This case history outlines a recent North Sea Coiled Tubing Drilling Project (CTD). The Project consisted of 2 main phases – Onshore Testing and Offshore Operations. The objective of the Project was to drill a 1000 ft sidetrack from an existing water injection well via a window cut in 7 inch casing. If the operation were to be unsuccessful, the well would be returned to its original configuration. The existing perforations were successfully abandoned using a gel plug and a cement abandonment plug. A separate cement kick off plug was spotted above the cement abandonment plug. A pilot hole was drilled in the kick off plug and a window cut in the casing. Eighty feet of formation was then drilled. Following a bottom hole assembly change access to the window was lost. Subsequent attempts to re-enter the window were unsuccessful. The drilling bottom hole assembly continued past the window into the original wellbore. Attempts were made to re-cement to allow a new window to be cut. These operations were unsuccessful. The Project was terminated after 52 days on location. All cement was underreamed from the well, the perforations treated with an acid wash and the well successfully returned to injection.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes the first few months of operation of a new, purpose built, underbalanced (UB)
This paper describes the equipment and techniques that were used for a high-pressure, high-temperature (HPHT) cleanout operation carried out on the Shearwater platform in the UK central North Sea with the support of a jackup drilling unit. The project involved intervention in three wells over a period of 9 months. The wells had been shut in for some time following production of reservoir solids. A hydraulic workover unit (HWU) was selected to clean out the production tubing to allow isolation barriers to be installed. In rig-assist mode, the HWU deploys pipe against surface pressure with the rig providing pipe-handling support. The paper details the planning and pre-engineering work that preceded offshore operations. Detailed planning and risk assessment were also required during operations because well conditions changed. Some equipment problems required a review of planned operations, and during an annual process plant shutdown, onshore tests were carried out before mobilization for the second phase of the intervention project. Modifications were required to the HWU to withstand the high buckling loads associated with snubbing against high pressure. Additionally, special downhole tooling was required to accommodate extreme well conditions. The paper discusses the development work involved and the subsequent performance of the equipment. Operating performance statistics and key lessons learned during the project are presented. Introduction The Shearwater field is located in the central North Sea in Block 22/30b, approximately 138 miles east of Aberdeen (Fig. 1). The field was discovered in 1988 and developed with dual platform facilities. The development consisted of a process, utilities, and quarters (PUQ) platform linked to a wellhead platform (WHP) by an 80-m (262-ft) bridge (Fig. 2). The platforms are installed in 90 m (297 ft) of water.
This paper describes two of the major technical achievements during the first year of operation of a new, purpose built, underbalanced (UB)
fax 01-214-952-9435. Abstract A coiled tubing stimulation treatment featuring a new high flash-point solvent was performed on an offshore injection well in the Ninian Field. This stimulation treatment was performed to q remove hydrocarbon residue and deep clay damage q stimulate low-permeability zones .increase water injection rates in an offshore wellThe target zone was treated with 587 bbl of sequential HF acid to prevent swelling of near-wellbore tines, solids, and clay. The application of sequential HF acid increased permeability 10-fold over standard HF acid treatments. An inflatable packer was placed between the upper zones and suspected weak tubing, confining the treatment to the target zones. The treatment successfully reduced the formation skin factor, which increased the injection rate by 100% (0.25 bbl/min to 0.5 bbl/ rein) and reduced the surface pressure by 3%.
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