Plunger lift is commonly used for production of low volume, high gas-oil ratio (GOR) or high gas-liquid ratio (GLR) wells. A plunger lift candidate must meet GLR and pressure requirements, but the method of installation and the mechanical setup of the well also are extremely important. Installation is a frequent cause of system failure. This page focuses on the installation and appropriate maintenance of plunger lift equipment. For reference, Figure 1 is a full wellbore schematic of major plunger-lift components, and Figure 1 is a plunger-lift troubleshooting guide. Numbers represent rank in order of most likely solution. There are many plunger-lift manufacturers and equipment options, so quality and design vary. Purchasers have the ultimate responsibility for investigating the manufacturing process.
This topic page provides an extensive set of tables intended to aid in the practical application of production-logging technology. For a given problem, the reader is guided first in the selection of the set of logging tools most appropriate. Next, suggestions are given on the proper procedure for each tool's use. This is an important part of the guidance, because the way logging records are obtained is often the most important part of the operation. Finally, the user is provided with comments regarding what the records should show relative to the problem.
Profile seating nipples and sliding sleeves have a special locking groove and a honed sealbore to allow a flow-control device to lock in the nipple and seal off when installed. By design, the sleeves and nipples will have a smaller inside diameter (ID) than that of the tubing string. For this reason, careful consideration must be given to the overall application and completion design when selecting and sizing the various models of profile seating nipples and sleeves. This is especially true in any case in which through-tubing operations or perforating are planned. Correct application of flow-control accessories can greatly reduce the time and money spent on diagnosing well problems (such as tubing or leaks) should they occur.
The casing-collar locator (CCL) is an important tool because it is used for depth control. When combined with a gamma ray log, it allows depth correlation of a cased-hole logging run with the openhole logs and, therefore, reservoir units or zones. This is essential for subsequent downhole operations such as perforating. Because it constitutes the primary depth control, the CCL is run on almost every cased-hole tool string. The tool comprises a coil-and-magnet arrangement with a downhole amplifier.
This short course is designed to provide knowledge and understanding of surface equipment, downhole tools, various applications, and operational contingencies for rigless well interventions involving coiled tubing, slickline, or wireline. The participants will learn first-hand knowledge of the capability of each intervention and what to consider when choosing which intervention method to utilize. The course will cover recommended risk mitigation and well control barriers as well as best practices gained from years of experience and application. To further illustrate the intervention methods utilized to resolve well issues or enhance well performance, real world examples for coiled tubing, slickline and wireline will be presented and discussed. Recognize and explain function of CT, Slickline, and wireline equipment Recognize and explain function of the Pressure Control Equipment and Bottom-hole assembly’s for coiled tubing, slickline and wireline interventions.
Kumar, Abhineet (Cairn Oil & Gas, Vedanta Limited) | Prakash, Aditya (Cairn Oil & Gas, Vedanta Limited) | Singh, Alok (Cairn Oil & Gas, Vedanta Limited) | Bharati, Pradeep (Cairn Oil & Gas, Vedanta Limited) | Jayan, Binshu (Cairn Oil & Gas, Vedanta Limited) | Kothiyal, Manish (Cairn Oil & Gas, Vedanta Limited) | Patil, Bhushan (Cairn Oil & Gas, Vedanta Limited) | Sarma, Phanijyoti (Cairn Oil & Gas, Vedanta Limited)
An offshore drilling campaign comprising of four development wells was conducted to augment oil production from a field located off the western coast of India. All four wells were designed to be sidetracked from existing depleted wells of the field. Historically, preparing existing wells in the field for side-track took ~4 days/well of a drilling rig and associated spread cost. This paper presents a case- history of conducting side-track well preparatory activities by a rig-less well intervention spread leading to significant time and cost savings. This method was also the first instance of such an activity being conducted in an offshore environment in India.
Prior to actual side-track drilling from an existing well in a brown field, it is required to abandon the open zones in the existing well and prepare the well for casing window cutting for further drilling to a new sub-surface target. Typical preparation activities include multiple wireline runs to set/retrieve deep set and tubing hanger plugs, well killing, nipple-down X-mas tree, nipple-up BOP, wireline run to cut tubing, retrieval of existing completion and ultimately placement of cement plugs to abandon the parent wellbore. The routine approach in the organization for all previous offshore drilling campaigns was to utilize the offshore drilling rig for afore-mentioned well preparation activities. Substantial rig time was spent incurring the cost of entire rig spread for an average ~4 days/well equivalent to ~40% of total well completion time.
The paper elaborates on rig-less operations set-up consisting of Cementing and Wireline Units utilized to conduct well killing, placement of cement plugs, production tubing cutting and nippling down X-mas tree prior to the mobilization of the drilling rig at the platform. The only operation left for the drilling rig was to pull-out the existing completion string and then drilling operations could commence.
The execution of planned operations was flawless on three wells while one well posed technical limitation due to its high deviation. The rig less well preparation campaign was concluded incident free, ahead of schedule and within budget. This offline exercise prior to rig-move saved ~12 days of drilling campaign time which helped in cutting down on overall drilling campaign cost and also allowed the flexibility of adding more wells to the campaign within fair weather window.
While this was an effort to simplify operations and save costly drilling rig-time in a side-track drilling campaign by conducting some very critical operations offline, these methods can also be adopted for planning well abandonment and decommissioning activities in a mature field.
As the scope of deepwater operations increases, the need for cost-effective well servicing is paramount, particularly because of the continued challenges associated with current volatile commodity pricing. One of the first requirements on any subsea deepwater intervention with a horizontal wellhead production tree is pulling the subsea horizontal tree isolation lock mandrel plugs, commonly referred to wellhead or crown plugs. This can be a "show stopper" event if not planned correctly. Because of the critical nature of this action, the majority of operators follow a two-prong approach, with a primary plan of action and a contingency procedure, to help ensure barrier removal proceeds as planned. Although successful removal of the crown plugs is the principal concern, it needs to be completed cost-effectively for the intervention to obtain approval.
The advent of digital slickline (DSL) allows surface readout (SRO) monitoring during the removal and installation of these barriers to provide an increased level of confidence during this important phase of the operation. This paper outlines case studies of the real-time sensors available with the RF communication DSL system that was highlighted previously (
Additionally, the straight pull battery operated extended-stroke downhole power unit highlighted in
New developments as the downhole power generator was ported to DSL are discussed, notably on- command motor controls and SRO, which was traditionally only available in memory. A downhole anchor was added to the toolbox, which can be run in combination with the downhole power generator to expand effectiveness, as new production trees might not allow for a no-go landing shoulder. To address the increased water depths, the 3.59-in. extended-stroke downhole power generator was upgraded to 80,000 lbf pulling force.
Vijay, Rachit (Cairn Oil and Gas,Vedanta Ltd) | Panigrahi, Nishant (Cairn Oil and Gas,Vedanta Ltd) | Khanna, Manu (Cairn Oil and Gas,Vedanta Ltd) | Kothiyal, Manish Dutt (Cairn Oil and Gas,Vedanta Ltd) | Sarma, P J (Cairn Oil and Gas,Vedanta Ltd) | Bohra, Avinash (Cairn Oil and Gas,Vedanta Ltd) | Tiwari, Shobhit (Cairn Oil and Gas,Vedanta Ltd) | Pinto, Thomas (Welltec)
The subject well is a recently drilled and completed in Cambay field offshore in West coast of India. After landing the completion, two mechanical plugs were installed to nipple down BOP and nipple up X-mas tree. The plugs were installed in a 3.875" tubing hanger profile and in a 3.813" SC-TRSSSV selective profile. The problem arose while retrieving the 3.813" selective plug with 4" GS tool after installation of X-mas tree. The slickline wire snapped while doing the jarring operations resulting in fish in the well with BHA and plug slipping down below the selective profile. The plug fell inside the well and got stuck at the 4.5" × 3.5" tubing crossover joint ~20m below the SC-TRSSSV depth. The fished slickline wire along with the slickline tool-string BHA was successfully retrieved from the well, however, the plug remained stuck at the 4.5" × 3.5" tubing cross-over and could not be fished out even after several conventional approaches with slickline.
Solutions involving rig based retrieval and rig less coil tubing intervention and e-line robotic technology for retrieval of the plug were evaluated. Upon completion of a detailed feasibility study of available options, it was decided to conduct fishing of the plug with e-line based advanced robotic well intervention techniques such as eline miller, tractor and stroker. Unique milling bits were designed and customized for this operation. The milling operation involved multiple runs to target the removal of various parts of the struck lock mandrel. Upon successful milling operation, it was planned to retrieve the plug with slickline.
Initial attempts to retrieve the plug by straight pull using 33k pulling capacity Eline Stroker were unsuccessful. Subsequently, milling was attempted with a combination of E-line tractor and Miller to drill thru the plug. The milling initially started as per the plan but after 3 inches of milling the bit got stalled and was eventually stuck inside the plug. The E-line BHA had to be released from the mechanical disconnect sub above the bit. A modified 2" UPT tool with E-line tractor-stroker was run to fish out the bit and plug which resulted in the plug getting released from the stuck position and moving upwards about 10-meter from the stuck depth. Once this was accomplished, plug and bit were successfully retrieved with slickline.
The paper details the background of the stuck incident, selection methodology of fishing technique, fishing work plan and its successful execution. The paper also describes the operational difficulties encountered and the mitigation chosen while milling a plug with an electric line in the offshore environment.
A suite of subsea intervention case histories at the Bacchus oil field in the North Sea will demonstrate how one operator matured intervention planning to address well entry challenges using learnings gained over the course of successive jobs. This contributed to better management and mitigation of potential risks leading to slickline performance improvement for gas lift valve reconfiguration, the successful deployment of coiled tubing to clean out asphaltene deposits in a live subsea oil well from a monohull vessel and setting of a retrofit gas lift straddle to optimize and secure production. The paper outlines intervention asset selection, work programme development and risk mitigation measures related to subsea tree valve function issues and loss of full bore access caused by asphaltene and wax deposits. Light well intervention vessel and mobile rig operations using deployment methods including slickline, digital slickline, electric line and coiled tubing are described. The role of production technology work undertaken to better understand the nature of organic deposits in the wells and how that contributed to anticipating well access risks and inform intervention planning will be highlighted. These real field examples add to the knowledge base of well services and production technology challenges faced during subsea well intervention and highlights approaches to overcome them.