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.
New electromechanical anchoring and shifting mechanisms for a 2 1/8-in. wireline shifting tool employ innovative linkage designs to enable passage through 2.2-in.-diameter restrictions and deployment in casings up to 5.0-in. inner diameter. The anchoring system delivers 60,000-lbf force through the entire opening range, and the tool provides more than 16,000 lbf of linear actuation force to the pressure- activated shifter.
Using wireline shifting tools for sliding sleeves, pulling plugs, fishing, and other operations requiring high axial forces is becoming more common because the tools generate forces comparable with surface- controlled pipe-conveyed devices while offering excellent operational control and real-time feedback downhole. Because operations may include going through a small-diameter restriction before shifting in a larger borehole, tools must open to a large diameter, a property known as the expansion ratio. However, as the expansion ratio increases, the ability of conventional tools for generating large linear forces diminishes. New anchor and shifting designs feature large expansion ratios while preserving the ability to deliver large linear loads.
Solutions are presented to the numerous challenges of the design for a wireline toolstring typically including an anchor, linear actuator, and shifting tool. The anchoring system has the capability to apply constant radial force that is independent of the borehole size. As with all intervention tools, it cannot stick to the tubular and must be fail-safe and fully retractable within the tool outside diameter (OD) in case of a power loss, even in high-debris environments. Integrity of the tubular where the anchor is set must be maintained. The anchoring force must not be influenced by the axial push/pull force of the linear actuator. Self-centralization of the anchoring system is needed to eliminate the large bending forces that would otherwise occur from the linear actuator action. Both the anchor and shifting tool must have features that enable pulling them out of hole reliably, even through a restriction. Force and opening displacement sensors are important in giving real-time feedback of the state of the system. In combination with integrated firmware, this enables the system to react to events in the hundred-milliseconds range for effective, high-accuracy operations. Examples are presented for tool usage for specific applications.
The novel designs presented in this paper expand the operating envelope of mechanical services on wireline to operations in wells that were previously not serviceable by such tools. Wider application of wireline tools will lead to reduced operational time and bring an increased success rate and intervention reliability on a lower cost conveyance platform.
This paper describes the mobilization of a snubbing unit and blowout preventer (BOP) stack in the Middle East and their use to enable the control of a well with an underground blowout and surface broaching within a short time. The mobilization timeline is provided, along with details about how the snubbing unit and BOPs were integrated with existing equipment to enable re-entry into the blowout well. The procedures and equipment used to enable a stable rig up and well entry are discussed. The paper also describes the situation within the well and the procedures used to enable control. Changes to the original plan, the reasons for the changes, and the results are also described.
Mobilization, rig up, and testing were completed within 12 days of receiving instructions to proceed. The well was controlled and left in a safe condition within an additional 14 days. The original plan had to be continuously reviewed and modified as more information became available during the snubbing operation. The original plan was to slip and shear the holed completion out of the well under pressure; however, as described in the paper, this plan was not implemented. The rapid deployment and use of the snubbing unit brought control to a deteriorating situation. Snubbing provided the fastest option to gain control of this well with an underground blowout and surface broaching.
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.
Hillier, Jill (Schlumberger) | Guedes, Carlos Eduardo (Schlumberger) | Baumann, Carlos (Schlumberger) | Torres, Abraham (Schlumberger) | Sarian, Serko (Schlumberger) | Aboelnaga, Sharif (Schlumberger)
The perforating deployment system significantly reduces rig time while maximizing the perforation length per run as compared with traditional systems, both on land and offshore, for rig or rigless interventions with very limited rig-up height.
In limited rig-up height interventions, such as installations with short rig-up height or small cranes, to perforate long intervals it is necessary to use multiple short gun runs. To reduce the number of runs, short gun subassemblies are connected using a sealed ballistic transfer connector. The sealed ballistic transfer connector provides surface wellhead pressure containment sealing capability within the gunstring while also ensuring downhole ballistic transfer between guns subassemblies and the added value of optimizing perforating underbalance conditions. There is no limit on the number of sealed ballistic transfer connectors that can be used in one string. The sealed ballistic transfer connector allows deployment and reverse deployment under pressure in wells up to 103 Mpa, and it is qualified for H2S environments.
The application of this technology allows significant rig-time savings and reduces personnel exposure via a remote operational console that enables personnel to connect and disconnect the guns under pressure from a safer distance. To date many jobs have been completed with this proven technology. One example presented in this paper is a horizontal well perforated from an offshore installation with an extremely short rig-up height, where there was only 16 m available to deploy wireline toolstrings. The limited height meant that a conventional wireline with tractor would allow deploying only a single 6-m-long gun carrier per trip. Using sealed ballistic transfer connectors enabled a 53-m gunstring (seven 6-m and one 3-m carrier plus adaptations) to be deployed in a single run using eight sealed ballistic transfer connectors. This was a record for the deployment conditions. More than 100 deployment and reverse deployment insertions were successfully conducted during this perforating job, reducing the required number of wireline runs from 59 to 10, and saving 51 days of operation and rig time.
This paper demonstrates how the integrated application of the perforating sealed ballistic transfer connector technology, tractors, and polymer-encapsulated cables can reduce time in long perforating jobs with short rig-up heights both on land and offshore. In another presented example, the operator saved days of rig time, in addition to large economic and production time savings, and also reduced the exposure of personnel to lengthy, riskier tasks.
Sarian, Serko (Schlumberger) | Arismendi, Francisco (Iberoamericana De Hidrocarburos) | Camperos, Silvio (Iberoamericana De Hidrocarburos) | Garza, Francisco (Iberoamericana De Hidrocarburos) | Trelles, Sergio (Schlumberger) | Varkey, Joseph (Schlumberger)
New generation Polymer-filled and jacketed wireline cased hole cables eliminate all inherent bottlenecks of traditional wireline logging cables, enabling unprecedented operational efficiency with substantial reduction of well control risk and costly maintenance. This Technology enables a Mexico operator to deliver all their Operator Field wells ahead of time, without any HSE or well control incident while gaining 9 days of early production.
Recently developed Polymer encapsulation and bonding technology completely seal Wireline cables electrical core and armors. The result is elimination of armor birdcaging (see glossary) and stranding, grease injection and associated equipment, cable gassing-up and well fluid related armor corrosion. Total armor torque balance and polymer outer jacket substantially reduce Chrome or glass coated completions damage, cable friction and maintenance requirements. The result is unprecedented well control safety, grease related environmental and reservoir damage elimination, higher operational efficiency with faster rig-up/down and tripping speeds, reduced tractor conveyance needs with improved well access in complex completions and proven early production gains.
Contrary to conventional Wireline cables, the new generation polymer encapsulated cables come with a gas blocked core and a pressure balanced sealed cable termination. Potential well fluid migration through the cable cross section is thus completely prevented. Along with the polymer jacketing, well control risk is all but eliminated. During 2018, and for the first time in Mexico, 45 cased hole interventions, 130 descents and more than 1,000,000 feet in the well polymer cable deployments were carried in a North Mexico gas field. All Perforations, Production logging and other cased hole descents were completed totally free from HSE, operational or well control issues. Logistically challenging cable maintenance trips were all but eliminated, saving substantial time and cost to all parties involved. Compared to conventional wireline operations, time saved using polymer encapsulated Wireline cables represented a 50% reduction in rig-up and rig-down time, as well as 40% operational efficiency gain. With wells delivered early to production all contractual targets were exceeded, adding 9 days of additional production of gas and condensate.
New generation Polymer encapsulated wireline cased hole cables have enabled the Mexico Operator plan and carry out efficient, safe, cost effective, and environmentally friendly Wireline Cased Hole operations, delivering producing wells ahead of time and exceeding contractual requirements.
An operator in west Texas experienced an obstruction pumping down a plug and perforating gun combination on a multi-stage frac operation in a 23,600-ft lateral. Following a 3.74" OD gauge run with 2-3/8" coiled tubing (CT), which hung up at 18,266 ft, a 3" gauge run was able to pass the holdup depth (HUD). To determine the cause of the restriction, the operator decided to run a video camera and a multi-finger caliper tool. However, due to some concerns with CT reach in the long lateral, issues with friction reducers, undesirable memory timers for recording the logs, and the inability to repeat logging in zones of interest or missing data, the camera provider recommended the logging be performed in "real time" on an electric-line (e-line) tractor.
A shop systems integration test of the combined tractor, caliper and camera was performed prior to running in the well. Clear fluid (fresh water) was pumped down the 5.5" × 4.5" casing from surface to obtain quality video downhole. Upon running the live system with the tractor, several over-torqued collars were identified as well as some buckling above those collars. The images were clear, and the problem areas were successfully identified. The total distance tractored was 10,063 ft, passing through the bad collars to the total measured depth of 23,511 ft.
This was the first time that a downhole video camera was run in combination with a multi-finger caliper tool on an e-line tractor in one run. This service benefits the industry in the following ways: Flexible logging program with real time diagnostics and decisions on additional passes in problem areas. No fluid darkening friction reducers necessary to achieve long lateral total depth. No CT helical buckling concerns. Small foot print for logging program on multi-well pads. Less chance of damaging logging tools on tractor than on CT if obstructions encountered.
Flexible logging program with real time diagnostics and decisions on additional passes in problem areas.
No fluid darkening friction reducers necessary to achieve long lateral total depth.
No CT helical buckling concerns.
Small foot print for logging program on multi-well pads.
Less chance of damaging logging tools on tractor than on CT if obstructions encountered.
This paper describes the operational details of this case and offers insights into the potential uses for such a service to the industry.
Many components used in completions are geometrically complex and machined to tight tolerances. Precisely measuring the internal profile dimensions of these items after installation is impossible using mechanical means such as calipers due to the sharp ID changes precluding good finger contact. This paper will discuss the use of a precision ultrasonic tool that allows accurate measurements to be taken without physical contact, and to detail a case study of inspecting a landing nipple profile.
Mechanical finger type caliper devices cannot measure internal diameters unless physically in contact with the surface and this is not possible at all times. An alternative to physical measurement is to reflect a projected beam of acoustic energy from the target and, knowing the speed of sound of the well fluid, calculate an ID measurement. Using a number of ultrasonic transducers allows beamforming techniques to precisely focus the sound to produce good resolution. The ultrasound tool uses a circumferentially arranged band of 288 sensors that operate in a phased array to determine accurate ID of even very complex profiles.
A landing nipple is a component that is designed for the installation of flow control devices in a well completion and comprises a seal area and a lock profile. The dimensions of these faces are very precisely controlled during manufacture because the device being installed, such a safety valve, must fit perfectly in order to provide a seal and mechanical attachment. If the lock profile, for example, becomes damaged or eroded than there is a chance of the safety valve being ejected from the nipple. The 288 transducer array of the ultrasound tool provides a circumferential spacing of 1.25° between measurements; ensuring even small defects can be detected. Following a laboratory test of a representative landing nipple under controlled conditions to verify the tool performance, a number of landing nipples were inspected in a field where erosion was suspected. The tool was able to accurately map the complex locking profile and to measure the dimensions to within a hundredth of an inch in each case, giving the operator confidence that the correct locks were being used to install the safety valves.
The unique properties of focused ultrasound allow the mapping and verification of even complex machined components while they are still downhole. With 288 circumferential readings, high resolution measurements are possible to an accuracy of a fraction of a millimetre raising the possibility of engineering a solution to a given problem rather than resorting to the expensive option of replacing the completion.
One method of sustaining and optimizing a well through its lifetime is underbalance perforating. When hydrostatic pressure inside the wellbore at the zone of interest is kept at less than the expected reservoir pressure, the damaged and crushed zones across the critical matrix at the reservoir that cause low permeability in the perforation tunnels will be immediately cleaned up as soon as communication to the reservoir is established upon perforating. In an operation offshore Malaysia, underbalance perforating was performed in injection wells, rather than producing wells, to optimize injection rates. The operation employed a fiber-optic firing head deployed on a fiber-optic coiled tubing (CT) real-time telemetry system.
The most common and effective method to achieve underbalance is displacing the well to a lighter fluid, less than the water gradient, prior to perforating. Subhydrostatic wells with low bottomhole reservoir pressure pose challenges to achieving the underbalance state. For these wells, well fluids must be removed via nitrogen displacement and the completion perforated with a nitrogen cushion. After underbalance is reached, the well is ideally ready to be perforated as it is, without introduction of additional fluids.
In the offshore Malaysia field, water injector wells had been perforated overbalance because the objective of the wells was injection and not production. However, the injection rate of these water injectors started to decline below the optimum design rate only after a short period, thus affecting the production rate of the neighboring oil and gas producers. Two pilot wells were designed to be perforated underbalance, achieving immediate cleanup after firing. The challenge was to perform an underbalance perforation in a low-pressure, depleted reservoir, using nitrogen as a displacement fluid. After this condition was fulfilled with a 500-psi differential, the well was to be perforated without any liquid introduction to activate the guns, which restricted the use of pressure- and ball-activated firing heads.
The fiber-optic-enabled firing head deployed on CT with real-time telemetry system is considered the most efficient intervention approach to overcome the challenges set. The new firing head will allow the perforating command to be given through an optical signal instantaneously at depth with no disturbance to the well fluid dynamics. This technique will also optimize an online rig operation where displacement, perforation, and nitrogen lift contingency can be performed in one CT run, hence reducing operating costs. Since the initial startup of the two pilot wells, the injection rates of the wells are at optimum, and the performance gained from the two wells has increased overall production in the field. Real-time underbalance perforating is thus seen as the way forward not only to enhance producing wells, but also to boost injectors as well, prolonging the life of an offshore oilfield.
With the objective of increasing productivity and achieving an economically sustainable development of the non-conventional reservoirs in Argentina, the oil and gas (O&G) energy companies are focused on drilling horizontal wells with lateral extensions between 2500 m (8,200 ft) to 3000 m (9,840 ft) in length. In order to produce commercial volumes of hydrocarbons, it is mandatory to fracture-stimulate multiple zones. The "plug and perf" method continues to be the most common completion technique in the field. Once the stimulation is completed, a coiled tubing (CT) milling operation is undertaken to remove the frac plugs. Critical to achieving a successful operation is reaching total depth (TD) in the well with the coiled tubing. The precise determination of the operational coefficient of friction (CoF) between the coiled tubing string and the production casing, could be the difference between failure and success, affecting both the technical and economical results of the project. The goal of this paper is to share the lessons learned after more than forty extended reach operations and the experience earned on the utilization of real time simulations to define both, the tensile load exerted for an extended reach tool and the coefficient of friction found during coiled tubing operations. Also demonstrate, by analyzing real life applications, how the implementation of this technology and new working methodology, allows to anticipate deviations with respect to the "normal" values of friction, achieve a better understanding of the influence of solids in the completion to the coefficient of friction and obtain a more efficient use of the metal-metal lubricant utilized during the milling operations.