Technical papers

Other important aspects considered on the new well design are the large thickness and high productivity of Buzios field reservoirs, as well as the need of some flexibility to deal with uncertainties. Finally, the new completion project was also designed to improve performance and safety on future challenging heavy workover interventions. The well construction area has gradually obtained improved performance in Buzios field with the adoption of the new practices and well design presented in this paper.

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During the earlier field development, many cementing challenges were encountered that increased risk and cost and the ability to deliver effective isolation across the reservoir. Poor isolation leads to poor matrix acid stimulation, higher skin and a higher risk of water production. To address this the operator sponsored an industry challenge to achieve reservoir isolation with cost and risk reduction and to deliver overall efficiency gains. Through dialogue between the Operator and a leading service provider in Open Hole Zonal Isolation, a solution was identified that would effectively replace the cement across the reservoir with a metal expandable annular sealing system.

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A tubing tractor and mechanical key and stroker were used to convey the wireline key in highly deviated wells. The key and stroker tools are latched into the sliding side doors (SSDs). They will activate open or close SSDs by down-strokes or up-strokes. In particular, the SSDs are closed when it is required to pressure up the tubing to set the packers. After the packers are set, an integrity test is conducted to confirm zonal isolation. Finally, the SSD is shifted open by the tubing tractor and a low rate injection test is performed to confirm the status of the SSD before handover the well.

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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.

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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.

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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.

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At the same time, the degree of exploration of the resource base of the Yamal OGR (the ratio of reserves of category C1 to reserves of category C2 and resources D0 + D1) is relatively high - 0.48. This suggests that the potential for reserves growth is very limited. To further maintain production, it is necessary to introduce promising oil and gas resources into prospecting-exploration drilling right now.

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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.

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A metal expandable annular sealing system was selected as a reliable isolation mechanism for effective cementation behind aquifers due to its ability to provide high expansion in potentially washed-out wellbores and the feature of long multi-element sealing systems with built in redundancy.

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The described technology allowed the Company to find a solution to work with the Y-Tool bypass system in the production wells of the Prirazlomnoye field.

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In the sidetrack, two Well Annular Barrier (WAB) were used to augment the cement. The WAB is a metalexpandable packer that sets in open hole to assure sealing. One WAB was installed between the oil zone and the gas cap, and another one between the oil zone and the bottom water. The operation was successfully executed and the WABs expanded in wet cement after bumping the plug. Three years later, the well is still producing with 0.2% BS&W.

This paper discusses the well conditions that contributed to insufficient cement sealing, the WAB
application in the field, and the field results.

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This approach can be said to have established a springboard upon which future well intervention operations can be developed, mainly for milling through mechanical restrictions, as this was the first ever 2.25” gate valve milling operation performed on electric wireline worldwide.

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The system was run in combination with multi open-close fracturing sleeves and a pressure activated toe sub rated to 10,000 psi for acid fracturing in three zones of a vertical carbonate well – the well was known for its heterogeneity and high reservoir pressure contrast. The use of mechanical packers with short sealing elements would have been challenging and increases the risk of unwanted communication between zones. Successful installations, activation of the sleeves and subsequent hydraulic fracturing were achieved, which enabled operational flexibility, reliable isolation and high expansion benefits. Acid fracturing treatment data from each of the stages were analyzed and used to confirm that the zonal isolation integrity.

This paper includes the challenges of providing zonal isolation with conventional packer designs and details the design, testing and qualification of the solution as well as further design modifications for higher fracturing pressure rating.

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Severe planning was performed prior to technology introduction, including possible solutions comparisons and risk assessment. Robotic intervention was proven not only technically superior, but yielded large economic benefits compared to traditional descaling and sampling methods. It involved less personnel and produced much less CO2 footprint as well.

Sample retrieved during the operation was analysed in laboratory and with high degree of certainty can be attributed as localized formation collapse. Same was confirmed by limited length of blockage that was successfully removed. This represented additional mechanism of wellbore restriction in the field.

The experience from first worldwide operation, the methods and tools descriptions, process, lessons learned, recommendations and way forward will be presented in this work and should be of great interest for wide group of practicing engineers.

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1. To log the entire open hole section and reach the Total Depth (TD) of the well.

2. To obtain high quality data from the logging tools, despite the adverse downhole environment.

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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). 

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The deployment of traditional rig or coiled tubing unit to help restoring production came with considerable cost due to the equipment and personnel requirements. Consequently, PHM continually looked for new techniques to reduce this challenge. Milling on wireline, where applicable, was one solution since it could be performed in rig-less environment.

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The system is compatible with a number of mono-cable logging tools and can be deployed using both E-line as well as Coiled Tubing. This paper describes the operation in detail and discusses the output and evaluates the results, which demonstrate the efficiency and accuracy of finding and entering the laterals.

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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.

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Earlier this year, in a gas field offshore East Malaysia, an Operator needed to investigate probable sand intrusion from an open-hole gravel pack prior to design a remedial plan to reactivate the well.

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The results have been well received, and precision has become a necessity in certain well interventions, especially where the life of a well is expected to extend and the recovery to become more sustainable. Consequently, precision interventions save considerable time and cost to the operators while offering safer alternatives to other methods.

In this case, we show how two cutting-edge, e-line technologies have solved two important challenges for an operator: (1) Orienting an e-line puncher tool sideways to secure circulation when punching tubing at high deviation, and (2) cutting tubing in compression without damaging the outer casing, leaving a clean, beveled edge for subsequent runs.

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The bit was specially designed to mill the flapper while minimizing the flapper rotational action that might have caused by the milling, hence increasing the milling effectiveness. As this is the first loose SCSSV flapper milling for Medco E&P Natuna, a System Integrity Test (SIT) was conducted at Service Company facility with actual flapper of the same type to prove the method would work, prior to the actual job onsite.

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All these requirements were implemented in new Multilateral reentry system. Once in field, system was proven reliable and useful for logging intervention in multilateral wells in various operating conditions.

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The retained solution used a wireline deployed milling toolstring equipped with a diamond coated bit. The benefits of this solution impacted several areas: the surface read out system allowed for fine control of the milling operation, the combinability of the tools allowed for adequate planning of potential fish recovery while retaining well barriers on a live well and the size of the equipment allowed for a rapid overseas mobilization.

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The sand cutting, though, did not work because perforations above the frac plug took the sand. Other tubing-based solutions required more mobilization time and complex logistics for rigging down and/or moving equipment on location. Therefore, the operator chose a wireline-based method for ease of operation, reduced HSE risk, and cost savings.

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At the South Tambeyskoye field, several field trial works (FTW) were carried out to prevent ACP on 4 wells:

- 3 production wells on Valanzhinsky deposits with reservoir pressures up to 350 atm.

- 1 production well on Jurassic deposits with reservoir pressures up to 820 atm.

Technology effectiveness comparison to standard methods has been conducted based on field trial results. Based on objectives achieved using modern technology, field trial works considered succesfull.

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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.

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Another challenge was that the 2.562″ and 2. 75″ ID mandrels were made of 13 Super Chrome, and there was limited experience milling these types of completion components. Also, due to a rush mobilization, there was no time to execute a SIT. The solution presented consisted of milling first the mandrel outer sleeve, then milling the inner sleeve from the plug body which will cause the mandrel anchoring system to collapse.

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The operator's method of choice was an e-line tractor and milling assembly that had previous success in the same area in similar conditions. Furthermore, a new milling bit was developed that drastically reduces milling debris and eliminates potential fishing runs. Finally, heavier intervention methods like coiled tubing were not possible to mobilize because of the weather conditions plus the risk of reservoir damage if introducing fluids required to mill on CT.

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As part of a global efficiency drive, the operator issued a challenge to the service industry, to reduce the DRILLEX of these wells whilst maintaining the beneficial productivity index that has been achieved within the highly heterogeneous carbonate field, being prone to asphaltenes. One of the implemented solutions wascement replacement across the reservoir. The benefits of this solution impacted several areas; it removed the need for drilling 100m of rat hole, under reaming of the 6 ½″ hole, clean out of the 6 ½″ hole and most significantly, eliminating cementing of the 4 ½″ liner. This led to a substantial cost savings and reduction of rig time and because it simplified the operations, the operational risks were also reduced.

The scope of work to deliver the solution included the design, development and qualification of the metal expandable annular sealing system. The project included validation of both sealing and anchoring of the cement-less liner within the open hole. The solution was also required to maintain the synergies with the perforation, acid stimulation and diversion techniques to achieve the required Productivity Index (PI) and Injectivity Index (II). The first deployment was within a well that was converted from producer to water injector. This would help validate the technology for further deployment on oil producers. The lower liner with the metal expandable annular sealing system was deployed from the rig whilst the activation (expansion) and subsequent acid stimulation were completed offline. Production and injectivity data were analysed and compared to the PI / II to the prior cemented and perforated well designs.

This paper will discuss the project scope of work, first deployment of the metal expandable sealing system, data analysis and an estimate of the risk and cost reduction delivered.

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Subsequently, a unique, star shaped milling bit was designed and manufactured to enable milling of the isolation which was smaller than 2.56" SSD and landing nipple present below the isolation valve. This was required to ensure future access for interventions through the SSD and landing nipples is not compromised and milling out the coupon from the flapper isolation valve does not get stuck in the smaller ID completion profile below it.

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TCP (Tubing Conveyed Perforation) and CTCP (Coiled Tubing Conveyed Perforation) were the logical choices, however after some considerable discussion it was agreed that wireline conveyed guns employing friction reducing rollers and tractors had the potential to save considerable rig time while satisfying all safety concerns. Detailed planning and simulation for this complex operation was required, the operator and service provider formed a strong technical alliance to achieve the objectives.

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This paper reviews and compares different ways of horizontal multizonal well preparation for hydraulic fracture stimulation using plug & perf technique in challenging downhole conditions - differential pressures over 15,000 psi, presence of depleted zones complicating cleanout and milling operations between the frac stages, depth control issues.

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In an effort to reduce rig time and ultimately workover cost, research was performed to find a cutter that could cut production casing in compression. The one chosen was an e-line conveyed cutter that could be run in conjunction with the cement bond log required on subsidence wells prior to the cut. This tool has a history of making cuts in casing that was under compression, but had yet to be vetted in the compression ranges associated with severe subsidence damage.

This innovative technology can be used in other wellbores where a quick, precise, and non-explosive casing cut is preferred, but most importantly, can be used with pipe in compression. This solution proved successful on six out of the seven cuts conducted in this campaign and is a cost-effective alternative to the aforementioned, conventional pipe cutting method. The campaign resulted in a rig time savings of approximately 18 hours per well.

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The complete straddle packer assembly was successfully installed in 17 runs without any nonproductive or lost time incidents. As a result of the intervention, gas production was greatly reduced and oil production was returned to normal levels. The operation was so successful that the client saved nearly 30 days on an operation that was planned for 45 days.

Due to the success of the initial operation, the client decided to execute several other, similar water and gas shut off operations in the field replicating the same methodology. This paper highlights the methodology used and the cost and HSE benefits provided by selecting the e-line solution with the tractor and stroking tools to perform the gas shut off. The paper will also discuss the details of the job planning as well as the execution of the operation, marking a first in this West African country.

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After multiple days spent on attempting to cycle open, attempts were then made with slickline to determine if debris accumulation was an issue. When this proved false, it was concluded that the flapper valve was mechanically stuck.

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The service company modified the tool to include a set of unique valves which would be able to store and preserve downhole liquid and solid samples, enabling the operator to retrieve and analyze the debris. This would then allow them to subsequently determine whether a planned chemical was the best possible treatment solution to remediate the suspected screen plugging.

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The stringent well control requirements of the oilfield operator make the operational design and corresponding job execution even more challenging. In this case, Well-A is a land based vertical oil well on which the master gate valve was stuck and non-functional in the closed position. The pressure bellow the valve was last measured to be 1200 psi, a relatively high shut-in wellhead pressure compared to other offset producers in the same field. 

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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.

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Prior to introduction of MCCP, all others technologies recommendedthat the pipebe placed in tension achieve a successful cut. MCCP technology allows the flexibility of effective and efficient tubing cut with string in both tension and compression which is highly desirable in deepwater intervention. The is achieved as the tool incorporated grinding of tubing surface which enables a smooth cut.

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This paper describes the logging operational experience of the CMI and the world’s first slim hole imaging logs in Saudi Arabia deployed by the wireline tractor 218XR (XR: Extended Reach) in an open hole horizontal section.

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The objective is indicating which technologies are feasiable for the future well intervention on subsea wells.

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Therefore, an open hole tractor was selected to reach the required point. To minimize the risks for the logging operation, a six blade Polycrystalline Diamond Compact (PDC) bit, Rotary Steerable System (RSS) and Logging While Drilling (LWD) were used in the pilot hole to make a smooth trajectory and confirm wellbore conditions.

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A hybrid tridem well tractor was developed based on hybrid downhole power generation and an existing wireline tractor. In order to provide the required pull force and contact to the formation, three wireline tractors were connected into a single tool.

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After the initial completion when well was put online, it couldn’t flow naturally and was activated with nitrogen. Post activation it was observed that a well with 500 m of clean sand along the lateral section and productivity index (PI) of 150 b/d/psi was flowing with a PI of ~ 10 b/d/psi which also was not sustained and well was put on artificial lift. After attempting various stimulation techniques and correlating with offset wells, it was decided to perforate the screen section of the horizontal.

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An in-depth, internal review had been conducted previously to evaluate all the available solutions in the market from both a technical and economic perspective. To enhance the chances of success, an innovative e-line conveyed core milling bit solution was selected for the pilot job in well A to restore full access to the well.

A customized solution using a 4.55 inch milling core bit run on e-line managed to successfully mill the malfunctioning lubricator valve and restore access to the well with substantial cost savings and lower risk compared to coiled tubing (CT) operation. Both milled coupons were retrieved with the aid of a catcher and brush combination designed into the bit .This managed to restore the access for the future intervention, zonal isolation and additional perforations in this well.

This paper shares a detailed case study of Well A in terms of technology selection, operation execution, lessons learnt, and future recommendations. It is evident that e-line conveyed, core milling bit technology is technically and economically feasible to mill malfunctioned lubricator valve, thus eliminating the need of expensive solutions such as CT or rig intervention.

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Based on the operators data driven decisions production and stimulation valves can be adjusted through wireline interventions, eliminating the need for control lines to surface. With no lines to surface the well design offers complete flexibility for inclusion or addition of multilaterals for infill drilling.

Results, Observations, Conclusions:
The benefits, simplicity and design flexibility of the concept makes it applicable for operators across all resource plays, conventional and unconventional. However, some factors and conditions do enhance the attractiveness of the solution, such as when traditional cementing is challenged, when high-pressure differentials are present, or when full-bore liner design is desired.

Novel/Additive Information:
This new way of designing and intervening in oil and gas wells offers the industry a safer approach that results in fewer people required offshore, simpler procedures and operations, and less equipment deployed for shorter time.

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Results:
The solution became to modify the clean-out tool by removing the drive shaft and mill bit, introduce check valves, and pre-load the bailers with Cal-Acid. This enabled the tool to act as a dump bailer with the Cal-Acid being displaced out of the pump ports and onto the scale. The Subsea Intervention Lubricator (SIL) had been pre-filled with Cal-Acid and, once the milling tool was activated in the SIL, the acid circulated into the bailers, which eliminated the need for any surface handling. The tools were then run to the holdup depth and the Cal-Acid unloaded. This was performed 16 times resulting in ~ 150 L of Cal-Acid being spotted around the scale build-up. A subsequent run with gauge cutters confirmed that the Cal-Acid spotting had been successful and access for the remainder of the operation had been achieved.

Novel info:
The innovative use of readily available tools, modified to a bespoke application, allowed the operation to continue, resulting in significant time and cost savings, and the concept of filling the bailers in the SIL made the operation inherently safer through reduced manual handling and recovery of sub-sea equipment.

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Results, Observations, Conclusions:
The high performance of the recently developed stroking tool turned out to be the correct solution for both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk including well control situation. In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head, in order to allow further contingencies to mitigate risk and increase safety. After four attempts the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.

Novel/Additive Information:
The case stories in this paper constitute the first jobs performed with the new tool. Two important features are reduced HSE risks and increased operational efficiency, which will also be captured in the paper.

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Starting from late 2013, the robotic technology solution has been used in KPO horizontal sour wells to close stimulation sleeves when required for reservoir fluid management, to convey perforation guns, to convey production logging tools and to mill frac balls and ball seats. This paper will present four case histories of the robotic technology application in the Karachaganak field. It will discuss the advantages of the technologies, the challenges and the future improvement required to further optimize the field operations.

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Results, Observations, Conclusions:
An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore. In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be
referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.

Novel/Additive Information:
Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.

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High-pressure, high-temperature (HPHT) horizontal gas wells have traditionally been challenging for performing tractor operations because of reliability issues. Recent technical improvements have enhanced the operating range of the tractor, enabling more consistent and dependable operations in these environments.

Based on the experience of conducting several plug and perforation stimulation jobs in Saudi Arabia, the electric-line (e-line) tractor has proven to be a reliable and consistent well intervention solution. The tractor-conveyed cement evaluation tools have produced high quality interpretable data used to design the multistage fracture job. Post-fracture diagnostic work has also been successfully performed in the horizontal sections to evaluate tubular integrity, providing valuable information for future fracture design. Moreover, tractor-conveyed perforating has proven to be an effective solution for conducting stage-1 toe perforations in comparison to other options from several aspects.

The option of contingency perforating in a closed system without fluid injectivity into the previously perforated stages has helped to maintain the continuity of operations. Successful tractor interventions have been performed in wells with more than 3,000 ft of horizontal sections, total depth (TD) of more than 17,000 ft, temperatures greater than 325°F, and pressures greater than 10,000 psi. This paper describes how the state-of-the-art technology has helped to meet the technical objectives of, and had a positive effect on, large rig-less production enhancement.

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Following the success of the first nipple milling in the world at an Operator’s field in Indonesia in 2009, another 12 wells had applied the same intervention technique at one field location and many other wells in various part of the world. The advantage of wireline nipple milling includes level of precision in milling, new smooth finishing of treated downhole accessories or completions, minimum cuttings left downhole, minimum volume of liquid required, small footprint required during operation and speed of milling operation that could be less than 2 hours even in small restriction such as 2.6 inch inner diameter. This paper presents the up to date achievements, case histories, challenges, best practices and technical aspects of the aforementioned milling system as well as similar challenges can be solved using similar technique.

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Results, Observations, Conclusions: An operator in the Middle East has experienced success in performing multiple tubing cuts in a single run on an offshore well using an e-line deployed electric over hydraulic cutting tool with tubing in compression.

Novel/Additive Information: Moreover the paper reviews test results from a new style of machining arms and discusses how this technology is enabling an operator to perform rigless cuts to eliminate the cost of rig time to be more efficient, safe and cost effective.

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In general, the setting and retrieving of such components requires a jarring force be applied, either up or down depending on the particular application, to overcome the shear strength of pins inserted in the valves and running or pulling tools to effect the action. In the case of slickline deployment, this force is applied from surface and transferred downhole via cable tension to the jarring device, which can be mechanical or hydraulic depending on the configuration. In deviated wells, the force that is transferable at depth is reduced because of friction contact between the cable and the casing or tubing and other factors, such as fluid weight and viscosity and wellbore debris can further impede the efficient and safe transfer of this force downhole.

These variables are sometimes difficult if not impossible to determine and model for, and changes in downhole or surface conditions during the operation can have substantial impacts on its success. This paper demonstrates a novel approach to fishing a slickline BHA while maintaining control of the slickline cable at surface. A Well Stroker tool was deployed by wireline tractor to assert the necessary force required to shear a 5/16-in. brass shear pin on an SB running tool attached to the bottom of a slickline tool string. Several procedural and operational modifications resulted in a successful operation.

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While plugging and perforating, the wireline adapter kit of the plug setting tool backed off the toolstring, creating a fish above the plug. It was unclear if the adapter kit was still whole or had broken into multiple components. The challenge in recovering the fish was that if it had disassembled, smaller components of the assembly could potentially slip through the bore of the recently set plug. If this occurred, the plug would need to be milled before a fishing attempt could be made.

Therefore, it was concluded that the fishing tools needed to be able to delicately engage the fish but still achieve a sufficient bite to hold the fish as it was dragged up the lateral. An overshot tool conveyed on coiled tubing was deemed too aggressive. Similarly, pumping down a wireline fishing tool was dismissed as the force from the pump down could potentially push the fish through the bore of the frac plug. Therefore, the decision was made to tractor-convey a rare earth magnet on e-line. This method successfully retrieved the fish on its first run, saving at least 3 days compared to the next-best recovery method.

This paper will detail the planning and execution of this fishing operation in order to provide insights for planning other extended-reach lateral completions. Specifically, this paper will show that existing technologies can be employed to overcome the challenges associated with fishing in extended-reach laterals.

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The need for such a solution was identified by an operator in West Africa. The well objective was elevated from a gas producer to a well that required the flexibility to produce gas or oil with gas lift capability. The well flow valve was selected and required on site variable choke capability for both oil and gas production, with choke position verification, ability to handle dirty gas production without risk of plugging, compliant with a high rate and high pressure proppant frac along with ease of operation and long term reliability.

The field trial included a high pressure proppant frac in the oil zone. In the shallower gas zone, three well flow valves were used to deliver variable choking capability from maximum gas flow rate with minimal delta P adjusting down to a choke size suitable for gas lift. The well flow valves were operated using a high expansion shifting key conveyed on eline through the 3 ½” production tubing. The shifting key expanded in the 4 ½” lower completion to open/close individually all the well flow valves in a single trip. Incorporating this new product overcame the challenges presented and met the objective of commingled production of oil and gas. The well flow control valve demonstrated flexibility through design, supply chain, manufacturing, and operations. This paper will also outline the future road map covering further developments of the well flow valve and its incorporation into an enhanced flexible lower liner solution aimed at lowering well completion costs and risks.

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For these specific conditions, it is beneficial to add an assurance that would maintain the integrity of the well even in case of bad cement. Some of the assurances used include port collars, external casing packers (ECP) and swell packers. Port collars allow a squeeze above the first stage cement, while ECP serves as a base for a second stage cement, and swell packers provides a baffle for sustained casing pressure. A more recent technology is the well annular barrier that can form a combined barrier with cement, and can also be used as a stand-alone primary barrier.

The well annular barrier is a metal-expandable barrier that is expanded with hydraulic pressure. It is full bore, highly customizable, and qualified to ISO 14310. The metallurgy allows the packer to shape fit into either an open hole with irregular geometry or inside a casing to preclude annular pressure build up by giving a life-of-well reliable seal. The well annular barrier has been deployed in a variety of wells to achieve well integrity with and without cement, protect the B-annulus from sustained casing pressure, or serve as a barrier between reservoirs that cannot be commingled.
This paper performs a review of the technologies used for cement assurance, their advantages and disadvantages. Case histories of well annular barrier deployments are presented, including a case where the well annular barrier was used as a stand-alone well barrier element without the need for dispensation. This paper also discusses how the well annular barrier fits into the regulatory requirements for well construction providing to the drilling industry an alternative to cement for the purpose of well integrity.

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On re-entry into the well, a mechanical restriction was met in the high angle section of the well thus impeding access to drain hole. A review of the situation, showed a possible collapse of the lower completions (sand screen) possibly due to high sand production. An attempt at sand clean-up was futile.

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The newly developed system consists of pressure and temperature sensors either mounted independently from, or integrated with, the WAB. Annular sealing integrity will be confirmed by direct pressure measurement down-hole. 

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The information gathered from this intervention would improve the overall understanding of the reservoir and well behavior thus enabling the operator to manage the multi-lateral wells’ individual drains, ensure production assurance and sustainability and revisit the development plan for the tight reservoirs based on proper reservoir evaluation.

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A major challenge that faces production engineers in their daily operations is identifying and accessing laterals windows in those MRC multilateral wells, in order to preform rigless downhole sensing and intervention jobs (logging, stimulation, etc.). 

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Following the cement operation, hydraulic pressure was applied to expand rapidly the sleeve bodies in wet cement and set against the 12 ¼" borehole thereby creating an impenetrable seal. The sealing was ultimately confirmed by the absence of scale during production compared to the previous experience of shut-in after only 18 hours of production.

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In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the setting tool had failed before it could break the stud connecting to the plug.

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When drilling SAGD well pairs, it is common practice to have an active ranging device placed in the “target” wellbore to aid in accurate well placement. The active ranging devices are electronic in nature and are limited to temperature exposure for reliable performance.

Collaborating with the operator, a secondary measurement provided by an e-line device was used in conjunction with field proven magnetic ranging equipment in order to provide real-time feedback to surface with the purpose of mitigating risks due to the high temperatures. The diagnostic device was used to monitor the effects of pumping fluid into the wellbore in order to cool sufficiently and thus protect the sensitive electronics in the active ranging device.

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The present paper describes the development of an intelligent, real-time controllable tool, the well-lateral-intervention tool (WLIT), that can identify a lateral junction and steer an intervention/surveillance string into it.

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Tests were conducted in a high‐pressure, corrosion‐resistant vessel over a range of high pressures (100 to 10,000 psi) and high temperatures (75 to 150 °C) to simulate downhole well conditions.

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Reliable and effective annular barriers continue to be crucial to well management for safety and performance. Cementing has been the industry’s conventional means of creating these barriers, having been used for almost 100 years (American Oil & Gas Historical Society 2015). However, the industry is not drilling and completing wells the way that it did a century ago.

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An electric driven version of the Well Tractor for wireline operations. Powered and controlled through the wireline.

The Well Tractors are designed in 3 different sizes. A Tractor with an outside diameter of 3 1/8″. A Tractor with an outside diameter of 4 3/4″ and a Tractor with an outside diameter of 2 1/8″.

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Careful pre-job planning is necessary to ensure success, since the Well Tractor technology adds a new dimension to the techniques required in normal wireline logging and well intervention.

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In the second case, drilling losses to the formation were experienced and it was decided to pump lost circulation material. However, during pumping the drill pipe plugged up completely. At the same time flow was recorded on the annulus side and the drilling BOP annular preventer was closed with subsequent pressure build-up below. A 2 1/8” Well Tractor was successfully run inside the DP to first gauge and subsequently punch holes in the drill pipe to open for circulation, thereby allowing pumping of heavy mud and regaining well control.

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This data, coupled with recent production data from other long wells in Lekhwair, provided the confidence to propose and drill extremely long horizontal wells (up to ~4 km openhole length) in 2000, resulting in a significantly more cost effective and faster field development.

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The service company was able to develop the solution within the client's parameters and in accordance with the timeline set out for this project. The offshore operation was completed in three days to the operator's satisfaction.

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Another world’s first from a vessel, was the deployment of a wireline driven Well Tractor® to convey lowside orientated perforating guns out in the deviated wells, incorporating the shortest tractor length ever deployed. The wells were water injectors, slightly under balanced and treated as live as hydrocarbons could enter the wells after the perforating. The longest well was 5657 m MD (18560 ft) and with highly deviated step out of approximately 2973 m MD (9754 ft). The paper will conclude with lesson learned and cost benefit issues.

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Also covered are the working principles of the CT Tractor and comparative calculations of lateral CT reach with and without the tractor. In addition, a world record setting CT tractor case history is discussed.

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Job Design

Based on computer simulations, it soon became clear that it would not be possible to reach the desired depth using coiled tubing and conventional "extended reach" techniques alone.

Computer simulations using reduced friction coefficients and/or altered fluid densities only improved results marginally and indicated that the 2-in" (optimized taper) coiled tubing at best would go into a lockup 174 meters away from target depth. Computer simulations using 2-3/8-in" coiled tubing also showed similar results with a little added penetration. CoilCAT* software was used for modeling of tubing forces in the well.

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Wells selected are horizontals that were drilled in a carbonate reservoir in the oil fields (both land and offshore) that are present in the eastern part of Saudi Arabia. The total length of the target zone for the Well “A” and Well “B” is 13,543 and 20,304 ft, respectively. Typical coiled tubing (1 ¾-inch) cannot reach the total depth in these well (CT lockup length is 10,300 ft for well “A” and 13,320 ft for well “B”).

A special hydraulic tractor was used to pull the coiled tubing to the total depth of these two wells. A visco-elastic surfactant based acid system was utilized to remove formation damage induced by the drilling fluid (water-based mud) and enhance the permeability of the formation in the critical wellbore area. Corrosion inhibitor and other acid additives were carefully selected to maintain the integrity of the well tubulars, coiled tubing and the tractor (metallic parts, O-rings and seals of the tractor). Before attempting the stimulation of the extended reach well, a water jetting method was adopted to remove near well bore damage resulting from the drilling mud cake and mud invasion. Production logging tests were conducted after drilling the well, after the water jetting treatment, and after the matrix stimulation. The productivity index of the well decreased after the water jetting treatment. However, the acid matrix treatment delivered through the CT tractor nearly doubled the productivity index of the treated well.

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Introduction

The Petronius project, located 150 mi south of Mobile, Alabama in the Gulf of Mexico, is operated by Chevron Corporation, with Chevron Corporation and Marathon Oil Corporation having a 50% working interest in the project.The project was sanctioned in August 1996 after a compliant tower and subsea development options were evaluated.The compliant tower alternative was selected based on superior well intervention capability, less complex seawater injection system designs, lower investment, and future hub potential.The 2,001-ft tall Petronius compliant tower is set in 1,754 ft of water, and is the world's tallest free-standing structure.

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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.

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This paper will present case histories and the benefits of operation, particularly in deviated wells, where tractor technology in combination with the Wireline Stroker exemplify the advantages of the subject technology.

In a well offshore Norway, producing since 1995, completed with 2 Sliding Side Doors (SSD) to control zone production, attempts had been made to close both SSD’s in October 2003, but only the upper SSD was possible to close. A two-piece straddle was sat above the lower SSD, which however showed no change in production. PLT results showed an internal leakage in straddle and tubing; straddle was therefore retrieved in February 2006 and the well temporarily plugged.

Later in 2006, it was decided to perform a new intervention in order to remedy the situation and a Tractor/Stroker combination was considered optimal for performing the operation, as an alternative to a Coiled Tubing operation.

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Lightweight and riser-less intervention well intervention has in this context become a proven approach with considerable potential for driving the future development. The ability to substitute large rigs with smaller and dynamically positioned light well intervention vessels has a major impact on cost and time. Riserless intervention as such has been done regularly for a number of years and has set excellent HSE standards. However, in recent years the use of riserless well intervention has become increasingly instrumental in the effort to enhance recovery rates and general performance.

The paper gives an account of a scale milling operation carried out at a Norwegian field in the North Sea where two wells both suffered from a significant drop in production.

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The paper provides a detailed account of the preparations and actual milling operation, including the lessons learned and how the objectives were achieved.

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RLWI operations are now common in shallow water depth up to 600 meter although at least one operation has been performed on 906 meter water depth.

Considerable efforts have been made to improve the RLWI system with respect to efficiency, weather sensitivity and at last – but not least – deep water compatibility.

During RLWI in deeper water, the environmental loading on the wireline from the vessel to the subsea equipment becomes the limiting factor as the wire is subjected to considerable loading from sea current.

Welltec, one of the pioneers in RLWI operation have started an R\&D program to fully understand the limitations and to provide the operator with a tool to assess if RLWI is possible based on simulated behavior and empirical data instead of merely stating that RLWI is not possible beyond a certain water depth.

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The approach presented is based on a solid metal expandable system developed for the applications where swellable external casing packers traditionally have been used. The well annular barrier provides long term robust and reliable zonal isolation in cemented or un-cemented wellbores and may be used in conjunction with casing as well as liners. It also provides higher differential pressure capacity and higher expansion ratio to running OD without compromising the inner diameter. Consequently it does not impair or restrict flow conditions and furthermore enables subsequent well maintenance to take place unhindered.

The paper presents the results of the development and testing of the new solid metal expandable system for external casing applications and discuss the rationality behind the technology as well as the experience gained.

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In order to keep the bit clear during milling, cuttings were flowed back to surface. Progress was made until the surface choke packed off and flow was no longer achievable, the toolstring had to be retrieved whilst choke and lines were cleared. The scale sheath was eventually broached and the decision made to continue in hole in order to drift, as well as providing the capability of dealing with any further scale that may be present; the Tractor Miller was started once more with a minimum of resistance encountered. Target depth was attained, all Tools were then retrieved to surface with no issues.

The overall objective was achieved, resulting in a significant increase in production. One hundred and twenty one (121m, 390 ft) of calcium carbonate scale was removed during the operation, validating the use of light well intervention techniques when removing scale.

This paper will discuss the technical aspects of e-line milling and challenges overcome during this particular operation.

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The operator is now able to optimize their gas lift design without the limitations imposed by conventional means for installing GLVs such as slickline and coiled tubing. This allows them to place gas lift valves in the high angle sections when necessary for increased oil recovery from their reservoirs.

Few changes have been made to the Kick-Over Tool technology in the past 40 years but it has been recently improved to operate more reliably in deviated and horizontal wells and has been modified to accommodate the forces generated by the HST. This paper will describe the challenges with the planning and execution of this operation and the implications for future gas lift design.

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The operator deployed the cleaning equipment in August 2011 and performed the work in 18 hours operating time. The SSSV tested successfully on the following day and the well was returned to production. The operator estimated that the selected technology saved more than a week of deferred production at 7500 BOPD and direct costs of rig mobilization. The wishbone honer brush tool run on a well tractor and electric line proved to be the alternate solution they were seeking and it is now the operator’s preferred technology for this application.

This paper will present the operational challenges as well as the results of this successful, rigless cleaning operation on an important producing well.

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Milling of wireline and other well bore obstructions on electric line offers a cost efficient alternative technology to existing methods. Furthermore, it offers reduced Health, Environment and Safety (HES) risk benefits and logistical advantages.

This paper will describe the actual process from preparation to completion of this first-of-its-kind fishing operation.

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The remaining debris in the internal fishing neck of the plug was sucked up by a high-powered e-line cleaning tool and the plug was pulled in the same run. The job was executed without incident from a small, dynamically positioned, vessel with a moon pool and a subsea lubricator, saving the operator about one year’s deferred production versus waiting for the coiled tubing solution. This paper discusses the operation of the downhole tools and procedure for riserless deployment to achieve the objectives and create this value.

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Based on site-specific experience, the operator concluded that each well intervention with drill pipe would require 48 hours per trip. In August 2011, after a formal risk analysis and systems integration testing (SIT), the operator mobilized a down-hole, robotics-solutions provider and successfully tractored a cement evaluation log to 11,079 ft. A regional record was set for longest tractor-conveyance during the first perforating run of 12,095 ft. A second perforating run of 11,037 ft was successful and set a regional record for longest, cumulative, tractor-conveyed distance in a single well at 34,211 ft. The cement evaluation and perforating runs were completed in less than 40 hours versus more than 96 hours, which was the estimate with pipe conveyance. The results of operations in the HS Llanos well are presented. Lessons learnt from these operations are part of this study.

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It also demonstrates that the candidate wells feature horizontal sections that are amongst the most ambitious for the application of the wireline tractor technique.

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Using a combination of tractor and milling technology on e-line in these wells provided the required torque for milling with a steady and constant weight on bit throughout the wellbore for removal of ball seat restrictions. This paper presents the latest achievements within e-line milling in Canada. The paper will discuss best practices of date as well as a discussion of e-line milling challenges through three case studies in Canada.

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On a previous workover, the operator had experienced problems pulling a packer, debris was suspected in the annulus resulting from an explosive cut then subsequent run to dress off the flaired end. Therefore, they were looking for a different method for tubing cutting operations, one with reduced risk, reduced debris, and fewer post-cutting tasks prior to removing the tubing and completion.

In the first trial, the tool was used to successfully cut 4-1/2-inch, 12.6-lb/ft tubing in a 57° deviated well, at a depth of more than 2,133.6 m. Total operating time was six hours and actual cutting time approximately 80 minutes. The e-line cutting tool cut the tubing cleanly without flairing or creating substantial debris, leaving a smooth, beveled interior which can be fished without dressing off the cut using a conventional overshot. 

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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 perform the sand cleanings, and
 Points 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.

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The operator decided to try the e-line technology on a five-well pilot project of cased, horizontal wells in the Eagle Ford development. This was the first time the technology was used in U.S. land operations. The e-line cleaning tool cleaned the wells, and the tractor-conveyed perforating guns reached the depth cleaned out by the e-line cleaning tool. On this pilot project, the average field time per well for an e-line cleanout and tractor-conveyed toe perforation was 24 hours. The pilot test was considered a success.

This paper discusses the details of the project and tool operations for each well, and the lessons learned and applied to each successive well in the pilot to develop a successful strategy for using these tools across a broad range of operating conditions.

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The e-line tool string included a wireline release device, an electric-over-hydraulic tractor with stroking tool, electric milling motor, and burning shoe with integral centralizer and no-go. The burning shoe was designed to reduce the outside diameter (OD) of the frac sleeve but preserve the packing bore inside diameter (ID) of the SSSV landing nipple. The tractorstroker- miller tool string was run in the well and tagged the sleeve at 2,119 ft measured depth (MD) where milling continued for approximately 4 ½ hours. After E-line milling was completed, slickline was rigged up for fishing operations and successfully pulled the frac sleeve. The tubing repair was completed and the well was returned to production.

This intervention technology can be used in other wellbores requiring precision milling. The solution proved successful and is a cost-effective alternative to conventional methods for milling obstructions.

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The operator had learned about a new electric-line, high-pressure suction tool that could be used instead of CT to remove the fill from around the plug’s external neck, thereby eliminating the extra time, cost, and HSE risks associated with CT use. During workover operations on a Gulf of Mexico well, the operator decided to put the electric-line suction tool to the test to determine its viability as a cost-effective alternative to CT.

This paper describes the successful use of the electric-line power suction tool to clean sand from around the inflatable packer’s external neck, which allowed the plug to be removed and production to resume.

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The benefits of extending the lateral reach capacity for the CT are multiple. Since the wells have already been drilled, there is the sunk cost associated to the depth of the well. If there is no method to get the CT to this depth, this cost cannot be capitalized on. Additional sunk costs are incurred by preparing, transporting and mixing all the stimulation fluids required to complete the entire well to the job site. If the CT hangs up far shorter than TD, these costs are again not recouped. Further, by not stimulating the well from the toe, or TD, the total production potential of the well is unrealized. In one of the wells, a world record was achieved when the CT tractor reached 28,759 ft. The operator wanted to access the open hole for stimulation, but without the 2 ½” CT tractor, the 2” CT would only have reached ~ 85% of the open hole section, leaving ~ 15% of the reservoir unstimulated. In another well, the CT tractor extended the reach of the CT by 5,610 ft, or 28%.

The CT tractor has proved itself capable of increasing the length of CT used on Manifa wells. This not only increases the operator’s return on sunk costs but more importantly, it increases the potential for full reservoir stimulation and boosts the productivity index significantly.

This paper documents the activity and successes that CT tractors have brought to Saudi Aramco in Manifa field.

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Modern electric line (e-line) capabilities can now accomplish what conventionally would have been rig- or coiled tubing-based workovers. In the North Sea, Canada, Alaska and Russia operators use e-line to perform ‘heavy’ workovers; explosion-free cutting of tubulars, scale and debris removal, milling through hardware such as nipples, failed isolation valves and flapper valves, and replacement of hardware, such as gas lift valves and Electric Submersible Pumps (ESP’s) in extended reach horizontals.
This paper discusses the benefits e-line tools can bring to accomplish ‘heavy’ workovers in a reliable manner in high latitude environments. Several case studies are presented to demonstrate these applications in practice.

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By turning to e-line tractor conveyance the 26 runs to ‘plug-and-perf’ were completed in just 14 days with no lost time. In addition, the patch was successfully negotiated, the plug set properly and the entire section was perforated. The swift and nimble nature of the e-line technology made it easy to overcome the logistical challenges and helped the operator with their timing and budget issues.

This paper will show why using e-line tractor conveyance was the right solution for this intervention where 146,608 ft were tractored with no lost time.

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This paper will share the learnings from a number of local operations in which this electric line technology has been deployed, including advances with DC electronics and some examples of AC electronics cases ranging from conveyance of logging tools to plug and perforating for fracture stimulations.

In addition, this paper will examine the differences between AC and DC electric line equipment, their application in high-temperature environments, as well as discuss current trends within electronics for electric line equipment and future outlook for high-temperature equipment.

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A traditional intervention operation to repair this includes using a slickline (SL) rotating wedge to manipulate the flapper to a position that will allow a subsequent, suitably 3 sized sleeve installation through the cavity, bypassing the flapper. This will allow for both toolstring deployment past the obstruction to assist in future up-hole re-completion operations and continued production without slugging from unexpected valve flapper reseating.

This paper discusses a case history in which the above-mentioned conventional SL manipulation toolstring was deemed not suitable, as it was currently designed for a small cavity-type Tubing Retrievable Surface Controlled Subsurface Safety Valve (TRSCSSV), and alternative intervention means were developed. Five full-scale4 tests were performed with four different toolstrings (one SL and three electric line [EL]) engineered to provide a method of inserting a bypass sleeve with predetermined minimum inside diameter requirements for future tubing cutter deployment. Of the four toolstring options developed, two were deemed field ready and deployed with the offshore operation itself, while the other two required additional engineered modifications. Details of the successful intervention deployment are also given in which desired flapper orientation and isolation was not only achieved by toolstring manipulation but also by well-production characteristics.

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The benefits to operators include increased reliability and certainty for success, both in the short-term and over the life of the wells.

This paper reports recent implementation of the new annular barrier to meet the unique challenges of annular high pressure containment. Findings are supported by specific case examples, and the paper includes a discussion on design, application and performance.

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A hydrate plug was tagged below the subsea tree in a water injection well. This unconventional solution was chosen to restore injectivity to wellbore and minimize non-productive time (NPT). Unfortunately, during the operation, harsh weather caused operations to be stopped due to safety issues, and prevented removal of the entire hydrate plug. At that point, re-establishing functionality to the downhole safety valve became a major issue. Fortunately, in less than 20 hours of milling time 173 ft (52 m) of hydrates were removed on e-line and the operator was able to re-establish the functionality of the downhole safety valve.

E-line technology provided a swift and accurate resolution to the problem, proving that hydrates can be dealt with as easily as doing any other e-line intervention and that the technology can be run in a ‘live’ well under pressure.

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A 3.6 in. patch was restricting the inner diameter of a 4½ in., 11.6# casing string. The operator needed to plug and perforate 26 zones horizontally from 21,740 ft up to 11,830 ft to get the well on-line quickly. Pumping the 4½ in. plug was not considered an option due to the risk of premature setting or pumping off plug and/or guns resulting in expensive and time consuming fishing operations. Coiled tubing would only be able to reach the first 16 zones leaving 10 zones non-perforated. Rig operations would be too time consuming and costly.

The 26 run, e-line operation was completed in 14 days with no conveyance mis-runs or lost time but only one gun mis-fire. The well was brought on-line quickly and the logistical challenges easily overcome due to the lightweight nature of the e-line technology. As an added bonus the operation offered several HSE benefits stemming from the low footprint, reduced personnel requirements, and less heavy lifting. 

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Building on experience, success factor analyses and best practice guidelines, the success rate of OH tractoring has steadily improved over the years. One of the traditional limiting factors is the diameter of the OH, which can be beyond the reach of the tractor arms or wheels, either due to large bit sizes or enlarged boreholes caused by washouts. A new generation tractor was introduced in 2010 to address this issue. With an outer diameter of 4 1/2” and an operational OH diameter from 4.8” – 18” this tractor has made another step improvement in the success rate of OH tractoring.

This paper will also review the tractor-based OH conveyance logging services including triple combos, production logging tools, formation imaging logs as well as formation testing.

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The first ever operation involving the milling of a blocked borehole on wireline was conducted in late 2003 in an oil producer on a North Sea platform. A single plate isolation valve was stuck in closed position and it was imperative to get the oil producing well on-stream at short notice.

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This paper describes the logging operational experience of the CMI and the world’s first slim hole imaging logs in Saudi Arabia deployed by the wireline tractor 218XR (XR: Extended Reach) in an open hole horizontal section.

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