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The transition to a climate-neutral society is both an urgent technical challenge and yet long-term CAPEX heavy requiring huge investments from industry and governments. Major oil and gas (O&G) operators around the globe have already established their decarbonization targets and even though upstream accounts for two-thirds of total emissions in the petroleum industry, both new well construction designs, and improved workover operations are proving to be effective measures in minimizing greenhouse gas (GHG) emissions while being economically viable. A novel completion technology has been installed in 114 wells in Russia since 2018 to eliminate sustained annular casing pressure (SAP) throughout the lives of wells and combat the associated release of carbon dioxide (CO2) and methane into the atmosphere. Since methane is much more powerful and has a 28-34 times more global warming potential compared to CO2 over the hundreds of years, and 84-86 times more potent over a 20-year timeframe respectively, these types of simple, yet efficient solutions represents enormous benefits to operators in reducing their carbon taxes while tackling climate change. Moreover, the installation of this technology resulted in reliable downhole well integrity of traditionally problematic wells, without the need for subsequent squeeze cementing operations. These types of completion solutions set both in an open and cased hole, allow operators not just to customize their cementing program and meet regulatory approvals, but also greatly reduce their reported carbon emissions. A summary of the results and efficiencies achieved with these installations will be presented and will be compared to conventional technologies. In addition, more than 15,000 lightweight e-line intervention operations have been performed both in Russia and Kazakhstan since 2011 which contributed to fewer emissions of hazardous greenhouse gases into the air versus conventional coiled tubing operations. These types of light interventions use less diesel to operate and with fewer people and equipment, leave a smaller carbon footprint on each well location which in turn makes a difference when it comes to GHG emission reduction. A comparison breakdown of coiled tubing versus e-line mechanical interventions will be statistically analyzed. This paper will illustrate how these newer technologies contributed to GHG emission reduction and how simultaneously economical efficiencies were achieved during well completion and intervention activities through reduced rig time and faster job execution compared to conventional methods. It will also review case histories from fields across the region using these installations and analyze each method. The field data will present the development, installation, and operational sequence and explain how each setup was tailored to meet both specific operational needs and to reduce greenhouse emissions, mainly by minimizing gas flaring. Widespread implementation of such technologies would help operators meet their emission targets and contribute to the reduction of the earth's climate change.

Pipe cutting operations are often a critical part of stuck pipe situations, well interventions and plug and abandon operations which all need to remove cut sections of pipe from the well. Unlike traditional ‘blade’ style e-line cutters, which can jam under pipe compression or explosive pipe cutters, which need to dress-over the jagged cut by the rig, a new electric line mechanical cutter's unique design enables performance even if the pipe is under compression, in tension or is neutral. It can also perform multiple cuts in the same run, while creating a clean and machined cut with tool-entry friendly shape. This paper will describe the technology of the new generation cutter, present two case histories; one of multiple cuts of stuck drill pipe, per each run in hole, from Germany and one of a critical tubing cut from a subsea well in Nigeria, using electric wireline and tractor conveyed services for many tasks traditionally performed with coiled tubing in highly deviated wells. These "light vs heavy" solutions can often be done off-line from the rig.

While optimizing hydrocarbon production, combining well intervention solutions can enable significant benefits due to reductions in risk exposure: fewer rig-ups and downs, less in-the-hole operating time and the carbon production and costs associated with rig time, especially when working from sub-sea intervention vessels. Operators in general, prefer to achieve multiple intervention objectives in a single descent in the well, if the operations complexity does not increase the risk exposure to an unacceptable level. Often, the risk of a mis-run, causing a second run, meets the cost vs value criteria for acceptable risk, when the large operating time savings of a successful combined run is considered. In collaboration with a mechanical e-line provider, North Sea operators developed three reliable combination solutions which increased their operational efficiency. Combining these most run services under more standard, common scope of work procedures, saved the operator time in planning, execution, risk exposure and money, while enabling them to produce hydrocarbons in the saved time. This paper will present the technology involved with these combined services, use a typical example of each and the cost savings achieved.

Effective zonal isolation within a layered reservoir in the Gulf of Mexico is a necessity to meet regulations for stacked reservoirs and to maximize total recoverables. Effective zonal isolation also ensures maximum production is achieved via a high-pressure proppant fracture treatment. A primary cement operation of a 10 1/8" production liner (within a 12 ¼" drilled hole section) was challenging due to a combination of high equivalent circulation density (ECD) and potential losses across a layered GOM reservoir. One layer had potential and significant depletion up to 8,000 psi. Critical well parameter considerations were: maintaining the liner burst of 18,200 psi, maximizing rotation and reciprocation capability of the liner, minimizing the impact on circulation and ECD, and ensuring compatibility with the mud systems. Following careful job planning, including the analysis of caliper data from logging while drilling (LWD) for the optimum placement, two metal expandable packers (MEPs) were installed on the 10 1/8" liner. The MEPs were positioned to straddle the highly depleted layer (one above and one below) in the 12 ¼" open hole section. The liner was deployed, and the cement operation was executed with minimal ECD impact from the inclusion of the MEPs. Surface pressure was applied to create sufficient differential pressure across the 10 1/8" liner wall to hydraulically expand the MEPs quickly under full surface control. This paper covers the qualification, planning, and deployment of MEPs to provide cement assurance (CA) for zonal isolation and improve the effectiveness of contingency cement squeezes. Though this technology has been used in other regions for several years, this was the first deployment in the Gulf of Mexico (GOM). The solution improved the probability of success of the primary cement job, negating the requirement for a remedial cement squeeze. The decision to run MEPs was based on the estimated cost savings of 3.5 million USD for remedial squeeze operations, a value proposition that did not account for the net present value (NPV) gain, due to improved fracture placement, compared to the case of poor cement isolation.

A new and transformational gas lift method termed Liquid Assisted Gas Lift (LAGL) has been developed. LAGL utilizes the co-injection of liquid with lift gas to reduce surface pressure requirements for the kick-off of gas lift, simplify well completions and improve system reliability/flexibility. PetroleumETC executed a Shell GameChanger project to demonstrate the delivery of LAGL for well unloading and kick-off of gas lift. Qualification testing was performed at a university test facility utilizing a 2,788 ft TVD test well with 5 ½-inch casing and 2 7/8-inch tubing. Air and water were the test media. In-well measurements were available bottomhole and mid-string for both the annulus and the tubing. The test well was successfully unloaded in 2 hours with a maximum pressure of 535 psig using manual operation of the module. Two automated tests were successfully conducted; one requiring 2 hours (670 psig max pressure) and one requiring 1 hr and 24 min (724 max pressure). Many lessons were learned, effectively de-risking the technology for field application. A new sliding-sleeve orifice valve was also tested with water, air and under multiphase flow conditions. The larger orifice sizes provided by the 2 7/8-inch sliding sleeve slim valve provides for faster unloading using the LAGL process. The paper provides an update on advances in the value case for the new LAGL technology. LAGL utilizes a single G-L valve, which reduces system costs versus the traditional use of multiple G-L valves and mandrels and dramatically reduces the risk of multi-pointing. LAGL provides the advantage of High-Pressure Single Point Gas Lift (HPSPGL) without the need for high pressures on the well pad, changing surface piping and a high pressure compressor.

Metal expandable annular sealing systems were used in a 4 ½" completion as an effective high-pressure isolation method inside 6" open hole mudstone formation in the Foothills Basin of Colombia. Effective isolation proved to be historically difficult to achieve. The operator was approached with a solid metal expandable sealing system with rotation capabilities as an annular barrier for a preferred cementless completion. The sealing system needed to be assembled on a full-bore liner able to deliver robust deployment with a high-pressure seal in a worse case washed-out scenario. The deployment of the system consisted of one annular barrier placed above and one annular barrier placed below the mudstone zone. Following careful job planning with the operator, the rotationally capable completion was deployed without any incidents. To achieve pressure integrity to set the metal expandable annular barriers, a ball seat sealing system was incorporated to allow the system to be closed and the annular barriers to be set. After putting the well onto the pipeline, the client recorded a 52% increase in their expected produc-tion from previous wells. Successful results were accomplished as effective isolation was achieved and enhanced production was obtained because of the effective stimulation. This paper overviews the appli-cation, design, implementation and results of the use of new metal annular sealing systems in a 4 ½" completion as an effective high-pressure isolation method inside a 6" open hole, drilled in fractured sandstone and mudstone formations.

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. This paper describes the operational details of this case and offers insights into the potential uses for such a service to the industry.

An Angolan operator needed to perform a coiled tubing (CT) acid micro-wash stimulation on a subsea sand screen completion in order to improve production. The CT simulation showed that the coil would not reach the objective, which was the bottom screen, even with friction reducers, without the assistance of additional forces. The operator chose to deploy a downhole tractor to provide a pulling force to achieve the desired depth. However, this horizontal well had debris which prevented reaching the objective and required changing strategies to accomplish the job. A downhole tractor can be powered by pumping fluids down the coiled tubing, driving a turbine which powers the hydraulic systems in the tractor. The drive fluid will then pass through the tractor and out the bottom of the tool to provide the treatment. Surface testing is performed prior to the job to determine at which pumping rate the tractor will be engaged and disengaged. This testing is performed with and without treating nozzles to gauge tool performance and expected pumping rates for tractoring and treating. In this Angolan operation two runs were required to reach the bottom screen due to debris fill in the completion preventing passage during the first run. On the second run the CT provider used a nozzle that could both clean the well and treat in the same run. This operation demonstrates the effectiveness of using CT tractors, which are under-utilized in the industry, to achieve extended reach beyond the normal CT range. It also demonstrates the quick mobilization and same day deployment, as well as problem solving that can occur when service companies (CT provider and tractor provider) work closely together.

Abstract In order to reduce rig time during workover operations, a new electric line (e-line) mechanical pipe cutting tool was deployed rigless in four ERD wells in the Middle East. The 4-1/2" production tubing of several high deviation wells needed to be cut and pulled prior to a tubing change-out campaign, commencing February 2013. This particular mechanical cutter was chosen for its non-explosive design, where a rotating crown removes pipe wall by grinding, creating a smooth bevelled surface without shavings. This eliminates the need for a polishing trip, allows the pipe to be severed even when under compression, and leaves a cut profile in the well which is ideal for subsequently fishing. Also, this type of cutter incorporates a 'fail-safe' mechanism that prevents the tool from becoming stuck following the cut process, and the cutting crown design precludes the tendency for sticking, which is a major concern with other mechanical cutters. In January, 2013, a system integration test was conducted to determine whether a grinding face cutter could actually cut a pipe in compression. A jig was set up to provide 20,000 lbs of compressive force on a 4-1/2", 12.6 lbs/ft pipe. The cut was made in 36 minutes. The subsequent rigless operations on four wells resulted in six successful cuts, without the requirement for the pipe to be put in neutral weight or tension. The amount of compression at the cutting depth was unknown, but at least 10,000lbs, as per the packer setting procedures. A key benefit of mechanical pipe cutters is that they eliminate the use of explosives and chemicals which can pose HSE and operational risks, especially when simultaneous operations are being conducted. The transfer and handling of explosives may also cause additional logistical requirements and significant delays, as safety procedures are employed. In addition, this mechanical solution eliminates the need for dress runs, and tubing recovery is optimized from a rig time perspective. This paper will discuss the operational steps taken to make the pipe cuts, a description of the new pipe cutting tool and lessons learned to improve future operations.

Tech 101 In this new series, TWA examines some of the most significant upstream technologies being employed today. This first installment focuses on well tractors.

Conventional methods used for downhole sand or debris cleaning have considerable investments in economic costs and time. Scheduling these activities to minimize production interuptions and to maximize unrestricted flow is a constant challenge faced by production and flow assurance engineers in the Oil & Gas industry. A sand and fill cleaning decision can be expressed as an optimization problem since its purpose is to maximize the production of the well to accomplish production goals at the end of a time period. This paper presents optimization algorithms applied in dynamic programming to help in scheduling cleaning interventions for wells in order to maximize the continuous production under physical, technical and economic considerations while minimizing the investment cost of the total operation. A strategy will be presented which takes into account mainly the fixed costs but also the variable costs and sensitivity analysis that allow the model to better approximate reality. The strategy considers three options based on the costs of cleaning with either electric line or coiled tubing technology; 1) to completely remove a given volume of sand, 2) to clean to a minimum acceptable level or, 3) not to clean and allow sand volume increases to continue. The cost to perform sand cleaning with a certain technology based on a mathematical function, considers the following requirements:the relationship between volume of sand produced per unit time, Vt (flow),(Vmax-Vmin) or the interval between Vmax in which production of oil is minimized and the Vmin for maximum production,the time horizon to perfom the sand cleanings, andPoints that make the operation unfeasible such as physical restrictions in the well or operator time/cost constraints. This paper will also present two cases demonstrating the strategy to schedule cleaning interventions that achieves a set production goal.

Recently, a solution has been developed to provide for milling of nipple profiles and other downhole hardware with electric wireline. A new milling bit and milling system for the wireline miller enables nipple profiles to be opened up in diameter to allow larger intervention products to be deployed, e.g. straddle packers and insert valves. Extensive testing was conducted prior to the introduction of this service to optimize the weight on bit and torque. The result was the development of a unique version of the hydraulic stroking tool to be combined with the milling tool to provide the controlled weight on bit.A major benefit of using the wireline milling system is the ability to provide precision milling without mobilizing coiled tubing (CT) or heavy surface equipment for circulating and handling fluids. Thus, there is no risk of damaging the reservoir from the circulating fluids. In addition, this kind of intervention can be performed more cost-effectively, involving less people, less heavy lifts and therefore, reduced HSE risks.The world's first milling of a nipple profile on wireline took place in Indonesia where the wireline miller was mobilized to enlarge the nipple profiles in 10 wells. The entire operation was performed in 20 operating days and well kills were prevented, which would have been necessary if executing the operation with a conventional method, such as on CT. Major benefits included minimal reduction in production levels, precision milling with zero cuttings left in hole and no labour-intensive requirement for CT or heavy surface equipment.As of December 2009, the ID of twenty (20) Super 13 Chrome nipples have been enlarged for one operator, without a miss-run related to the new milling system.This paper will discuss the technical aspects of this new milling system as well as present the field performance gained to date through a field test and two case histories.

With today's high rig operating costs, identifying areas where new technology can be used to improve efficiency and reduce rig-time is critical to many a project's financial success. In deep water regions, new intervention solutions that are not rig dependent are especially desirable. Electric wireline deployed interventions have been shown to offer both technical and financial benefits in mechanical manipulation of downhole hardware, such as isolation valves, in that they are faster to mobilize and execute, saving the operator several days in rig-time and deferred production compared to pipe conveyed methods. Many deep water completions use down hole isolation valves for temporarily closing off production while awaiting flowline connections for first oil. These isolation valves can be shifted open or closed through surface commands while a backup (contingency) allows the valves to be mechanically shifted. Failure of these valves can result in expensive delays to production with large rig time costs to intervene. Operators in the Gulf of Mexico, West of Shetland and West Africa have been pioneers in the application of wireline conveyed mechanical solutions for isolation valve contingencies. The contingency consists of an electric wireline hydraulic stroking tool to shift the sleeve open or closed. The wireline stroker is either wireline tractor conveyed in high angles or run with only the shifting tool attached in low angles. A new intelligent shifting tool is also available for opening and closing valves on command to avoid hang ups on downhole profiles that may occur with the conventional spring-loaded shifting tools.

A light weight intervention technique utilizing electric wireline has emerged as an alternative to existing well intervention methods. Tractor technology enables high speed, low HSE impact and a high degree of precision in production enhancing interventions in onshore and offshore wells. Wireline tractor technology eliminates the limitation on traditional wireline by extending the reach of the wireline into a high angle or horizontal part of the well bore, enabling access to the entire length of the well. Interventions in challenging conditions such as subsea, deepwater, extended reach, high-yield, heavy oil and deepwater are also enabled whether the hole angles are highly deviated or not. For instance, where slick line or coiled tubing (CT) operations below 20,000 ft can be risky and costly, tractor technology offers a time and cost-efficient alternative for valve manipulation, sand clean out and scale milling. Furthermore, interventions have been performed in high temperature wells (388°F), high pressure (>20,000 psi), ERD wells (>30K ft) and high deviations (130°) wells. Wireline tractor services can be mobilized in a matter of hours and only require a crew of from two to four people, depending on the operation. Transportation can be done in a helicopter to avoid the cost and time of mobilizing a full CT spread such as when cleaning and milling operations are performed without surface fluid handling logistics. Further, lightweight interventions with tractor technology combined with low surface impact left on the environment, allows mobilizations in eco-sensitive regions where heavy methods are not permitted due to the irreversible environmental damage that would be caused. This paper will present case studies where the HSE impact was significantly reduced by employing lightweight intervention techniques through tractor related mechanical services. One case will be a recent operation of milling barium sulfate scale on electric wireline and removing the cuttings in the same run in the hole. The second case will be milling out a cast iron bridge plug on electric wireline and the third will highlight the world's first wireline tractor intervention from a subsea intervention ship, which provided a much lighter solution for the operator.

Traditionally, deviated and horizontal wells have been challenging to service in a cost and time-efficient manner. Conventional technology requires large equipment to be mobilized and many heavy lifts in the offshore environment, sometimes with negative HSE consequences. New technology on electric wireline has made it possible to access the entire well regardless of deviation and lateral reach. Wireline tractors and new mechanical services can be mobilized in a matter of hours and only require a crew of two people for many applications. Transportation can be done by helicopter to avoid the cost and time of mobilizing a full coiled tubing (CT) spread with bottom hole assembly. Additionally, fuel consumption, emissions and fluid discharges are reduced and heavy lifts are eliminated for the offshore environment. Mechanical down hole wireline tools have also been developed to manage produced water. When wells produce up to 100% of water, mechanical tools can isolate the water to increase oil recovery. By reducing water entry at the source, the subsequent efforts and costs to address it are reduced along with the environmental risks. This paper will illustrate how HSE benefits can be achieved through several case histories. One case history will show how time and crew requirements can be reduced when a wireline tractor and milling system were deployed to remove 42 ft of barium sulfate inside two wellbores. The scale was removed from both wells in 12 days – the same time it would have taken a CT unit to mobilize and demobilize offshore. Costs were reduced by 60% and crew requirements were reduced from 23 to 12 people compared which reduced human exposure to risks offshore. Another case history will illustrate how produced water can be effectively reduced through e-line mechanical services. In an offshore well in Norway, a leak was detected in the tubing, which resulted in 85% water cut. A wireline tractor and stroker were applied to install two straddle packers in order to isolate the water-producing area. Water cut was reduced to 5% and oil production increased 800%.

Many subsea completions employ a down hole isolation valve for temporarily closing off production while awaiting first oil or flow line connections. These valves are designed to be opened or closed through surface pressure pulses in the fluid column to activate stored nitrogen in the valve housing. When a valve fails to activate as expected, a reliable contingency plan must be ready or the financial consequences can be large. With the use of electric wireline tractor technology, a contingency valve opening system allows malfunctioning isolation valves to be mechanically shifted with depth precision and controlled force. This method uses an electrically powered hydraulic stroking tool to shift the valve sleeve open or closed with a selected force of 10K - 30K lbs depending on the type of valve. The stroking tool is either tractor conveyed in high angles or run with only a shifting tool attached in low angles. A new intelligent key tool replaces the spring loaded shifter, to allow the system to be run "slick" and avoid hang ups on down hole profiles that can occur with the conventional spring loaded shifting tools. An electric line deployed solution is faster to mobilize, more precise in locating shifting sleeves and less expensive than alternative solutions. A review of case histories will prove these points. Also, pre-job planning, integrated team involvement, SIT and operational recommendations will be discussed.

In recent years, re-invention and development of electrical wireline mechanical applications, initially for high-angle well-access in conjunction with wireline tractors, has proven able to unlock value potentials by allowing interventions, previously thought impossible or cost prohibitive, even in low angle wells. Common denominators are remote-control, rig-less operations and documented large value-creations. The most recent advancement in this service category includes milling and drilling on wireline; a breakthrough within intelligent production optimization. With the ability to engage a wide variety of challenges downhole, this technology provides hitherto unseen possibilities to increase production quickly, efficiently and safely. Also representing new capabilities is the technology of transforming constant mechanical force independently of the wireline and depth/deviation of the well. The advantage here is that operations can be performed from a crane or mast unit with electric line and apply a pulling/pushing force capable of manipulating down hole production control devices in a controlled and repeatable manner. This paper will present innovative areas of recovering production through various case histories.

Sand accumulations in high angle wellbores inhibits production, plugs completions, erodes hardware and blocks access to downhole jewelry, such as valves and sliding sleeves. Bailing on sick line wire is the preferred, low cost method to clean sand and debris in vertical wells but slick line can not often reach in high angles. Conventional remediation methods for high angles use either Coiled Tubing or an expensive rig to remove sand and debris. This paper presents a rigless alternative to sand, debris or scale removal utilizing a combination of well tractor technology and a new vacuum/bailer system all conveyed on electric wireline. Tractor technology is a proven tool as a conveyor of services in high angle wells. Combining a tractor with a well cleaning system provides the means of accessing and removing debris either selectively in one run or over a general area in multiple runs. These electric line powered tools can be mobilized quickly with less crew, and for far less cost than a coiled tubing mobilization. Following the sand removal, evaluation of the source of the sanding problem can then be performed with E-line inspection services during the same rig up. Three case examples will be presented demonstrating the three different cleaning methods: liquid environment vacuum system, dry environment auger system and scale milling system. Each example will detail the unique cleaning head and bailer system used for the given completion and problem.

Wireline tractoring technology has set world and Gulf of Mexico records for several logging applications during the initial completion and intervention of two extended-reach, deepwater frac pack wells and one extended-reach, deepwater water-injection well. This paper reviews some of the challenges involved with conventional conveyance methods in extended-reach wells, describes the planning process for wireline tractoring operations, including prejob modeling, and summarizes the results of a project.The authors will also share the lessons learned and best practices implemented. Proper utilization of this technology has led to significant cost savings for the example project.