This paper describes the results obtained and the equipment and techniques used in setting up the first barge-assisted hydraulic workover operation in the Gulf of Thailand (GOT). This paper will discuss the hydraulic workover unit (HWU) selected to perform the operations along with the engineering modifications that were required to meet the operator's requirements in the GOT, primarily installing electrical submersible pump (ESP) completions in depleting wells.
The paper includes descriptions of the challenges faced in operating an HWU on minimum facility production installations (MFPI) with total platform weight limitations of 40 mT and minimal crane capacity. Also discussed are a number of innovations designed and built into the HWU to enable a safe, quick assembly using a barge crane and remote power and fluid systems to make the HWU system as flexible as possible to cover all known deviations from the standard scope of work.
Lessons learned from the operations are also presented to demonstrate the ongoing operational challenges, the solutions implemented, and the results achieved.
During 2005, an operator conducted a four-well pilot ESP workover campaign using a jack-up (JU) rig in the GOT. Due to the formations in the GOT being highly compartmentalized, braided fluvial sand environments, typical oil wells there were producing 40 to 60% water-cut, giving an average pipeline pressure of 350 to 600 psi. As such, the natural gas lift diminished as the source of high pressure depleted.
Through this successful pilot scheme, it was recognized that the economics for using a drilling rig to install the ESP completions would not be favorable unless an alternative and less expensive installation method could be found.
The candidate ESP wells were to be completed as 2 7/8-in. monobore completions within 7-in. casing with the packer to be set above the existing tubing at the top of cement (TOC) in the 7-in. casing. This would result in the ESP being set 2,000 to 3,700 ft true vertical depth (TVD) above the top perforations at a depth of ~6,500 ft. This meant that the expected pickup weight of the tubing was 70,000 lb and, as such, a rig with a minimum 150,000-lb lift capacity would be required to run the completion.
Key drivers in this alternative solution were:
The customer to deliver high volumes of new wells to meet gas delivery commitments.
Utilization of the available JU drilling rigs to drill and complete new wells.
The significant increase in JU rig rates in the GOT.
Candidate wells were located on MFPI in the GOT with an average size of 180 m2.
Deck load capacity of MPFIs limited to 40 mT total.
Existing platform crane capacity ±5 tons.
Platforms located 150 miles offshore in 250 ft of water.