Reservoir characterization

Case History: High-Pressure/High-Temperature Underbalanced Drillstem Testing

This paper describes the method developed to achieve underbalanced drillstem testing (DST) in a deepwater field offshore India.

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Fig. 1—Well schematic.

This paper describes the method developed to achieve underbalanced drillstem testing (DST) in a deepwater field offshore India. DST tools rated to 450°F and 15,000-psi differential pressure were configured to maintain integrity and successfully evaluate the well potential. By use of a multicycle DST tool string, the reservoir potential was tested safely and effectively with an underbalanced test fluid in two deepwater wells, achieving the desired test objectives.

Introduction

An operator in India needed to conduct high-pressure/high-temperature (HP/HT) drillstem testing on a deep­water well with low-density clear brine in the annulus. Performing DST was necessary to assess hydrocarbon potential in the deep­water block for further field-­development plans. The DST tools performed satisfactorily for approximately 18 days during the test on a semisubmersible rig.

The well was completed in a 6-in. hole, which resulted in a 5-in. casing program, thereby creating a significant challenge. The retrievable packer suitable for the 7-in. casing was set above the 5-in.-­liner-hanger top, resulting in a tail pipe of approximately 350 m. Well killing at the end of the DST with such a long tail pipe was a challenge.

The method of operating DST tools in both underbalanced brine and kill-weight mud was developed along with a meticulously designed well-test program and a well-kill procedure with a long tail pipe below the 7-in. retrievable packer. Before lowering the DST tools, a well-integrity test was performed by conducting an inflow test for a 5-in.-liner shoe, a 5-in.-liner-hanger top, and a 7-in.-­liner-hanger top. Hermetic tests were performed to ensure that casings sustained the required annulus pressure for operation of the DST tools.

Need for HP/HT Underbalanced Testing

The anticipated pore pressure was significantly higher than the available brine weight. The use of kill-weight mud for the DST operation was considered, but high-temperature conditions, barite sagging, and solid settlement could have resulted in the retrievable packer sticking and could have presented challenges for annulus pressure transmission to operate DST tools. The kill-mud weight required was in the range of 15.8 to 16.8 lbm/gal, compared with the available brine weight of 11.4 to 13.8 lbm/gal. The bottomhole temperature was in the range of 365 to 370°F.

Slimhole DST Tools

The option of deploying slimhole DST tools suitable for a 5-in. liner was planned but was not possible because of the available time frame. Slimhole DST tools would have limited operations such as wireline correlation and slickline sampling.

Planning and Execution

The objectives and challenges of this DST job were defined as follows:

  • Determine the initial reservoir pressure and temperature.
  • Gather the bottomhole fluid sample.
  • Verify well integrity.
  • Perform underbalanced DST with reservoir pressure of 15.8 lbm/gal and temperature of 370°F at 4300‑m depth.
  • Conduct underbalanced DST of reservoir objects behind a 5-in. liner using a 7-in. retrievable packer and DST tools with a long tail pipe.
  • Execute the well-kill plan.

Equipment Preparation

After completing the logging activities, reservoir data such as bottomhole pressure and temperature were received. This information is very important for equipment preparation. Because the DST tools operate with a dual-fluid system at 370°F, all the tools were stripped and were reassembled with special HP/HT redress kits. Equipment reassembling, function testing, and pressure testing were carried out by a highly experienced DST team.

Multicycle circulating valves and multi­cycle downhole tester valves require nitrogen precharge. Because the tools were expected to operate in both underbalanced brine and kill-weight mud, a nitrogen precharge suitable to both fluid systems was performed. The single-shot rupture-disk-operated tools were also designed to operate in both fluid systems. The function test of equipment is important because the tools are required to operate in the wellbore in HP/HT conditions. The equipment-function test and pressure test were witnessed by an on-site DST engineer and the operator’s on-site well-test engineer.

Well-Test-Program Preparation and Contingency Plan

A detailed well-test program and DST-tool operating-pressure calculation were prepared by the service company’s well-test engineer and were reviewed with the operator’s well-test engineer. A detailed discussion and review were held with all involved teams to explain the detailed well-test program. The well-test program served as the reference document for every step. It covered aspects of the operation such as well information, approval for expenditure, sequence of operations, contingency plans in case of tubing leaks, leaks in the riser, string diagrams, operating-pressure calculations, risk analysis, roles and responsibilities, and lines of communication.

Well Preparation and Testing Operation: Detailed Steps

The detailed steps performed after completing drilling, lowering a 5-in. liner, and cementing are listed here. Fig. 1 above provides the well schematic. The steps to complete the well preparation are provided in the complete paper.

Completing all the steps in well preparation is critical before beginning an underbalanced tubing-conveyed-­perforation (TCP) and DST bottomhole-­assembly deployment.

The following steps were taken to perform the underbalanced DST:

  1. Make up and run in hole the TCP assembly.
  2. Make up and run in hole the 2⅞-in. tubing to serve as tail pipe in the 5-in.-liner section.
  3. Make up and run in hole the 7-in. retrievable packer and HP/HT DST tools.
  4. Make up and run in hole the 3½‑in. tubing up to seabed. The tubing was hydraulically pressure tested at very high pressures while running in hole considering the TCP hydraulic firing-head pressure and reservoir pressure.
  5. The fluted hanger assembly was made up on string and run in hole on drillpipe as a landing string.
  6. Wireline correlation was conducted to space out guns on depth.
  7. The fluted hanger with drillpipe was pulled out of hole and laid down.
  8. The subsea safety system was made up; the latch/unlatch mechanism was function tested and run in hole.
  9. The flowhead was connected after running in hole all the assemblies.
  10. The retrievable packer was set by rotation, the rupture-disk/pipe-tester valve was activated, and the circulating valve was cycled for cushion spotting.
  11. After cushion spotting, the circulating valve was cycled to the well-test position, and TCP guns were activated hydraulically while the downhole tester valve was kept in fail-safe open mode.
  12. A reservoir study program was completed. Pressure, volume, and temperature samples were also captured, and a gradient survey was performed.
  13. The well-kill operation commenced. The circulating valve was cycled to circulating position to displace annulus brine by kill-weight mud.
  14. After completing the kill-weight-mud displacement, the circulating valve was cycled to the well-test position. At this stage, the well volume above the circulating valve had kill-weight brine in annulus and tubing.
  15. The next step in the operation was to bullhead kill mud to the formation. Bullheading gas trapped below the 7-in. packer was challenging, so, in the string diagram, one circulating sub was strategically placed immediately below the 7-in. packer.
  16. The placement of the circulating sub enabled bullheading below the 7-in. packer into the formation.
  17. The contingency plan in case the formation did not allow bullheading was also prepared, which required increasing the kill-weight mud above 16.5 lbm/gal at the depth of the circulating valve (approximately 3800 m) to balance the hydrostatic head against the formation pressure at a depth of 4300 m, which was approximately 18.0 lbm/gal.
  18. A flow check was conducted, and the packer was unseated afterward.
  19. The TCP-DST string was pulled out of hole after the successful job.

Conclusion

By use of the multicycle DST tool string, the operator was able to test the reservoir potential safely and effectively with an underbalanced test fluid in two deepwater wells, achieving the desired test objectives. This project set a record for a service company performing HP/HT underbalanced DST in a deepwater environment in India.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178089, “Case History: HP/HT Underbalanced Drillstem Testing, Deepwater KG Offshore,” by Mahesh Sarode and Milind Khati, Halliburton, prepared for the 2015 SPE Oil and Gas India Conference and Exhibition, Mumbai, 24–26 November. The paper has not been peer reviewed.