Downhole power unit overcomes HPHT problem

Economically setting sump packers by wireline saves Chevron’s Tahiti deepwater project significant rig-time cost. 

Jack Clemens, Halliburton and Luis Rivas, Chevron

The Tahiti project in the GOM is developed in a deep, high-pressure reservoir that produces some unique challenges, Fig. 1. Chevron is the project’s operator with a 58% working interest along with partners Statoil (25%) and Total (17%). Tahiti is about 100 mi south of Louisiana in 4,100 ft of water with the main pay at about 26,000-ft subsea, Fig. 2.

Fig. 1. The technical challenges at Tahiti are many and varied.

Fig. 2. The Tahiti project is located about 100 mi south of Louisiana in 4,100 ft of water.

Chevron had successfully completed a test well in this area, and at that time, it was the deepest successful well test run in the GOM. The BHP at Tahiti is about 20,000 psi, and the wells are capable of making 25,000 bopd. The partners wanted to find an alternative to the traditional jointed tubing-conveyed, hydrostatic setting of sump packers in these deep wells and approached Halliburton with the problem. Typically, setting a sump packer at about 25,000 ft with these tools can take 48 hr of rig time.

Given the high rig rates, Chevron was looking for alternatives to setting packers on pipe. With five wells to be completed, in Tahiti Phase 1, the cost savings had the potential to be multiplied five times, if wireline could be used.

Common explosive-type wireline setting tools have a hydrostatic pressure operational limit well below Tahiti’s 20,000 psi BHP. The question was, “Is there a method to set the sump packers at the extreme HPHT environment reliably on wireline?” Deploying a sump packer for the first completion on the Tahiti project was targeted for September 2006.

Each Tahiti well was planned with a sump packer at the base of the completion in which to place the lower interval’s sand control screen. Since conventional electric-line (E-line) setting tools could not be used to set sump packers, bridge plugs or retainers at Tahiti’s depths and pressures, the only way was to set those same tools on jointed pipe. At Tahiti’s depth, a round trip to run and set the tools with the workstring would require at least two days.

The service company proposed using the Downhole Power Unit (DPU), an electromechanical setting tool, to set the sump packer on wireline. The proposal was to deploy the DPU using the wireline units that were on Transocean’s Cajun Express, and Discoverer Deep Seas, dynamically positioned, fifth-generation semisubmersibles capable of drilling to 35,000 ft.

Since setting the sump packer with conventional wireline explosive setting tools was investigated and determined not to work at Tahiti’s depths and pressures, the companies focused on qualifying the DPU for the project’s high pressures.

The DPU has been used to set wellbore sealing devices for over 10 yr. The E-line DPU is powered with the surface DC power supply through the conductor cable. This tool is rated for 20,000 psi collapse, 200°C (400°F) and 60,000 lb of shear force. It has an 8.75-in. maximum effective setting stroke, similar to most explosive wireline setting tools.

Since the DPU is an electromechanical device, the 60,000-lb shear force is available through the entire setting stroke. DPU design calculations and FEA analysis indicated that DPU operation at Tahiti’s well conditions would be within the allowable engineering limits.

The project required setting a 97/8-in. sump packer in a well environment at 26,500 ft, with 20,400 psi BHP and 200°F in 14.8-ppg ZnBr completion fluid. A shear force of 55,600 to 63,840 lbf needed to be delivered. The heavy-weight ZnBr fluid was required to balance BHP when the well was perforated after the DPU set the sump packer. The DPU, when configured with lower threaded connections, simulates a conventional setting kit that is compatible with the sump packer connections and stroke requirements.

Since the well’s proposed environment pressure was extremely high, a test plan was proposed to validate DPU operation. The well environment caused mechanical concerns including high hydrostatic pressure, O-ring leakage, power-rod seal leakage and excessive electric-current requirements due to seal squeeze on the power rod.

The environment also caused system concerns including wireline drag requirements at extreme depths (requiring Cerberus modeling for each well), electric-line cable integrity and conductor current leakage, as well as tool string current demands during the setting process.

The test would be conducted in four phases:

• Simulation of packer-setting stroke at atmospheric conditions
• Test under pressure and temperature with a shear-test fixture
• Full-scale system integration test with surface equipment, conductor cable and tool string
• SIT test-setting of the sump packer in casing at pressure and temperature.

These tests validated DPU operation at the extreme operating limits, and would provide the economic value Chevron desired.

DPU DESCRIPTION

The DPU can be run on slickline, braided line, E-line or coiled tubing. The tool can be powered either by batteries for slickline operations or by a surface DC power supply for E-line operations, Fig. 3. It has several characteristics that enhance the setting process and safety of operation:

• Non-explosive activation. Since the DPU is electromechanical, there are no special transportation issues, no radio silence during operations is required and it does not require explosive-trained personnel.
• Setting speed of about 0.5 in./min. The ultra-slow positive setting speed allows the slips on wellbore sealing devices to slowly latch into the tubing. The sealing element on the wellbore sealing device gradually expands, allowing a positive 360° form-fit to the tubing/casing ID.
• The setting force is enhanced with hydrostatic pressure, allowing operation in HPHT wells. In contrast, the output setting force for explosive setting tools decreases when the hydrostatic pressure rating is exceeded.
• The device can produce the maximum-rated setting force throughout the entire stroke. Explosive setting tools have a peak setting force that occurs at a particular location during setting.
• Power can be applied while the tool strokes inward or outward.

Fig. 3. The DPU is an electromechanical setting tool that was used to set the sump packer on wireline.

The operating parameters for this application equaled or slightly exceeded published DPU operating limits. Although the DPU had performed successfully in normal service worldwide for years, this was its first HPHT service. Thus, extensive testing was required to validate successful, reliable operation.

TESTING

Four testing phases were proposed for this project, which tested two E-line DPUs.

Phase 1-Hydraulic test stand DPU/sump packer simulation. The test’s purpose was to verify that electric current and mechanical forces at the required peak shear test were within the DPU’s scope. The tool’s operating voltage and current were recorded during the packer simulation testing.

The first phase of testing was to attach the tool to the hydraulic test stand and simulation of the packer-setting shear events. The test stand is a hydraulic cylinder that creates forces, up to 116,000 lb, against the DPU equal to all the shear events during packer setting. The forces created are spaced the same as in the packer setting process.

The DPU performed successfully during the hydraulic test stand simulation.

Phase 2-High pressure and high temperature shear. The purpose of the test was to verify that electric current and mechanical forces at the required 64,000 lbf-peak shear test were within the DPU’s scope. The tool was tested in a pressurized chamber at 275°F and 21,000 psi. This test environment exceeded the tool’s maximum-rated pressure and shear value.

The tool has internal atmospheric pressur, and the hydrostatic pressures “assist” the tool by reducing current demands on the electric motor. The tool’s nominal peak shear force is 60,000 lb and nominal peak pressure rating is 20,000 psi. The operating voltage and current was recorded and plotted during testing. This information is valuable during Phase 4.

After successfully setting the sump packer in the HPHT environment, the DPU was disassembled and inspected for irregularities. Post-job inspection showed that all components operated normally. The DPU passed this testing phase.

Phase 3-SIT test with wireline unit. Two E-line DPUs were successfully tested on a wireline unit with a full cable spool to verify that adequate electric power could be provided. The power requirements are high, and a validation test was conducted to assure that power could pass through the Gamma/Casing Collar Locator (G/CCL) , mounted above the tool.

The DPU power demand during a setting event is not like a typical wireline setting tool. Compensation for voltage losses through the conductor cable must be made during the entire setting process. Voltage losses in conductor lines vary depending on the resistance of the cable armor and conductor armor. Downhole temperature also affects the conductor’s voltage loss during the setting process.

Phase 4-SIT test setting sump packer in casing at pressure and temperature. The final phase set a 9 5/8-in., 62.8-lb sump packer in a section of casing while the test chamber was at 20,000 psi and 275°F. A logging unit supplied power. Two different E-line DPUs were used to verify downhole DPU operation, setting two sump packers in two independent events.

The DPU was attached to the sump packer, and the complete DPU/packer assembly was placed in a test chamber, which was pressurized and heated over night. The wireline unit with cable and G/CCL tool inline activated the packer-setting process. The DPU’s operating voltage and current were recorded, plotted and compared to the Phase 2 recording.

After successfully setting the sump packer in the HPHT environment, the DPU was disassembled and inspected for irregularities. Post-job inspection showed that all components operated normally during the extreme conditions.

SUMP PACKER SETTING

Safety issues were discussed at the wellsite prior to starting the job. Prior to running in the well, a surface shear test was conducted with the DPU connected to the service company’s tool string. The purpose was to confirm that the E-line DPU was configured correctly, the tool string above the DPU was configured correctly and that surface voltage, voltage at DPU and current during the setting process was satisfactory.

The surface shear test is imperative for successful DPU operation. A junk basket and 8.5-in. diameter gauge ring was run to 27,095 ft prior to running the DPU into the well. The wireline unit was equipped with 36,000 ft of wireline. This wire is rated for about 25,000 lb and has a working limit of about 15,000 lb.

The DPU was prepared for the packer by attaching an adapter kit that configures the lower DPU connection. On November 20, 2006 at 3:15 p.m., the DPU was attached to the G/CCL tool string. Power was applied to confirm that the DPU was operating correctly. The power rod was stroked in 1/16-in. This confirmed that the DPU and tool string were configured correctly.

Next, the packer was attached to the DPU. Then, the tool string with DPU and packer was lifted and placed into the well, Fig. 4. The hanging weight of the tool string in air prior to placing in the well was 1,130 lb. The assembly was started into the well and logged up three times to correlate depth.

Fig. 4. After the packer was attached to the DPU, the tool string with DPU and packer was lifted into the well.

The tool string was parked at 26,996.5 ft (hang weight of 8,610 lb) and the DPU was activated to set the sump packer. The tool string was then picked up and set back on the packer to verify its location and setting.

At about 8:50 p.m., the wireline tool string began pulling out of the hole and by 1:00 a.m. the string was at the surface. When the tubing was tripped back into the well, the tubing was set down on the packer and 30,000 lbf was applied to verify that the packer was fully set. The packer did not move.

CONCLUSION

The economic goal set by Chevron was met. Successful setting of the sump packer on wireline saved at least 24 hr of rig time, resulted in a significant savings. Since this successful job, the DPU has been used to set four sump packers and two cement retainers during phase 1 of the Tahiti Project. The service company has run an additional 20 jobs with these tools in similar environments for Chevron and other clients.  

THE AUTHORS
	Jack Clemens earned a BSME from the University of Arkansas in 1971 and is a registered professional engineer in Texas. He has over 20 years with Halliburton and other oilfield related jobs prior to Halliburton. Clemens’ interests are downhole electromechanical tools that are used in wireline and perforating. He has eight patents and has co-authored numerous technical papers. Clemens is a technical advisor in the Halliburton Wireline and Perforating Group.
	Luis F. Rivas earned a BS degree in petroleum and natural gas engineering from Pennsylvania State University and has 30 years’ experience. He has worked for Chevron since 1980 in a variety of drilling, completion and production engineering roles in the Gulf of Mexico, Rockies and California. Rivas is presently senior completion engineering advisor with Chevron North America Upstream for the Tahiti Project Team in Houston, Texas.