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Results
Abstract This paper describes a recent Directional Coiled Tubing Drilling (DCTD) job that was completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified adjacent to a recently drilled, vertical well using a lateral sidetrack. The target thickness was around 15ft so accurate depth control was critical. It was also considered essential that the entire reservoir section be drilled underbalanced to minimise formation damage. The challenge was to deliver a productive horizontal sidetrack in an effective and cost-efficient manner. The field development strategy required costs to be kept to a minimum, but the use of high-tech equipment was essential to delivering the production improvements. A 3.2 inch DCTD Bottom Hole Assembly (BHA) and a specialised DCTD engineering software package were enabling technologies. A multi-disciplinary approach was adopted to plan and execute the sidetrack. This approach required inputs to the planning process from all stages in delivering the well, which included: 3D seismic, well trajectory planning, drilling engineering, completions. This project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well, thereby validating the technology and multi-disciplinary approach of the team. The lessons learned from this operation can be used to optimise the planning of future wells and maximise the value of re-entering marginal wells and fields.
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (7 more...)
Abstract This paper presents a case history where the entire lateral of a producing well was restimulated in a single trip using a novel cost-effective intervention tool designed to provide discrete stage isolation. Lessons learned and job details are discussed and compared with other restimulation methods used in the area. The new method is based on a novel straddle packer system that uses two mechanically-activated sealing elements—as opposed to conventional sealing cups—to overcome wear and bottomhole pressure limitations found in traditional straddle systems. The novel stage isolation system enables higher flow rates and pressure differentials as well as a larger number of stages, therefore reducing the amount of trips in the well required to complete typical refracturing operations. A comparison will be made to conventional refracturing methods based on intervention tools. As a bonus, pressure data gathered during the treatment indicating limited coverage of the primary fracturing job will be discussed. The case study provides the framework to describe how the novel technology enables multiple treatments in a single trip in the horizontal well, therefore reducing the operational time, resources, and cost required to complete a restimulation job. The paper will show how the use of the novel technology reduced operational time by 30% compared to other methods, and enabled the operator to treat a horizontal well with full mechanical isolation in a manner not previously available. In addition, the paper will discuss pressure data gathered during the deployment that suggests limited cluster efficiency on the primary fracturing operation. The results of the paper are relevant because they provide a new cost-effective alternative to conventional restimulation systems that was not available in the past due to inherent technology limitations of existing straddle packer systems. This is important because: (1) the technology described in the paper overcomes these limitations for both vertical and horizontal wells, (2) more refracturing operations are executed by blindly pumping treatments from surface into a full lateral with open perforations without an effective way to mechanically isolate target zones, and (3) the technology may shed additional light on the discussion of cluster efficiency during primary stimulation operations.
- North America > United States > Texas (0.83)
- North America > United States > New Mexico (0.51)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
- Well Completion > Hydraulic Fracturing > Re-fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Abstract One of the biggest sources of dry gas in the world is located in the Middle East. Every project in this field faces challenges that require good-quality downhole data to be properly addressed. In the present case, the risks involved when milling inside a 7-in. monobore completion with 2 3/8-in. coiled tubing (CT) in gas conditions motivated the use of a state-of-the-art bottomhole assembly capable of providing real-time downhole parameters to operate the mill both safely and efficiently. The project, which included an extensive integration between the CT and downhole tools providers, consisted of various innovative stages. First, a stimulation vessel was used to deliver enough pumping capacity to inject the fiber optics carrier into the CT pipe located on the rig. Then, a customized surface acquisition system was implemented to comply with strict zoning requirements, and protocols and hardware were designed for communication between the software of all parties to transmit downhole and surface data in real time. Finally, a thorough analysis was conducted to identify the safest method to deploy and run the milling tools to achieve the job objective. This successful milling operation in 7-in. monobore completion and gas conditions was the result of several achievements made throughout the project. The real-time telemetry system served rugged downhole tools, which were being used under these conditions for the first time. They provided downhole torque, pressure (both inside and outside of the milling tool), depth control variables, and weight on bit to the CT control cabin, where the CT operator and milling tool specialist effectively interpreted the data and took actions to mill 100 ft of cement and a drillable plug in three runs. The critical operation to inject the fiber optic carrier in the 2 3/8-in. CT pipe required incorporating extra measurement equipment such as flowmeters and pressure gauges in the system to closely check pumping parameters, which will now be utilized as a standard for other such interventions worldwide. Finally, the design of the communication interface between the software of the different companies proved to be effective at compiling all the critical parameters and became a benchmark for future operations. Even though well conditions changed during the operation, the job was executed safely based on a detailed decision tree that incorporated several contingencies. Each action was reviewed by all parties based mainly on the downhole data recorded, which allowed getting the best out of the milling bottomhole assembly and the expertise incorporated in the project. This work shares a vast amount of information collected during the design and execution of the project. The significant effort performed by all the parties to integrate their equipment and technology are detailed within the context of the job's objectives and can be used as a reference by other locations. Contingency plans are also detailed, as well as safety measures and lessons learned.
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas (0.28)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract "Run in hole", "stop CT", "pickup", "drop pumps"… All common commands heard in the control cab during a coiled tubing plug drillout (CTDO). What drives the decision making process and what information has been processed to arrive at such a conclusion? During a coiled tubing (CT) operation, many parameters are being acquired including pump rate, pressures, weights and speeds, and the success of the operation relies on how the supervisory personnel interpret this data and advise on next steps. At the end of the job, if lucky, this crucial data is archived in the catacombs of the well file on some network server. What if instead, this information was analyzed to detail the operation, develop performance metrics to help understand why the results were what they were, and ultimately provide guidance for future operations? This paper discusses an algorithm developed to support analysis and a philosophy of job review that has been utilized to robustly process a rich, continuous and widely available CTDO data set.
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Management (1.00)
Real-Time Fiber Optic Integrated System Provides Precision and Confidence in a Coiled-Tubing-Conveyed Perforating Operation: A Case Study from the Eastern Foothills in Colombia
Vera, Vanessa (Halliburton) | Torres, Carlos A. (Halliburton) | Delgado, Eduardo (Halliburton) | Pacheco, Carlos (Halliburton) | Sampayo, David (Halliburton) | Higuera, Josue (Equion Energia Limited) | Torres, Monica (Equion Energia Limited)
Abstract Underbalanced perforating with conventional cable operations involves several risks associated with well tortuosity, cable tension capacity, gun lifting, and the capability of achieving the optimum underbalance for effective tunnel cleanup (Graeme et al. 2008). Because of these risks, an operator in Colombia elected to perform a perforating operation using a coiled tubing (CT) real-time fiber optic (RTFO) integrated system in a newly drilled development well. CT-conveyed perforating is ideal for this type of wellbore. To achieve the proper underbalance and depth correlation to perforate the target interval, an RTFO CT system provides the most accurate and reliable depth correlation process, in addition to real-time pressure and temperature monitoring inside the CT and the outer annulus. Using the RTFO CT system, only two runs were necessary to complete the perforating program, in accordance with the operator design, rather than performing an additional run needed for pickling and to generate underbalanced conditions. The use of the RTFO CT system can help to prevent correlation errors resulting from CT elongation. A CT structure was not necessary to deploy the guns based on the finite model analysis that calculates maximum stress and flange bending, including a safety factor. A hydraulic firing head can be used with an RTFO CT system to activate the guns without affecting the integrity of the fiber optics or the downhole sensor tool after detonation. The RTFO CT system enabled the operator to evaluate the reservoir potential. The evaluation results indicated that one of the zones is a low producer, which avoided the pumping of unnecessary nitrogen to induce the specific zone. The use of a downhole pressure sensor enabled the identification of the time at which the guns were detonated. Improvement to the rigup was evidenced and enabled time optimization without affecting the operation. The casing collar locator (CCL), used for depth correlation, was a crucial factor in reducing operational costs because it helped to optimize placement accuracy and gun detonation and to prevent misfiring (Newman 2003). The guns were successfully activated without nonproductive time (NPT) or health, safety, or environmental (HSE) incidents during operations. A successful perforating operation was completed with 4,000 psi underbalance in a new formation using hydraulic detonation with continuous real-time downhole condition monitoring before and after detonation, enabling the operating company to make decisions in real time. This new approach of using an RTFO CT system combined with the hydraulic firing head can be used to perforate new formations in these crucial scenarios (wells with production greater than 20 MMscf/D and zones with continued sand production).
- South America > Colombia (0.61)
- North America > United States > Texas (0.28)
- South America > Colombia > Casanare Department > Pauto Field (0.94)
- South America > Colombia > Casanare Department > Llanos Basin > Cusiana Field > Mirador Formation (0.94)
- South America > Colombia > Casanare Department > Florena Field (0.94)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks (0.93)
Abstract Operators continuously strive to improve the efficiency of well intervention activities, as any time spent on interventions is non-productive time. However, planning and executing an efficient intervention is challenging when downhole conditions or issues are uncertain. The guesswork involved often leads to a trial-and-error process during interventions. Performing diagnostic imaging at the outset of an intervention could break this inefficient cycle, but the techniques commonly used for downhole visualizations, such as video cameras, lead impression blocks and ultrasonic imaging, are not sufficiently reliable. Recently, an X-ray based wireline tool was introduced for providing downhole imaging, regardless of the well fluid. We will present a case study in which this new tool was used to assess the condition of the flapper on a downhole safety valve. The X-ray images showed that the flapper was mobile and verified that an insert downhole safety could potentially be installed. This allowed the operator to eliminate higher-risk and more costly options, and they eventually installed the insert downhole safety valve.
- North America > United States (0.46)
- Europe (0.30)
- Asia (0.28)
- Geophysics > Borehole Geophysics (0.87)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)
- Health & Medicine (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract In the current oil and gas environment, the status quo for completing and perforating wells is being challenged by increased well complexities and extreme cost pressure. In pursuit of increased productivity, improved operational efficiency, and reduced costs, operators and service companies must look at novel approaches to how they complete and perforate wells. Several innovative approaches have been implemented to optimize perforating operations and enable operators to complete wells in a more efficient, cost-effective, and productive manner. Detailed job planning and preparation identified candidate wells with intervals that typically would not be accessible or cost-effective via wireline perforating. Through the introduction of wireline perforating tractors, addressable selective switches, release devices and high-strength cables, the ability to access these wells by wireline and convey ultralong perforating gun strings has pushed the operating envelope. Utilizing job simulation and planning software, optimum perforating configurations can be designed to maximize gun length while ensuring the assembly can reach the target depth, perforate, and either drop the guns intentionally or withstand the perforating shock and return to surface safely with the spent guns. In the last several years, ultralong perforating operations deployed on wireline have become more widespread. These jobs have demonstrated that in specific applications, improved completion efficiency can be achieved over conventional perforating operations without impacting the operational integrity or safety of the operation. A specific area of focus is wireline-deployed perforating that is performed without killing the well. In these cases, innovative solutions have delivered significant cost savings to the operator with improved operational efficiency of the perforating operation as well as the post-perforating cleanup.
- Europe (0.74)
- North America > Mexico (0.48)
Abstract A North Sea well was drilled and completed as a sidetrack with a 4 ½" liner set using open-hole sand screens (2x12m) in the toe and swell packers for isolating the production intervals. Due to poor productivity and injectivity, the well had been shut-in. It was suspected that the completed interval had been filled by particles (mainly barite) from different mud types that were suspended or settled in the completion fluid placed both inside and outside the screens. Due to multiple uncertainties regarding the fill, it was desirable to perform a drift run to determine the hold-up depth (HUD) and collect samples there. The operator decided to apply a modified version of a known electric-line (e-line) suction tool. 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. In a subsequent run a newly developed, e-line powered, downhole jetting tool would be deployed to convey the chemicals to target depth and flush the screens using the tool's jetting nozzles. The performance of both the modified suction tool and the new downhole jetting tool were successful in accomplishing both challenges in this operation. They managed to determine the HUD and collect samples of both solids and liquids. Then, on a subsequent run, the jetting tool conveyed chemicals down to the screen and cleaned them with a high pressure jet opening the screens to flow. This paper will review the procedural details of this operation, which constitutes the first job performed with such e-line powered tools; tools which enable accomplishing the objectives without injection or production required on the well. Two important benefits are demonstrated: an increased operational efficiency for collecting samples and a new method to perform down-hole, high pressure injection without the need to mobilize surface pumping equipment and fluids.
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- Europe > North Sea (0.25)
- (2 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.81)
- Well Completion > Sand Control > Screen selection (0.49)
Abstract An Angolan operator needed to perform a coiled tubing (CT) acid micro-wash stimulation on a subsea sand screen completion in order to improve production. The CT simulation showed that the coil would not reach the objective, which was the bottom screen, even with friction reducers, without the assistance of additional forces. The operator chose to deploy a downhole tractor to provide a pulling force to achieve the desired depth. However, this horizontal well had debris which prevented reaching the objective and required changing strategies to accomplish the job. A downhole tractor can be powered by pumping fluids down the coiled tubing, driving a turbine which powers the hydraulic systems in the tractor. The drive fluid will then pass through the tractor and out the bottom of the tool to provide the treatment. Surface testing is performed prior to the job to determine at which pumping rate the tractor will be engaged and disengaged. This testing is performed with and without treating nozzles to gauge tool performance and expected pumping rates for tractoring and treating. In this Angolan operation two runs were required to reach the bottom screen due to debris fill in the completion preventing passage during the first run. On the second run the CT provider used a nozzle that could both clean the well and treat in the same run. This operation demonstrates the effectiveness of using CT tractors, which are under-utilized in the industry, to achieve extended reach beyond the normal CT range. It also demonstrates the quick mobilization and same day deployment, as well as problem solving that can occur when service companies (CT provider and tractor provider) work closely together.
- North America > United States (0.47)
- Africa > Angola (0.41)
Abstract Although all plug-and-perf systems require frac plugs to isolate zones in the wellbore, there are alternative approaches to hydraulic fracturing using the plug-and-perf method. The availability of dissolvable frac plugs enables operators to weigh the cost and risk of using non-dissolvable frac plugs against the cost and risk of dissolvable frac plugs. This paper analyzes the cost and value of these varying fracturing approaches for applications in North America in traditional and extended reach wellbores. Frac plugs must be removed from the wellbore before production begins. Non-dissolving frac plugs are removed by milling; this step increases the cost of the overall completion and can sometimes lead to production delays. Risks associated with the milling operation include becoming stuck in the wellbore, damage from the milling debris, and the requirement for larger amounts of water. Consequently, the cost of milling is an added cost to non-dissolvable fracture products. Dissolvable solutions, however, have a larger upfront cost because dissolvable materials are more expensive than non-dissolving materials. There is a trade-off between the larger upfront costs of dissolvable fracturing technology and the milling costs and risks of non-dissolvable fracturing technology. This trade-off depends on the number of stages, wellbore fluids, formation parameters, operational costs, cost of delayed production, and the operator's willingness to accept risk. The trade-offs also vary between operators and regional geographies. The costs of non-dissolving frac plugs are acquired from historical data and include tools, milling, materials, and the time delay to production, as well as the weighted risk of potential formation damage and lost time incidents. The costs of dissolvable fracture plugs are estimated from the experience in the use of this dissolvable technology. These dissolvable costs are modeled for a typical wellbore in North America for both full wellbore and extended reach laterals. The result is an estimate of the trade-off between cost and risk for non-dissolving and dissolvable fracture technology. A dissolvable frac plug adds both cost and value to fracturing operations in the unconventional market. A key advantage for dissolvable frac plugs is the ability to fracture longer extended reach wellbores. This paper enables the operator to balance the tool cost with the value of eliminating operational mill-out steps, overall cost of the completion, risk associated with the completion, and the time necessary to begin production.