne wells has been dictated by high well temperatures, high gas/oil ratios, and the presence of H2S.

The decision was made to use a premium ESP cable (rated to 400 F.) having superior mechanical and electrical characteristics. Initial cable designs on most wells, based on anticipated motor loads, showed that a No. 2 AWG cable would be satisfactory.

However, No. 1 AWG 5 ky cable was chosen to minimize voltage losses and related heat rise in the cable. No. 1 cable has been run in all Yowlumne installations for this reason.

Lead sheathed cables have been used for the following reasons.

First, the lead sheath prevents H2S from attacking the copper conductors. Secondly, lead minimizes diffusion of hydrocarbon gases into the insulation. These gases can cause explosive decompression when the cable is pulled.

The concern over hydrocarbon gases was based on other operators' experiences in deep, gassy wells. AOGC's experience shows that cables pulled from Yowlumne wells appear to be in excellent condition, both electrically and mechanically.

SEALS

Tandem seat sections in all installations ensure that the motor is protected from well fluid contamination. In most cases, two, three-chamber labyrinth sections with a high-density blocking fluid have provided sufficient protection.

Initially, rubber bladders were not used because of concerns over the effect of high temperatures. Mechanical design features in the seal section have included increased tolerances of running surfaces, tungsten carbide mechanical seals, and babbittless thrust bearings for improved run life. However, a subsequent installation included a special high-temperature elastomer bladder with no apparent problems.

GAS SEPARATOR

Rotary gas separators were installed in most wells to minimize the potential for gas locking the pump. The separator typically includes a low net positive suction head (NPSH) stage to generate stable pressure into the separation chamber.

The separation chamber is designed to centrifugally separate liquids from free gas. The free gas is vented through a crossover diffuser into the well bore while liquids are fed directly into the pump.

It should be mentioned that some of the design features now being used have been incorporated as a result of pump teardowns. The design of equipment for the Yowlumne wells continues to be an evolving process with the goal of optimizing performance as well as maximize run life.

INSTALLATION

To ensure proper installation of ESP equipment, quality control includes prerun pit tests, seal-section integrity tests, and personnel training. Quality control has been stressed due to the high economic impact of these wells.

Pit tests on each pump follow pump assembly in the vendor's shop. All tests are monitored by AOGC personnel so that on-the-spot decisions can be made in the event problems occur.

Pit test performance is then compared to the manufacturer's published catalog curve. Pumps which fall outside tolerances outlined in API RP 11S2 "Electric Submersible Pump Testing" are rejected as unacceptable.

The remaining equipment is required to also be tested, although this has not been routinely witnessed.

Several years ago, AOGC developed a procedure to test the integrity of ESP seal sections. The test is performed at the rig site following makeup of the seal section, motor, and pothead connections.

The purpose of the test is to ensure that no leaks exist in any of these areas prior to installation. The two-stage test requires the seal section to be pressured to 5 psig. Pressure is held briefly to check for leaks.

Pressure is then increased to 30 psig and held for 10 min. In addition to ensuring connection integrity, the test also forces personnel to pay close attention to this phase of installation, particularly the pothead connection.

The performance of rig personnel is key to the success of any ESP installation. As local producing fields do not have many ESP'S, finding crews experienced in running the equipment proved difficult at first.

Prior to installation, crews receive specific instructions on the care and handling of ESP equipment. In addition, crews are generally limited to running 15 stands/hr to minimize the risk of damaging the equipment, particularly the cable.

One way to improve equipment design is to perform teardown inspections following any failure. Every teardown performed, including those following successful runs, has resulted in some design improvement.

AOGC uses an ESP equipment teardown report that requires specific information on teardown findings. To ensure that a thorough inspection takes place, every teardown is witnessed by AOGC personnel.

Quality control is also emphasized in splicing techniques (taped instead of molded), use of high strength cable bands, and monitoring electrical integrity while running.

In addition, following each pull, the cable is high potential tested (hypotted) to 12,000 v dc to ensure integrity. This is performed in the field by contract personnel.

OPERATION

As mentioned previously, the primary means of artificial lift in the Yowlumne field has historically been hydraulic lift. Compared to hydraulic systems in use, ESP's have the following advantages:

Increased fluid withdrawals
Reduced oil spill potential
No on-site air emissions because no gas engine is used
Elimination of pressure vessels and high pressure piping
Reduced manpower requirements to operate and maintain

As with any artificial lift system, frequent monitoring of ESPs is essential to ensure optimum performance. Most of the useful data are provided by fluid levels, well tests, and ampere charts. Using this information, adjustments are then made using the VSC and/or a wellhead choke.

In addition, total dynamic head (TDH)-vs.-rate is plotted on the original pump curve to compare actual performance to predicted performance.

Several operating limits have been placed on these systems. For instance, 70 hz is considered the maximum allowable frequency for any pump system. This limitation was set at the manufacturer's request because of concerns about accelerated wear and its effects on equipment run life (especially the rotary gas separator).

Operating fluid levels over the pump are maintained to minimize potential for gas lock conditions.

ARCO installed the first ESP in the Yowlumne field in Well No. 88x-33 in November 1989. The future of ESP applications in this field depended on the success of the first installation, which ran 516 days before scale caused the pump to fail. During this time, the well produced more than 1 million bbl of oil, or 1,950 bo/d.

Both the equipment and the well performed significantly better than expected. This initial success prompted installation of three more ESP's during the next year. All have given excellent results (Table 3).