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Collaborating Authors
Well Completion
Abstract Coiled tubing (CT) cleanout operations in New Zealand require extremely detailed planning and execution. When significant proppant is left in the well as a result of hydraulic fracture screenout, customer concern requires ensuring that hydrocarbons are not produced and returned to temporary surface equipment during the cleanout operation. During solids removal, the solid rate of return at surface must be limited to prevent erosion of flowback equipment. To reduce operator uncertainty during this process, modeling with a solids transport simulator, along with a real-time downhole communication system, was used to provide real-time pressure data at downhole conditions. To provide an engineered cleanout, one of the modeling goals was to determine the predicted maximum solids return rates so the flowback choke integrity was maintained. Real-time monitoring of downhole information during the operation enabled a hydrostatic pressure calculation based on true vertical depth (TVD) to determine the equivalent circulation density (ECD) of the fluid column. Determining the ECD enabled the estimation of the solids concentration in the fluid returned via the annulus (tubing/CT). Consequently, an increase of hydrostatic pressure (relative to water) at downhole conditions correlated to an increase of solids concentration in the fluid column during the cleanout phase. By monitoring this increase in the ECD during the sand cleanout, the operator had an early indication of an increase in solids concentration in the fluid returns. This knowledge enabled the operator to manage the flowback operation at the surface, without exceeding surface equipment specifications. The process met customer requirements for enhanced proppant cleanout operations. This paper details the background of the operator cleanout requirements, the pre-job design analysis used, the job parameters during execution, and the incorporated improvements made compared with conventional well interventions.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (3 more...)
Abstract This paper examines techniques necessary to fish coiled tubing (CT) with internal weld seams in a live well environment without back pressure valves (BPVs) using a hydraulic workover unit (HWO). The challenges of placing barriers in internal seamed CT verses using the slip and shear method is addressed. The discussed onshore operation was completed August 2013 in North America. Using the techniques described, a 14,000-ft (4267 m) 2-in. (50.8-mm) CT fish was successfully removed from a well with an average surface pressure of 5,500 psi. This was achieved by first opening the blind rams, snubbing in, and dressing off the CT fish. Next, the CT fish was latched with an overshot and a pull test was performed, pressure was equalized, and the slip and pipe rams were opened. Following, the CT fish was picked up and moved to a desired location in the blowout preventer (BOP) stack (approximately 51 ft 4 in.). The slip rams were then closed and a weight check was performed. The pipe rams and inverted rams were then closed. The CT fish was shear/cut, the pipe was picked up and the blind rams were closed. This was concluded by laying down the fish and the process was repeated 276 times with an average cut of 50 ft. The HWO fishing procedures consisted of 541 hours without any health, safety, or environment (HSE) incidents, accidents, injuries, or job failures.
- Well Drilling > Drilling Equipment > Well control equipment (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Mechanical defects are incurred routinely in the coiled tubing (CT), and can have a first order influence on fatigue crack development. Failures of the CT can significantly impact operations and in a worst case can lead to the loss of a well. This paper developed the new non-contact CT assessment system with the new inspection method, which is suitable for the detection in-service and new coiled tubing. This paper proposes a new micro-magnetic detection technology for rapid detection in-service coiled tubing. The method is based on a high precision fluxgate sensor that measures the magnetic field changes in the geomagnetic field, without needing external magnetization and demagnetization to identify the location of the defect. We use iron base amorphous alloy to make the smallerfluxgate sensor. This method is effective in assessing the early damage and developed defects. Eddy current lift-off technique is used for the gap measurement and design ovality detection algorithm. The ovality is obtained through calculation of the software. The optical distance measure sensor measures down to the length of the coiled tubing. The test tool is designed and produced and can be installed and removed fast. 2D imaging is achieved and features the shape of defect. This system is available for various CT diameters. Data acquisition software real-time display flaws curve and the detection imaging. The tool can realize non-contact, measure wall thickness, diameter, ovality, and can fast nondestructively test in-service coiled tubing. The resolution of the testing instrument is 1 mm. It is easy-operating and time-saving, and has the maximum measuring velocity of up to several meters per second. Detection results are close to accurate location of prefabricated corrosion defects through inspection CT test sample. However, as a comparatively new test method, it still has a large room to be improved. Micro-magnetic measurement signals are weak, and its amplitude is small and unperturbed by the environment. Inspection of in-service coiled tubing still need to improve and develop.
Improving Well-Work Efficiency and Mitigating Risk Exposure by Utilizing Digital Slickline in the Kuparuk River Unit, North Slope, Alaska
Wiese, T.. (ConocoPhillips Alaska Inc) | Yoakum, V.. (ConocoPhillips Alaska Inc) | O'Dell, B.. (ConocoPhillips Alaska Inc) | Loov, R.. (Schlumberger) | Milazzo, B.. (Schlumberger) | Nemec, J.. (Schlumberger)
Abstract With approximately 1,200 wells and 47 developed drill sites in the Kuparuk River unit (KRU), North Slope, Alaska, a variety of well intervention services are required to keep wells in safe operating condition. Historically, conventional slickline and electric line services have performed a large portion of the non-rig diagnostics and repairs. With slickline operations generally limited to mechanical interventions and electric line required for depth-critical logging operations, both services are commonly required to complete a given well-work program. Because the intervention units are a shared resource, and the well-work schedule is priority based, there are often delays between slickline operations and the electric line diagnostics that follow. Digital slickline services are being used in the KRU to improve overall well-work efficiency by completing intervention programs without the need for separate slickline and electric line services. Digital slickline services are being used to mechanically prepare wells for diagnostics, perform logging operations that would normally require electric line, and ready wells for repair without the need of additional service units. The enhancements linked to incorporating real-time surface readout data while performing mechanical interventions has reduced uncertainty and provided information for effective workover decisions. Using digital slickline technology has also mitigated risk exposure, as fewer crew hours are spent traveling and handling surface equipment. Examples of intervention work that have been completed with digital slickline services in the KRU include setting retrievable tubing patches, well integrity diagnostics and conventional slickline operations. The operations in the KRU have provided lessons learned and an understanding of the challenges associated with the technology.
- Production and Well Operations > Well Intervention (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.94)
- Production and Well Operations > Artificial Lift Systems > Gas lift (0.70)
- Well Completion > Completion Installation and Operations > Perforating (0.69)
Abstract Well intervention is a critical aspect of managing brownfield assets as operators seek to optimize hydrocarbon recovery and perform maintenance work to ensure wellbore integrity. The costs of traditional workover methods and technologies, specifically in an offshore environment, can create economic barriers to the number and types of interventions that are completed in a declining field. Light well intervention technology is considered a cost effective alternative to performing rig interventions on aging subsea wells. Operators and service providers continually seek to develop technologies and procedures that mitigate economic risk when working on these mature production wellbores. One revolution that has been in development for the past few decades involves using conventional slickline and electric line to perform light well interventions without the requirement of an offshore drilling or workover rig. This process uses a light well intervention vessel (LWIV) complete with a moonpool located mid-deck for open-sea access, a riserless pressure control package typically involving remotely operated vehicles (ROVs), and a combination of conventional slickline and electric line intervention packages. Interventions using this technology adaptation were primarily developed for the North Sea and Gulf of Mexico regions and have been widely used in those regions. However, after several years of planning, the technology has now been used for the first time to rework several wells for an operator off the east coast of Canada. Light, riserless, well intervention technologies have been deployed in three individual wellbores offshore Canada. Multiple services were required in each of these three wellbores. Conventional slickline operations were run to prepare each of wellbores, with the retrieval of crown plugs and conventional drift runs. Operations then switched to electric line services to perform diagnostic runs followed by remedial intervention services. Once the electric line services were completed, slickline services were used for safety valve isolations and gas lift remedial work and then returning the newly configured wells back to production mode. The use of the LWIV provided the operator with an efficient intervention technique to evaluate and potentially improve well performance.
- North America > Canada (0.91)
- North America > United States > Texas (0.29)
- Europe > United Kingdom > North Sea (0.24)
- (4 more...)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (3 more...)
Optimization of Matrix Acidizing With Fluids Diversion in Real-Time Using Distributed Temperature Sensing and Coiled Tubing
Medina, Eber (Pinnacle, a Halliburton Service) | Sierra, Jose (Pinnacle, a Halliburton Service) | Garcia, Alexis (Halliburton, Boots & Coots) | Gleaves, Jorge (Halliburton, Boots & Coots) | Mendez, Josue (PEMEX)
Abstract Carbonate formations in southern Mexico are commonly stimulated using matrix acidizing treatments to increase well productivity by removing near-wellbore (NWB) damage. Such damage can be attributed to accumulation of paraffin and asphaltene deposits during the productive life of the well and, in other scenarios, to fluid invasion while performing workover activities. A high perforation length across the reservoir to increase production from this highly natural-fractured carbonate has been the completion option for several years. The use of diverters is a common practice in the Bellota-Jujo field when multiple intervals are open. However, the effectiveness of the diversion had not been evaluated in real-time. A distributed temperature sensing (DTS) option was deployed to measure temperature profiles along coiled tubing (CT) equipped with an internal fiber-optic cable and a modular bottomhole assembly (BHA) consisting of pressure, temperature, and depth correlation sensors. This option was selected to monitor the treatment and help make real-time decisions. This real-time fiber-optic (RTFO) integrated system used during the stimulation allowed identification of zones with higher and lower admission. Based on this information, decisions were made during the pumping schedule, modifying volumes and rates of diverting agents and stimulation fluids being pumped through the annular space between production tubing and CT, also pumping through CT using a fluidic oscillating tool optimizing the diversion process during different stages of the intervention. This system enabled the operator to correlate depth and continuously monitor the temperature changes across the producing zone of the well. The findings and results of the stimulation treatment with this technique used in the well, Bricol 2DL, are presented in addition to the thermal analysis of the DTS profiles. The use of the RTFO integrated system during a matrix stimulation treatment in a carbonate formation with high permeability contributed to successfully evaluating the effectiveness of the fluids and mechanical diversion resulting in a well productivity increase of 60%, thus keeping the well in production since the treatment was performed.
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Well Completion > Acidizing (1.00)
- (2 more...)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.61)
Successful Offshore Coiled tubing Well Intervention in Mega-Reach Wells in the Russian Caspian: A 4-Well Case Study
Burdin, K.. (Schlumberger) | Mazitov, R.. (Schlumberger) | Bravkov, P.. (Schlumberger) | Lobov, M.. (Schlumberger) | Kichigin, A.. (Schlumberger) | Stepanov, V.. (Schlumberger) | Eliseev, D.. (Lukoil-Nizhnevolskneft) | Zemchihin, A.. (Lukoil-Nizhnevolskneft) | Byakov, A.. (Lukoil-Nizhnevolskneft)
Abstract Korchagin oilfield is located in the northern part of the Caspian Sea. Drilled wells are mega-reach (MD/TVD ratio greater than 3.0) with measured total depth (MD) up to 23,622 ft [7,200 m] and vertical depth of only 5,118 ft [1,560 m]. This presented a great challenge for coiled tubing (CT) well intervention even with the help of state-of-the-art hydraulic tractors. Limited working area, weight restrictions, challenging well geometry, completion features and lack of experience in offshore CT operations in the North Caspian Sea, required complex pre-job activities to optimize job design, select proper downhole tools and prepare a robust layout plan. This paper will illustrate the project preparation challenges, on-the-job troubleshooting and workflow, supported by the well case studies and results from the first CT operation in Northern Caspian Offshore. Lessons learned from the project, where all defined objectives were achieved with zero HSE (health, safety and environment) incidents, were also captured to assist in future campaigns with similar operational environment.
- North America > United States (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- (3 more...)
Abstract The oil industry in the UAE is striving to advance both onshore and offshore operations to address technological challenges that will allow for increased oil production in a safe and efficient manner. Offshore, artificial islands are being built for the purpose of accommodating up to 300 wellheads on a single island, with the wells themselves comprising multiple, extended-reach horizontal laterals. These ground breaking projects present new and exciting challenges for coiled tubing (CT) interventions, which require extensive planning and the use of innovative technologies. Specific challenges were identified during the design phase of intervening on a trilateral, extended reach well and applying several technologies enabled us to overcome these challenges to allow successful execution of a stimulation treatment on the well. Techniques used included accessibility modelling and CT string selection to achieve maximum reach. The methodology used and the testing conducted were designed to ensure that the multicomponent CT bottomhole assembly (BHA) allowed for selective engagement of each lateral and subsequent horizontal accessibility of each extended-reach lateral. Operations were performed in the context of the completion restrictions, diameter of the openhole and cased-hole laterals, and the requirement to pump large volume acid treatments. Each of these factors added a layer of complexity to the final CT BHA selection and setup, which had to operate within a limited range of activation pressures and rates. Finally, the lessons learned during the execution phase have been captured and recommendations formulated for moving forward with CT intervention in similar types of multilateral and extended reach wells. These lessons contribute to subsequent studies of maximum reservoir contact wells and form the basis of future development and intervention plans for the offshore and islands projects in the UAE.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations (1.00)
Abstract More operators are seeing the production benefits of targeted horizontal annular fracturing. The most active method of annular fracturing in the USA involves ported sleeves installed with the completion and activated via an isolation packer. Initial operations were in lateral lengths of 2,000 to 3,000 ft. However, current operations are planned for accessing up to 10,000 ft laterals. Increasing lateral length results in the traditional access challenges faced by all coiled tubing (CT) operations. The traditional method of lubricant use is the primary option due to its simplicity. The second method is to use fluid hammer tools (FHT). These are industry standard for improving efficiency in composite plug milling operations, but their use in genuine extended-reach operations is not as broad. This paper briefly covers historical ported annular fracturing operations and the various methods of achieving increased lateral reach. Results from four wells with lateral reach of 7,200 to 10,277 ft are detailed in the paper. The balance of the paper details operational results and optimization from several extended-reach wells. Detailed lateral reach modelling was performed prior to all operations. This permitted the determination of the number of expected stages that would require the use of lubricant in the fracture treatment flush. Given that residual lubricant in the completion is removed by the erosion effects of the proppant in the fracture treatment, each stage would require an additional fluid flush. This gives an opportunity to modify the lubricant concentration, type, and volume in the flush. Before using fluid hammer tools (FHT) for setting the isolation packer, laboratory testing was performed to ensure the bottom-hole assembly (BHA) system compatibility. The lubricant testing and initial field results were reported previously (Livescu and Craig 2014; Livescu et al. 2014a,b). This paper provides operators with sufficient case histories of the planned use of an advanced lubricant in genuine extended-reach wells in real life situations. This knowledge can improve operator confidence in drilling longer laterals for predictable access for annular fracturing operations.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
Abstract The use of pressure-activated toe valves in a completion string is yet another innovative approach to completing a horizontal well. This technology eliminates the need for perforating guns prior to a multi-stage hydraulic fracturing (frac) operation. Subsequently, the operator can greatly reduce costs when the need for coiled tubing (CT), wireline (WL), or workover rig (WOR) is no longer needed on location to convey perforating guns. However, when injection rate through the toe valve is not adequate for wireline pump-down operations, or the toe valve fails to open at all, the operator must revert back to conventional methods of perforating in order to achieve injection into the well and begin the frac operation. These failures immediately negate any of the cost savings the toe valves were designed to provide. This paper will review cost effective solutions, through the use of abrasive perforating, to quickly and efficiently perforate the toe stage and minimize non-productive time (NPT). Most often, adequate pump-down rate is not achieved through the toe valve when debris or cement is lying across the tool, preventing it from opening or plugging off the ports. Prior to perforating, a motor and bit run is common to verify that the well is clean down to plug back total depth (PBTD). This requires a minimum of two round trips with coiled tubing or a workover rig. Two different methods of abrasive perforating have been used to benefit both conventional plug and perforate and frac sleeve completions (sometimes referred to as “baffles”). Several case histories will be presented to explain how a single trip in hole, utilizing a motor BHA and abrasive perforator in tandem to clean and perforate the toe stage, can minimize costs compared to several round trips using the conventional method with perforating guns. Additionally, we will explore an innovative approach to abrasively perforate the toe stage through frac sleeves where minimal ID's pose a problem with conventional methods of perforating. Abrasive perforating technology, in conjunction with other innovative tools, adds a wide range of flexibility for today's complex horizontal wells. Utilizing this technology, problems such as toe valve failures can be addressed in a safe and cost effective manner.
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)