Artigos Técnicos

The metal expandable annular sealing system was custom designed in order to provide high expansion that can be set in potentially washed out wellbores. The design included a long multi-element sealing system with built-in redundancy to account for fracturing fluid chemical reaction with the rock behind the seals

The system is just under 4 meters, complemented with multi-elastomer seals, each delivering full Delta P capability within a washed-out hole up to 6.5”. The unique design allows full rotational capabilities during deployment, minimizing operational risks.

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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Wireline conveyed, lightweight, robotic intervention tools were used in one of fields in Saudi Arabia to collect uncontaminated sample of obstructive material for future chemical treatment and to remove the bridge in Open Hole section of oil well, so Workover Rig or Coiled Tubing intervention can be avoided or significantly deferred. Operation was performed without killing the well and with no additional fluids pumped into well, reducing possible intrusion and skin build up. This technology was run first time in world practice to clear an obstruction in Open hole section.

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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Many previous subsidence workovers had utilized drill-pipe conveyed cutters which required the casing to be in tension to ensure a quality cut. In order to get the casing in tension, a multi-step process was required. First the blowout preventers (BOP) and tubing heads had to be removed. That was followed by a controlled growth of the compressed casing after which the casing was then stretched and re-landed in tension. The excess casing was then cut off, and, finally, the BOPs were re-installed and tested. This entire process could many times take over 24-36 hours.

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 client’s considerations included coiled tubing (CT) and slickline. It was also necessary to be as efficient as possible to keep time and costs down. Based on these considerations, the operator decided to use an electric line (e-line) tractor combined with a hydraulic stroking tool for its high reliability. The stroking tool also provided the benefit of delivering the required force at the exact point where it was needed downhole as compared to coiled tubing, which would exert the force from the surface.

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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Currently, the operator has embarked on an aggressive, reactivation campaign to restore production through interventions. Well A became idle in January 2013 due to unknown reasons and was selected as a pilot well for the re-activation campaign. Tubing Retrievable – Surface Controlled Subsurface Safety Valve (TR-SCSSV) cycling and Critical Device Function Test (CDFT) were performed successfully, but did not impact the production. In August 2013, lubricator valve (LV) diagnostics were performed using a Lead Impression Block (LIB) tool which indicated that the lubricator valve above the TR-SCSSV was only 80% open. As such, this malfunctioning lubricator valve (LV) prevented any future interventions for diagnostics, zonal isolation or the addition of perforations in order to fulfill the objectives of the idle-well reactivation campaign.

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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Methods, Procedures, Process:
The approach, here referred to as the flex-well, concentrates on simplicity while providing all the components an operator requires to design and construct a completion that is fit-for-purpose; it can be as minimalistic or as intricate as the operator requires in order to accomplish maximum reservoir drainage. The flex-well has been engineered to provide a low total-cost-of-ownership solution that meets global operators’ current and future drilling, deployment, and production
challenges. The flex-well integrates intervention solutions through a full-bore completion designed for easy access and proactive adjustment. Diagnostic solutions that convey information to surface through wireline data retrieval allow operators to achieve a detailed understanding of well characteristics without permanent cables to surface. This understanding allows for better decision making to optimize and manage the reservoir for maximum recovery throughout the life of the well.
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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Method
The operation took place in the British shelf of the North Sea. A subsea well was facing severe scale issues that were threatening to stop production. From the beginning, it was the plan to perform the operation as a RLWI from a vessel. During the initial drift run, it was discovered that the CaCO3 scale had become so severe that it would not be possible to run the e-line milling solution as originally planned. The team needed to remove ~15 ft. of scale in order to accomondate the clean-out toolstring below the subsea tree before the operation could continue. Standard dump bailers were not available on the vessel and, as weather prevented the flying of equipment to the vessel, the team worked together to quickly contrive a readily available solution that would allow Cal-Acid scale dissolver to be spotted precisely and safely at the holdup depth.

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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Methods, Procedures, Process:
In one operation, a plug was accidentally set across the christmas tree and blowout preventer (BOP), effectively eliminating the christmas tree as a well barrier element, and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar. 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.

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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Examples of such tasks are downhole milling, shifting of stimulation sleeves, etc. Surface real time monitoring and control features are required to ensure that such tasks done by robotic tools are successfully achieved with high accuracy. As the demand increases to use this type of powered devices in a more hostile well environment, service companies have developed technologies to expand their operating range.

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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Methods, Procedures, Process
The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment’s arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the
fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.
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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Multistage fracture operations are primarily conducted using plug and perforation technology to establish reservoir connectivity and production. The stimulation work involves multidisciplinary teams conducting simultaneous operations in a limited workspace and time. The primary well intervention challenges include the following:

• Effective deployment of cement and casing inspection tools in the horizontal section
• Safe, reliable, and efficient technology to convey the perforating bottomhole assembly (BHA) to the target depths in the long horizontal section during some stages of the plug and perforation operations
• Available, reliable, and readily deployable contingency perforating option for plug and perforation operations

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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The methods described were actual field operations demonstrating the successful application of the technology in a mature field. This paper will describe the history, background and challenges of a well in this mature field and the subsequent application of alternate technology to overcome those challenges and maintain the asset as a viable, producing well. Due to the availability of downhole tools and services to solve an immediate problem in a well, the need to reconstruct the existing wellbore interior to create larger access for example, becomes inevitable in many cases. Such was the case on offshore wells in Indonesia where the inner diameter size of the downhole accessories forbid tools to reach the lower targeted depth.

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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Methods, Procedures, Process: A common practice for workover operations is to remove the existing completion and replace it with a new completion, either the same or sometimes with improved components. One of the steps required to pull the completion in this case is a run to cut the production tubing in one or more places prior to pulling the completion from the wellbore. A common practice is the use of an e-line cutting tool. Conventionally the best practice for this e-line tubing cut operation is to keep the pipe/casing in tension while performing the required cuts. This practice prevents pinching of the cutting blades and ensures higher chance of a successful cut for the operation.

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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These technologies often present cost-effective alternatives to proven methods, providing in many cases more precise control of operational parameters and greater access to highly deviated well configurations. Slickline cable deployment as a means of well intervention operations has long been an industry standard for a wide range of applications. Bottomhole assemblies (BHA) can be designed and configured to set and retrieve a broad variety of valves and plugs required for numerous completion and well maintenance procedures.

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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It is desirable to remove the control lines whilst maintaining the functionality of multi zone, variable choke flow control. The well flow valve is a full-bore, reliable and robust mechanically operated sleeve, qualified in accordance with ISO14998 including multiple open/close cycles, at a sustained unloading pressure of 1,500 psi, with highly customizable flow ports.

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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A little bit more than half of the failures can be attributed to operational challenges (pump failure, cement contamination), or design oversights (cement recipe, centralizers). However there are still cement failures with perfect design and field execution. These failures typically exhibit some of the following characteristics: high deviation, high pressure, washouts, natural fractures, long casing section, heterogeneous sands.

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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The Well Tractors are used for cleaning, setting and pulling of plugs, operating sliding sleeves, open hole logging, running of production logs, drilling, perforation guns, cement bond logs etc.

Horizontally the Well Tractors pull coiled tubing and/or wireline beyond 10,000 ft. The Well Tractors are capable of pulling more then 25,000 ft of coiled tubing and/or wireline into a highly deviated well. Furthermore the tools are designed for pushing other tools into the hole, e.g. logging tools, video cameras etc.

The Well Tractors with modular power source are designed in two versions:
A fluid driven version for coiled tubing operations. Powered by brine, water, mud etc. which is pumped down through standard coiled tubing. The tool is controlled from the surface via a wireline running inside the tubing. Through the wireline measurements can be transmitted to the surface. Alternatively the tool can also operate without the wireline which enables it to run with a smaller size of coiled tubing or have a higher flow rate for e.g. cleaning jobs.

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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The Well Tractor technology has been extensively field proven and has demonstrated significant cost savings for operating companies when compared to previous methods of performing well intervention operations in horizontal wells. In some cases, use of the Well Tractor technology can mean the difference between whether or not required well intervention operations can be carried out.

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 first case, the drill pipe became stuck while running in and circulation was subsequently lost. After 100 jarring cycles were performed it was decided to attempt a fishing operation using the 2 1/8” Well Tractor enabling the retrieval of the radioactive logging source. The retrieval tool was deployed on Well Tractor, which enabled the radioactive source to be successfully recovered from the bottom hole assembly (BHA). The drill pipe was subsequently backed-off using Well Tractor to convey the explosives.

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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Two logging runs were carried out by Schlumberger, one of which reached the world record distance of 1550 m in openhole (3012m along hole). Water flow log (WFL) and full bore spinner (FBS) data were measured and confirmed that injectivity is uniform along the length of this well, providing confidence in the current line drive, water-flood field development. This is the first time that quantitative logging data has been obtained from an openhole using the Well Tractor.

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 paper will further discuss the challenges and the experiences captured and gained from the operation. The water depth was world breaking for this type of well intervention vessel operation, with a water depth of 341 m (1120 ft).

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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The application of the Well Tractor facilitates the use of Coiled Tubing on offshore platforms where it previously could not been utilized due to crane and/or platform deck loading limitations.

This paper describes the innovative Well Tractor tool developed to extend the envelope for CT operations. The tractor is fluid driven and capable of over 2500 lbs pull/push. It is designed to work with acidifying fluids, nitrogen or drilling muds.

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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Introduction

Njord is a sub sea completed oil field operated by Hydro, located offshore northwest Norway. Njord "A" is a floating drilling and production unit. The well is an oil-producer in the Tilje formation, completed with a 7-in" production tubing and a 7-in" perforated liner (Fig 1&2).

The objective was to isolate selected intervals in the reservoir section at 130 degrees inclination in the "toe" of the well in order to reduce the gas to oil ratio (GOR). The chosen method was to install a purpose designed straddle packer assembly utilizing coiled tubing and tractor.

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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This paper discusses an innovative approach to treat horizontal wells with extended reach. This new technique comprises mechanical diversion in the wellbore, and chemical diversion in carbonate formations.

Coiled tubing has been used for years to better distribute the acid in vertical and horizontal wells. However, application of coiled tubing in long horizontal wells is a function of wellbore diameter and length. Coiled tubing cannot reach the total depth of the well if there is large washout, or if the length of the open hole is greater than what the CT can reach. The maximum length that CT can reach depends on the length of the reel, diameter of the coil and wellbore geometry. To extend this length, we have used a hydraulic tractor to pull the coiled tubing to the total depth of the well. This will ensure better acid distribution over the wellbore. To enhance acid diversion in the formation, a visco-elastic surfactant-based acid system was employed.

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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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.

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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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 10 K – 30 K 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.

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A new technology has enabled increased recovery rates by managing produced water and allowing remote mechanical manipulation of downhole valves on Wireline. These services are possible when applying a robotic stroking device and a Wireline key tool combined with field proven Wireline Tractor technology – best described as Well Construction on Wireline in a highly deviated well.

This technology represents a cost-efficient method for setting and retrieval of specific downhole hardware (i.e. plugs and straddles) as a resource-efficient alternative to existing technologies.

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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This is due to the high intervention costs which are directly related to the rates of the rigs required to carry out such operations if the traditional and conventional approach is adopted. Hence the incentive to increase recovery rates has been limited as the balance between cost and revenue has been unfavorable, even with increasing oil and gas prices. However, this has also stimulated the development of alternative methods which can enhance recovery rates and not least address the challenges created by more fields passing maturity and exploration moving to more demanding areas.

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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An identical setup with two sizes of seats and balls was established in an almost horizontal pipe setup onshore and the tool-string consisting of a conveyance tractor mounted with a milling device fitted with a tungsten carbide bit was driven into the pipe. The milling was carried out with different levels of weight on bit by adding back-tension on the cable as well as using different numbers of drive sections on the tractor. Then the results were evaluated. Additional tests were carried out with parts of a milled ball dropped down hole on the ball seat to ensure that milling could be done. The tests showed that the tool-string as configured could mill out the ball seats in one operation. This was later confirmed as the actual seat situated at 12.647 ft. measured depth was removed in one run.

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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It is a well known fact that subsea wells normally under perform platform wells in recovery between 15-20%. To a large extent, the gap in recovery is related to the high cost in access to the subsea well compared with surface or platform wells.
Efficient and low cost well intervention techniques are of the out-most importance for increased field recovery. Riserless Light Well Intervention (RLWI) is one of the tools helping to close the recovery gap.

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 use of cement as annular isolation usually is considered as the industry standard, however it is a complicated, time-consuming and expensive to deploy. Alternatives, such as polymer-based swellable packers, are usually less complicated to deploy, but the degradable polymers invoke a risk in the typically harsh environment of a well.

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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The Operator was experiencing high water cut in one of its wells; previous interventions in other wells connected to the same reservoir indicated a high probability of scale. The plan was to log, isolate the watered out zone and then re-perforate in order to increase oil production rate. Electric line Tractor Milling equipment was mobilized as contingency, should well access be an issue, which happened to be the case.

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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Slickline was unable to overcome the higher deviations, while imprecise depth control during coiled tubing operations required multiple run-in-hole attempts to pull and replace the valve.

Based on previous, positive experiences with electric line – mechanical solutions, the customer chose a unique solution using a newly modified Kick-Over Tool (KOT). Two KOTs run in tandem and combined with a tractor and a hydraulic stroking tool (HST) were used to pull the existing gas lift valve (GLV) and replace it in a single run. The tractor conveyed the tool string to the correct depth where the HST and the first KOT provided the pulling force for removal. Then, the HST and second KOT were used to successfully install the new GLV into the mandrel.

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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While testing a SSSV in one of its wells in the Campeche Bay, a major Latin American Operator discovered scale deposits that prevented the SSSV from sealing shut. The operator was looking for an alternative mechanical solution, since pumping acid into its wells had not been effective. A downhole tractor service provider approached the operator and after carefully studying the case, presented the wishbone honer brush design run on a well tractor and electric line to repair the valve in situ and avoid costs associated with mobilizing a rig and removing well components. It was the first time this technology was used successfully for this application.

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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In July 2011 on a small, unmanned offshore platform in Equatorial Guinea, a downhole tractor and a milling tool were conveyed on electric line to remove an obstruction created by Lost in Hole (LIH) electric line cable and production logging tools (PLT).

By using customized core milling bits, 13 successful milling runs were made. During this unique operation, most of the milled wireline material was recovered, and the challenges of controlling torque and milling penetration were achieved. In between milling runs, slickline fishing attempts were made in order to recover the remaining LIH wireline. After the last milling run, a major breakthrough was made when the PLT string moved downhole to a position that uncovered the proposed new completion interval. Ultimately the well was perforated and returned to production at projected gas and condensate rates.

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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A rig or intervention vessel with riser for coiled tubing cleanout was unavailable for approximately a year. The operator requested innovative solutions and selected a unique riserless light well intervention consisting of an e-line cleaning tool with a reverse circulating bit and bailer sections to break through the hard-packed debris, vacuum it into the bailers, and retrieve it to surface.

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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Available logging and perforating technologies were reviewed and evaluated which included Drill Pipe, Coiled Tubing and e-line options. Tubing Conveyed Perforating (TCP), using a combination of Drill Pipe (DP) / tubing string and Coiled Tubing (CT) perforating technologies was considered as part of the evaluation, but the selected method was an e-line well tractor to deploy the logging tool and perforating assembly. Using tractor conveyance saved significant time and associated rig costs with respect to pipe conveyance to perforate this new well. In so doing it also set two, Latin American, regional records for tractor-conveyed tools in one well.

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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Recently, a series of e-line milling operations were performed to remove repeater-sub and ball-seat restrictions in oil producing horizontal wellbores located in Southeast Saskatchewan. The low pressure reservoirs favored intervention technologies that did not require excessive hydrostatic head. Operators have traditionally used nitrogen mixed with water to prevent damage to the reservoir and to maintain circulation; however, this reduces the amount of torque that can be achieved at the bit, and causes stalling and sticking issues.

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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With these characteristics, the operator did not have to address any of the operational and administrative concerns or costs associated with conventional explosive methods such as: extra procedures, time for safe handling, limited vessel traffic, added security, nor additional operational rig time to dress off the flaired cut end before removal.

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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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 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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In an effort to reduce completion costs and minimize CT use, reserving it for only those tasks that absolutely require it, an operator in the Eagle Ford shale decided to investigate alternative technologies for performing post-cementing well cleanup and toe perforating. The operator was aware of an electric-line (e-line), tractor-conveyed cleaning tool with a reverse circulating bit (RCB) that was being used for drifting and cleanout runs. These tools have been used successfully in Norway and Canada, offshore and on land, to clean out cement stringers and other debris from the wellbore, ensuring a clear path for the toe perforations, which follow. With these tasks successfully completed, the pumping down of frac plugs can be accomplished with confidence during multi-stage completion operations.

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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Past attempts to remove the sleeve with conventional methods were unsuccessful. Those attempts included slickline, coiled tubing (CT), and pulling 110,000 lbf with a workover rig using a through-tubing work string. At the time, the sleeve did not interfere with production, so it was left in the well. However, an unrelated tubing leak developed below the stuck frac sleeve. The well had to be shut in until the frac sleeve could be pulled to allow installation of a tubing patch.

Milling the frac sleeve with coiled tubing or replacing the entire tubing string with a workover rig was considered. However, cost and time could be reduced if the frac sleeve could be milled with an electric-line (e-line) conveyed bottomhole assembly (BHA).

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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To navigate the narrow inside diameter (ID) of production tubing, the plug is run deflated; it is inflated at the desired measured depth to create a barrier during workover operations; and then, when work is complete, deflated again for removal.

To protect the inflatable plug—especially its retrieval mechanism—from falling-debris damage during workover, a common practice is to use a protective fill, such as sand or proppant, on top of the plug. Of course, before the plug can be removed, both the debris and the sand must first be removed. Traditionally a slickline bailer is used to remove the debris and sand up to the top of the plug’s external fishing neck. Then coiled tubing (CT) is used to wash away enough of the remaining sand from around the neck of the plug so that a slickline-deployed retrieving tool can latch onto the plug and retrieve it.

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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Coiled tubing (CT) is a well-proven method to access these long, horizontal wells and is used frequently in the completion to perform matrix stimulation. However, it faces certain limitations that can prevent it from accessing the full TD in these extended reach wells. Reach capabilities depend on the size of the reel, the diameter of the coil, the material of the coil, the completion size and the wellbore geometry, to name a few. In order to extend the reach length of CT, hydraulic tractors in various sizes have successfully been run to pull the CT to TD in Manifa field. The CT tractor eliminates the aforementioned limitations by pulling the CT with forces of up to 4,000 lbs and removing the issues relating to helical buckling.

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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As a result, job complexity often leads to outright failure or an exponential increase in time to accomplish what would be a routine task in a normal environment. Often the best route to success and efficiency in these conditions is proven technologies and strategies. For over 80 years, e-line conveyance and tools have been refined and improved to become a very reliable means of data gathering and workovers, such as plug setting, debris removal, hardware milling, pipe recovery and so forth.

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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The operator needed to plug and perforate 26 zones from max depth at 21,740 ft up to the upper perforations at 11,830 ft to get the well on line swiftly. However, a 3.5 in. patch at 11,689 ft–11,709 ft meant the ID of the 4 1/2 in., 11.6# casing string was restricted, and thus the 4 1/2 in. plug could not be pumped in safely. Pumping the plug could cause it to set prematurely or get pumped off causing an expensive fishing job. Rig workover was deemed too time consuming due to the number of runs necessary and as a 2 in. coiled tubing (CT) string would only be able to reach about 17,000 ft, this option would have left 10 zones unperforated. To further complicate matters, spring thaw road weight restrictions were in place and the project was already over budget and behind schedule.

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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The industry’s definition for ‘high temperature’ ranges from 300°F to 400°F. Working in this environment requires careful preparation, as well as proven, reliable service providers and equipment. Established electric line tractor-based technologies running on AC power, as well as DC equipment have proven their application in these harsh and unforgiving environments. They offer additional benefits like reduced personnel and less heavy lifting, making these technologies inherently safer.

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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Whether it is of the surface-controlled (SC), subsurface-controlled (SSC), wireline-retrievable (WR), tubing-retrievable (TR), ball check, or flapper valve variety, subsurface safety valves can easily be damaged during through-tubing (wireline, coiled tubing [CT], etc.) deployment through the valve if steps, such as equalization before opening, slowing toolstring running speed, etc., are not taken to properly safeguard valve integrity. A problem that could occur during these deployments, specifically in reference to the SSV flapper-type valve, is shearing of the hinge pin on which the valve flapper rotates, allowing the flapper to “float” in a cavity directly below its rotation point, creating an effective downhole obstruction.

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.

Three benefits can instantly be noted from the developments and lessons learned. First, the toolstring solutions could be used for obstruction isolation of many varieties. Second, this rigless operation is part of the ongoing efforts in the Gulf of Mexico and elsewhere in the world to intervene in wells in the most economically feasible, least hazardous, and most expedited manner. Lastly, the intervention means employed here incorporates toolstring components readily available on the market. Lead time and operational use are minimized, and rig campaign schedules can be maintained almost without delay.

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To address these challenges, a novel design was introduced, effectively creating an expandable metal, sleeve-type annular barrier that allows cementless completions and effective zonal isolation. The design of the new annular barriers, assembled on a full bore liner, minimizes the running outside diameter (OD) whilst delivering a high differential pressure seal even within a washed out hole.

The qualification process was designed to meet the International Organization for Standardization ISO14310 V3 standard and to simulate the life cycle of the packer during acid stimulation and later-life water management.

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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This paper will share the knowledge gained from a world’s first operation, demonstrating that hydrates can be milled using electric line (e-line) tools. The operation was performed from a Vessel Fit for Purpose (VFFP) as a Riserless Light Well Intervention (RLWI) operation in the North Sea, offshore UK.

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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The operation was a success and more such operations have been run. This paper will present the lessons learned from these operations, as well as discuss the applicability and efficiency gains of e-line, tractor-based conveyance. Best practice consideration will be proposed for future plug & perf operations in horizontal wells.

Several challenges led to the initial decision to select the tractor-conveyed solution. Poor road conditions made the logistics of heavy equipment difficult, and coupled with severe time constraints and strict budget considerations the e-line solution became the preferred choice. This decision enabled the operator to get this USD 9M asset on production in a timely manner.

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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This paper will share the lessons learned and best practices derived from 15 years of OH tractoring operations. It will examine the track record of OH conveyance in several countries, including operations in the Middle East and in unconventional wells in the USA, describe the success factors, review rock strength issues and compare the risks of tractor-based conveyance to drill pipe conveyance.

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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One major challenge in performing a plug-and-perf completion on the extended-reach lateral in this case study was that the toe of the well extended further than could be cost-effectively cleaned out with a service rig or coiled tubing. Therefore, large-bore cast iron permanent frac plugs, which are designed to be produced through, were used to isolate frac stages in the toe. Before pumping a subsequent stage, a dissolvable ball was seated on the plug to isolate the previously fractured stages.

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.

Find the full paper at https://www.onepetro.org/