An operator drilled an inland waters well in the 1960’s in southern Louisiana. By the time the well was scheduled for plug and abandonment (P&A), the canal had been transformed into wetlands and significant silt had built up around the wellhead, thus increasing the complexity of the abandonment operations. The environmental impact to the wetlands would be minimized by laying mats around the well in preparation for coiled tubing (CT) operations. However, these mats laid out on the soft wetlands would not safely support the excessive weight of the CT unit and reel, so they were rigged up on a barge 125-ft away from the wellhead. A CT drilling tower was used to provide stability to the wellhead stack. The wellbore conditions (11,300 psi MASP and 313 deg F BHT) increased the complexity of this operation further, requiring a very thorough job planning process. A mock rig-up of equipment was performed before mobilizing equipment to location to ensure the stability of the wellhead stack. The CT operations were completed successfully which allowed the operator to complete the decommissioning of the well. This paper presents a case study that demonstrates the adaptability of CT technology to meet the special requirements of well abandonment in the inland waters environment of the Gulf of Mexico.

As a result of production having drained once-prolific reservoirs, Gulf of Mexico (GOM) operators are dealing with an increase in well abandonment activity spurred by environmental concerns and government regulatory agencies. Many well plugging and abandonment (P&A) activities are performed using coiled tubing (CT), which eliminates the need for a rig. Cement placement is an essential part of every P&A operation. Deep wells (exceeding 20,000-ft measured depth) with high bottomhole static temperature (BHST) (greater than 400°F) and an aggressive H2S/CO2 environment add additional challenges to the cement slurry design. Furthermore, operations need to be executed safely and within the limits of CT equipment. An operator needed to P&A a well in the Mobile Bay block of the GOM. No previous high-pressure, high-temperature cementing operations through CT at BHSTs greater than 400 °F in the Gulf had been performed. One of the key challenges for this CT intervention was designing a cement system for 425 °F BHST to be pumped through a 23,620-ft, 1-1/2-in. OD CT string. Concentrations of 75 ppm H2S and 4% CO2 increased the complexity of the operation even further. After several unsuccessful attempts with wireline to dump-bail cement, the operator successfully used CT to plug the bottom zone of this deep, high-pressure well with cement.

Coiled tubing (CT) has been used in Alaska for over 20 yr as a low-cost alternative to a workover rig to complete a variety of well interventions in Arctic conditions in an effort to increase oil production. The majority of these operations are performed on wells that have a maximum anticipated surface pressure (MASP) that does not exceed 5,000 psi and are considered low-pressure wells. The working pressure of the lowest-rated component in the well control stack, including the operator's wellhead, is typically 5,000 psi. Therefore, CT interventions in Alaska on wells where the MASP exceeds 5,000 psi must be well planned far in advance of the job date to ensure that a thorough review of the equipment requirements, job design, and other aspects of the job are completed so that the operation can be executed safely.Given current Alaska Oil & Gas Conservation Commission (AOGCC) regulations, an operator decided to re-enter five wells in the remote Point Thomson field area that contain hydrocarbons such as diesel or "arctic pack" (gelled diesel) in the wellbore to remove the hydrocarbon fluids and plug and abandon (P&A) the wells. There were several key challenges associated with this operation; these included the well's high MASP (7,900 psi), low ambient temperatures (Ϫ50°F), performing CT milling operations in large casing (9 5/8 in.), and cement placement through CT in zones with very low bottomhole temperature (29°F). The low-temperature cement system used was designed so that volumes of cement in excess of 200 bbl could be placed in the well through CT. In addition, a pressure and fluid management system for controlling pressure and removing solids and gas from the working fluids was used to manage high well pressures and reduce fluid costs. CT operations were completed safely. The application of CT to meet the requirements of these unique well abandonments allowed the operator to complete the P&A of all five wells.

Drilling activity in remote, complex environments has increased in Alaska as operators seek to combat falling production in existing wells and shift to commercialization of natural gas and condensates. The completion of these wells often requires coiled tubing (CT) intervention, whereby CT is used for various applications, including wellbore cleanout, milling, fishing, and acidizing operations. To complete multiple high-pressure wells in a remote field, an operator required a CT contingency to shift formation isolation valves. A new collaborative approach was implemented in which the operator and CT service provider closely worked together on the technical job design from the onset of the project to optimize planning and execution. The planned intervention was part of a large project in which a single company provided most of the services. This allowed the CT service provider to work closely with the operator and third-party providers, such as the fluid supplier and completion equipment supplier, to complete key technical design elements, including CT string design, fluid design, and downhole tools selection. In this way, an integrated, fit-for-purpose solution was delivered to the operator. Many ke y challenges were associated with this intervention. The biggest challenge was the absence of previous such experience in a well in Alaska where maximum allowable surface pressure (MASP) exceeded 8,500 psi. The intervention would require well control equipment and other pieces of treating equipment and downhole tools rated for 15,000 psi that were not readily available in Alaska. In addition to the well's high MASP (8,564 psi), other key challenges included being ready to perform a CT milling operation of a formation isolation valve in large casing (7⅝ in.) in an environment with 30-ppm H2S and 4.55% CO2 where ambient temperatures could drop as low as−50° F. A 2-in. CT string with a length of 19,000 ft was designed to provide sufficient weight on bit and overpull to complete all required contingency CT operations. A fluid system was designed to not only control the high pressure in the well but also be pumped through the CT string at circulating pressures that did not exceed the limits of the pipe. Furthermore, a test was completed prior to the mobilization of equipment to location to determine the optimal design for milling the formation isolation valve with CT. This paper presents the job design and preparation processes completed for the first planned CT intervention contingency in Alaska, in addition to lessons learned that can be applied to future high-pressure CT operations requiring well control equipment rated to 15,000 psi.

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