This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204403, “Development of Low-Force Shear Blades for High-Strength Coiled Tubing,” by Scott Sherman, Nexus Energy Technologies, prepared for the 2021 SPE/ICoTA Virtual Well Intervention Conference, 22–25 March. The paper has not been peer reviewed. As coiled tubing (CT) grades have evolved during the past 20 years and wall thicknesses have increased, the resulting force required to shear coil has more than doubled. An industry need existed to develop a shear blade for blowout preventers (BOPs) that could cut high-strength CT using legacy pressure-control equipment already in use. The paper describes the iterative process of development of a novel shear blade able to cut high-strength CT with 50% of the normal shear force. Objective The objective of the work detailed in the complete paper was to develop a novel CT-shearing system capable of cutting high-strength heavy-wall CT with reduced hydraulic pressures. Considering that CT will continue to evolve in terms of yield strength, the goal of the study was to future-proof BOPs wherever possible to protect customers from the liability of obsolete equipment. The authors write that, ultimately, BOPs will need to cut 175-grade CT strings with a 7-mm wall thickness with 103 MPa of wellbore pressure and less than 17.2 MPa hydraulic pressure. Development Process Initially, the following five options were considered: - Larger-diameter cylinders. This seemingly simple option, which would generate more shear force, was ruled out because the implementation would not be backward-compatible with existing well-control equipment and the larger cylinder volume would result in slower cycle times. - Boosted actuators. These could double shear force while maintaining piston diameter. While this solution is simple, theoretically, these actuators require twice as much hydraulic fluid from the accumulator to function. This results in a closing time that is nearly double that of a nonboosted actuator. - Pressure-balanced actuators. With this option, hydraulic forces would not need to overcome the forces related to wellbore pressure in addition to providing sufficient force to shear CT. These actuators do increase the amount of shear force available to cut CT when used on high-pressure wells. However, they increase complexity, cost, and weight and could result in trapped wellbore fluids within the actuator that could lead to corrosion-related issues. - Increasing hydraulic pressure to a given set of rams using a pressure multiplier for the shear rams or a similar system. This solution was deemed unsuitable because the hydraulics of most BOPs are designed for 150% of their rated pressure. Doubling the hydraulic pressure available to the BOP could damage the hydraulic cylinders and associated actuators, resulting in a catastrophic well-control situation. - Modifying shear blade geometry to reduce the shear force needed to cut CT using existing equipment. This was selected as the most-logical approach because the modified shear blades could be retrofitted into existing BOPs. Furthermore, this solution would not require modification to existing wellsite equipment such as accumulator skids and would not increase the weight or size of the BOP stack.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 204417, “Avoiding Erosion: Best Practices for Coiled Tubing Annular Fracturing Operations,” by Kaveh Yekta, SPE, and Jamie Fenwick, SPE, Essential Energy Services, and Kevin Elliott, SPE, NOV, et al., prepared for the 2021 SPE/ICoTA Virtual Well Intervention Conference, 22–25 March. The paper has not been peer reviewed. The onset of erosion of coiled tubing (CT) strings may be difficult to predict in annular fracturing operations. The complete paper describes a methodology of verifying that CT strings have not been subject to erosion caused by annular fracturing operations. An exploration of pumping rates used on these strings in operations also provides field-tested practical guidelines for avoiding erosion when performing annular fracturing jobs. Inspection A CT string may be exposed to erosion in the outer surface during CT annular fracturing operations. The critical parameters that may influence the magnitude of erosion include fracturing pump rate, sand concentration, fluid rheology, wellbore geometry, and the grade of CT string. One measurable parameter to examine the string’s suitability is the wall thickness for each section. The CT strings discussed in the complete paper were sent for inspection to learn about the effect of the fracturing treatment. A series of nondestructive tests was conducted pre- and post-operation to evaluate the readiness of strings for subsequent operations. The complete paper includes two graphs related to the results of these tests. Materials The API 5ST specification requires using eddy current (EC) inspection for CT. With respect to API 5ST, quenched and tempered tubing had not been addressed at the time of this paper’s submission, so it is not clear whether the CT manufacturers employ EC techniques after quenching and tempering. However, it is expected that all tubing will be subject to EC inspection at least before any quenching and tempering operations. Inspection methodology and equipment consistency is important to establish a baseline inspection necessary for subsequent comparisons. In the case of the CT strings used in this study, all were subject to EC inspection at tubing manufacturing and then subsequently inspected by an outside, third-party vendor using magnetic flux leakage (MFL) technology when spooling the strings on the unit. No known third-party EC vendors can inspect string lengths of CT, so MFL inspection is the only available solution. Photographs of CT inspections taken at the manufacturing facility and the service and distribution point are included in the paper. Several commercial third-party inspection companies operate in North America, where this work was performed. Provided that the inspection can begin by identifying features in the calibration standard (often a through-drilled hole), the selection of inspection methodology is primarily a matter of preference for the service company and operator.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199853, “Development and Testing of an Electrical Drillstem Testing Tool Conveyed by Coiled Tubing With a Real-Time Control and Acquisition System,” by Michael Affleck, SPE, Aramco, and Monika Bakke Malmin and Per Egil Almas, Target Intervention, et al., prepared for the 2020 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, 24-25 March. The paper has not been peer reviewed. Some well-testing operations are executed by performing multiple runs in hole using slickline and coiled tubing (CT). A technology has been developed that combines many of these operations, including contingency stimulation activities, into one run. The complete paper introduces the major system components and reviews challenges associated with design, manufacture, and testing. Developing and Qualification Testing of the Tool Before engaging in the tool- development process, the following major operation-al requirements were identified and confirmed: Reduce the number of different services required and their associated rigup and rigdown times by maximizing the work scope performed with CT Increase timely access to high-quality data for rapid onsite decision making during well testing by converting from memory-based gauges and time-activated downhole shut-in tools to real-time control and data transmission to surface Maximize operational efficiency during well testing by having real-time data transmission to surface Introduce on-demand, selective stimulation capability while the tool and CT remain downhole Allow multiple testing periods during one trip in hole when required at different depths Increase the effectiveness of transferring the well from underbalanced to overbalanced status or vice versa by changing out fluids in the well or pumping nitrogen through the CT Reduce overall risk of stuck pipe or stuck tools during well testing by always having circulation available above the packer module Following multiple design iterations, two complete prototype tools were manufactured and module-level function testing was performed. In parallel, software development and testing of the graphical user interface commenced. Significant effort was applied to ensure that module testing was conducted in realistic downhole scenarios. Dedicated testing equipment was designed and manufactured. Design, manufacture, and module testing was performed in Algard, Norway. Primary components and specifications of the tool are provided in de-tail in the complete paper. Fig. 1 shows the tool [known as the e-drillstem test (e-DST) tool], while Table 1 provides specifications. Following qualification testing but before the first field application, a system-integrity test was performed with the CT service company. Special attention was paid to verifying all interfaces between the downhole tool and the supplier of CT equipment and processes. The verification of operating the new tool through the full length of cable (inside the CT) was tested thoroughly. Significant calibration was expected, required, and performed because the monoconductor cable is used for data communication in addition to tool power supply.

Note: The situation with the spread of the virus and government and company responses to it is very fluid. To meet press deadlines for JPT , this piece was written in mid-March. As the situation evolves, SPE will update this note at www.spe.org and individual event or other activity websites with the latest information. Networking is core to SPE activities, whether through an event, a local section meeting, service on a committee or other activity. The rapid spread of the COVID-19 virus globally is having far-reaching impacts across SPE activities. SPE has acted quickly, first in Asia Pacific, then elsewhere, to avoid increasing potential member and staff exposure. To date, SPE has postponed a number of conferences and most workshops including the following (see event websites for more details). OTC Asia, Kuala Lumpur Oman Petroleum & Energy Show, Muscat International HSE Conference, Bogota Latin America and Caribbean Petroleum Engineering Conference, Bogota Canada Heavy Oil Conference, Calgary Canada Unconventional Resources Conference, Calgary Norway Subsurface Conference, Bergen Offshore Technology Conference, Houston By the time you are reading this, it is very likely that more events will have been postponed. By postponing, rather than canceling these events, we ensure that the significant work of program committees and authors to prepare for these events covering important technical topics will not have been wasted. In a few cases, it may be necessary to cancel an event. Thus far, this includes only the SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas. Canceled events are most likely annual events and postponing by a few months would harm the next edition of the event. We are actively investigating options to allow those presenting papers at these events to do so in a digital format to share the content. In determining whether to postpone an event, SPE is taking into consideration the following factors: Conditions in the location where the event is to be held Mix of local and international participation expected at the event Guidance from key companies for the event about employee travel and participation Most of the Distinguished Lecturer (DL) tours for March and April have been canceled either due to the situation in the region to be visited or company travel restrictions. We are exploring virtual and digital options for the DL program. SPE has pro-vided some guidance to sections on their decision-making regarding local events, recognizing these are decisions best made at the local level. SPE will use criteria similar to those above in determining how to proceed with activities such as Regional Officers Meetings, Student Paper Contests, and PetroBowl Regional Qualifiers. We are seeking ways to enable remote participation in as many activities as feasible. Our emphasis in all cases is on local conditions and the health and safety of participants. SPE will continue actively monitoring the situation and potential impacts on future activities. The health and safety of our members, attendees, and staff is our highest priority, and that will guide any decisions that we make.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194284, “Pushing the Limits of Damage Identification With Coiled Tubing in Extreme Conditions: A Success Story From Japan,” by Nozomu Yoshida, SPE, Satoshi Teshima, SPE, and Ryo Yamada, INPEX, and Umut Aybar, SPE, and Pierre Ramondenc, SPE, Schlumberger, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper was peer reviewed and is scheduled for publication in SPE Production & Operations. The success of water-conformance operations often depends on clear identification of the water-production mechanism. Such assessment can be complicated significantly when formation damage is also occurring. Coiled tubing (CT) and distributed temperature sensing (DTS) were combined to overcome challenging conditions (high temperature, low injectivity, high deviation, long perforated intervals, and wellbore damage) to identify damaged oil zones and suspected water-bearing zones in an onshore well in Japan. Introduction Source and location affect the selection of water-shutoff techniques, which are either mechanical or chemical in nature or a combination. No matter the operational approach, identification of the water zone is a critical step for any subsequent course of actions. One method for the identification of water-producing zones is the use of production logging. Conventional production logging uses spinners and capacitance logs to detect water flow in the wellbore. Production logging tools (PLTs) can be deployed into the wellbore using slickline, wireline, or CT. To enable real-time evaluation of the acquired data, possible options include wireline, digital slickline, and CT equipped with either a conductor cable or fiber optics. In damaged wells with high water cut, flow conditions can be unstable, with drastic changes in flow regimes. Once the well can no longer sustain stable flow because of reservoir depletion or damage in the absence of an artificial-lift method, a PLT becomes impractical. Furthermore, when wellbore conditions are complicated by the presence of debris or contaminants, data acquisition itself becomes difficult. Quantification of the damage profile and of water-producing intervals is of great importance in proper planning for subsequent operations. To address these challenges, an alternative approach was used wherein DTS obtained through fiber optics deployed with CT was used to quantify damage profiles in severely damaged wells and to identify suspected water-bearing zones by integrating complementary information. The proposed operational procedures are similar to those used for the quantification of fluid placement during acidizing operations: injection of fluid to cool down the formation and shut-in to measure rate and amplitude of temperature recovery along intervals of interest. In the present case, brine was used as the injection fluid. Quantification of the damage and injection-rate profiles are achieved by temperature inversion; the measured DTS data are matched with the simulated temperature response given by combined flow and thermal numerical models accounting for key formation and near-wellbore parameters. The subject well was suspected to be severely damaged during the completion phase and yielded a relatively high water cut during flow test. This case not only highlights the validity of the proposed approach but also details the work flow and analyses performed to obtain meaningful data and to reduce uncertainty of the interpretation. The work also raises the importance of the integration of complementary data for a comprehensive understanding of well conditions.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 194283, “Rapid Deployment and Use of Snubbing Unit Brings Well With Underground Blowout and Surface Broaching Under Control,” by Albert Donaldson, SPE, Victor Marrero-Reyes, and William Scott, Halliburton, and Haitham Al-Mayyan, SPE, Kuwait Oil Company, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. This paper describes the mobilization of a snubbing unit and blowout preventer (BOP) stack in the Middle East that enabled a well with an underground blowout and surface broaching to be brought under control within a short time. The mobilization timeline is provided, along with details about how the snubbing unit and BOPs were integrated with existing equipment to enable re-entry into the blowout well. The procedures and equipment used to enable a stable rig-up and well entry are discussed. The paper also describes the situation within the well and the procedures used to bring it under control. Introduction and Background A well drilled and completed in 1991 was last worked over and recompleted as a single-zone producer in 2010. On 25 March 2018, the perforated zone was isolated riglessly with a through- tubing bridge plug (TTBP) and dumped cement, and new perforations were added between 3,994 and 4,010 ft. After perforation, wellhead pressure (WHP) was only 90 psi, which was not sufficient to flow the well to the nearby gathering center, and the well was shut in. On 29 March, the gathering center reported that WHP had increased to 800 psi and that a nearby cathodic protection well had begun producing oil and gas to atmosphere. Investigations were performed on all production wells in the vicinity, and identified the well that was the source of communication with the cathodic protection well. The tubing pressure was found to be 800 psi, and the casing pressure was recorded as 650 psi. Slickline was mobilized, and on 29 March, a tubing check revealed an obstruction in the tubing at 3,738 ft and provided evidence of damaged tubing at 1,960 ft. Between 29 and 31 March, multiple attempts to kill the well were made with brine weights between 9.0 and 9.6 ppg, followed by oil-based mud (OBM) at 16.0 ppg. Although pressures were temporarily reduced to 0 psi, they quickly returned to 800 psi on the tubing and 650 psi on the tubing by the 7-in. casing annulus. A total of 1,200 bbl of OBM was pumped into the well. On 3 April, wireline was rigged up, and the logs run indicated that the tubing was severely damaged at approximately 1,951 ft, with many holes and wall loss between 1,296 and 3,727 ft. The 7-in. casing was found to have severe damage between 1,585 and 1,620 ft. Pressure and temperature logs indicated gas flow between the tubing and casing at 1,951 ft.

Carlos Castañeda is hungry for more data and analysis from coiled tubing jobs, and the manager of coiled tubing engineering at Pioneer Energy Services said he also needs to know how his company’s work compares with the competition. Pioneer is one of more than 25 companies relying on CoilData for real-time monitoring. The data and analysis can tell him which of his people is efficiently drilling out plugs left after fracturing and the ones who may need retraining. What he does not have is a measure of how his company’s work compares with competing well-intervention companies because the data needed to do that are confidential. “If you are an individual service company, you are looking at your pipe in isolation,” said Paul Brown, the CEO and founder of CoilData. He sees great value in the data he has collected from more than 155,000 jobs monitored over the past 10 years, but tapping it will require companies to decide if the competitive advantage of analysis based on industry benchmarks exceeds the value of the current level of confidentiality. Recently he presented a rare multicompany look at how coiled tubing companies manage their most critical asset, coiled tubing strings. The paper presented at the SPE/ICoTA Well Intervention Conference and Exhibition showed significant differences in how much use companies got out of 3,700 tubing strings studied (SPE 194306). It raised the question: Are they leaving money on the table by prematurely retiring tubing strings that cost about $250,000 each? The Bigger Picture For those with no interest in well workover, it also raised a larger question about decision making. It showed how service company decisions vary widely when each company is operating in data isolation. Brown’s discussion of the results also showed how the available information on decision making can be limited and subjective. Brown has a unique perspective based on a career where he used his software and analytical skills to create tools to gather, monitor, and analyze well interventions. He offers many reasons for why companies stop using strings of coiled tubing. But the study showed a significant number of examples where the string’s cumulative metal fatigue—an estimate used to predict the likelihood of failure—was so low it suggested the tubing could have been used longer without a significant risk of failure. “They must have had a reason for doing it, but it might have been a bad reason,” he said. The qualifier “might” is required because only the company using the string can see what it looks like or know all the details about how it was used or abused.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194269, “An Advanced Technique for Simultaneous In-Situ Inspection of Multiple Metallic Tubulars,” by Yanxiang Yu, William Redfield, SPE, Nicholas Boggs, Kuang Qin, Marvin Rourke, SPE, and Jeff Olson, SPE, GOWell International, and Mosunmola Ekije, Fluor Federal Petroleum Operations, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper has not been peer reviewed. A new pulsed-eddy-current (PEC) electromagnetic (EM)-based tool called an enhanced pipe-thickness-detection tool (ePDT) has been introduced for the corrosion inspection of multiple pipes. The tool can measure the metal wall thickness of five concentric pipes with a maximum outer diameter (OD) of up to 26 in. This capability, along with the tool’s unique configuration, provides an advanced downhole solution for tubular evaluations of production, injector, and storage wells. Introduction As hydrocarbon production and storage wells age and new production and storage wells are exposed to elevated concentrations of corrosive fluids, well-integrity monitoring is gaining more attention. These factors have influenced well-performance, safety, and environmental concerns. Early, periodic monitoring of tubular corrosion and other defects can reduce the risks of serious leaks or well failures in a cost-effective way. Historically, the continuous sinusoidal-signal-based far-field eddy-current (FFEC) technologies have been developed and deployed for multiple-concentric-pipe average-thickness measurements. However, FFEC is adversely influenced by the strong interference of direct excitation signal transmission coupling and the EM skin effect; this reduces the pipe response because of a decreasing signal-to-noise ratio (SNR) that does not allow quantitative evaluation of more than two concentric pipes. In contrast, the PEC-excited EM signal contains wideband frequency components from kilo-Hertz to sub-Hertz range. The low-frequency EM signals penetrate concentric metal pipes effectively. The induced PEC on each tubular has different initial amplitude and decay rates because of a combination of OD, thickness, and EM parameters. After excitation, magnetic-field changes triggered by a combination of mutual inductive interactions among the pipes, eddy-current diffusion, and damping are picked up by the receiving coil during the acquisition window. Research and field applications have proved that the PEC method is more reliable for average thickness detection in multiple pipes. In previous studies by the authors, three pipes with up to 17-in. OD can be detected by magnetic tools. However, because of the combination of high signal dynamic range, inadequate SNR, extraneous tool motion, and troublesome interference of pipe magnetization, it has proved difficult for these tools to quantify thicknesses of outer pipes reliably in the presence of more than three concentric tubulars or at ODs greater than 17 in.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194255, “In-Line Quench-and-Temper Technology Applied to Coiled Tubing Improves Safety and Reliability in Extended-Reach US Shale Operations,” by Eric Gagen, SPE, and Gaston Piller, SPE, Coil Tubing Partners, and Irma Irais Galvan and Garry McClelland, Global Tubing, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper has not been peer reviewed. In unconventional resource plays across the United States, lateral well sections are being extended beyond 10,000 ft. The increased application of larger coiled tubing (CT) of 2.375-in. and 2.625-in. diameter for operations in high-pressure wells has pushed the reliability envelope for conventional CT strings. This paper discusses the advantages of the in-line quench-and-temper (Q&T) process, which enhances overall CT life and reliability by producing tubing with more-uniform microstructure throughout its entire length, increased material strength, and improved bend-fatigue performance. Technology Background Applying Q&T technology to CT has transformed well intervention in unconventional shale plays, particularly for multistage fracturing applications in 10,000-ft laterals or longer that are commonly completed with more than 80 intervals per wellbore. With some laterals 14,000 to 16,000 ft long, with 130 or more entry points, manufacturers and service companies have strived to deliver safe, cost-effective solutions for operational challenges. The implementation of technological innovations in surface equipment, downhole tools, and Q&T custom-engineered CT strings, along with refined operational practices and logistics, allows the performance of low-risk completions with over 10,000-ft laterals on a larger scale. At the time of writing, predictions suggested that more than 90% of the US CT market would switch to Q&T products by the end of 2018. Extended-Reach CT Design With Rapid-Taper-Strip Technology Rapid-taper-strip technology, which features a quick increase or decrease of wall thicknesses within the CT string, is an engineered solution for CT applications in difficult well conditions and geometries. This technology provides rapid wall-thickness strip transitions of 300-ft to 700-ft long to place specific thicknesses purposefully along the length of the string. Rapid-taper strips combined with Q&T grades enable engineers to design unique string configurations that can achieve unprecedented well lateral reach and service life. The technology helps minimize tubing weight in the horizontal section and increase stiffness in the vertical section to avoid the onset of CT buckling inside the wells. After its successful application in North America, the flexibility and operational benefits of this strip technology became well known. It has expanded into other applications, particularly in unconventional-resource developments where CT is subjected to extremely challenging environments. With weight restrictions being the pre-dominant challenge in extended-reach CT-string designs, the flexibility of rapid-taper strips allows for custom-engineered hourglass CT strings that maximize reach, overpull, and fatigue life while meeting CT surface-equipment-design constraints. An hourglass string configuration features a reduced wall thickness in the upper end of the CT string. This reduced wall provides safe overpull capacity during operations. Hourglass CT-string configuration advantages include weight optimization, reduction of frictional pressure losses, and added rigidity where needed while minimizing wall thickness elsewhere in the string to re-duce overall tubing costs.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 194254, “Study on Mechanism of Coiled Tubing Surface Damage in Injector Heads,” by Zhihong Zhou, Guofeng Zhang, Fayong Yuan, Tang Wang, Yunwei Gao, and Weijia Wang, Jianghan Shale Gas Development Technical Service Company, prepared for the 2019 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 26–27 March. The paper has not been peer reviewed. Although several kinds of mechanical damage cause coiled tubing (CT) failure, longitudinal plowing marks (LPMs) account for a large portion of such damage. Understanding the mechanisms of LPM damage on CT surfaces will help reduce the occurrence of this type of damage. In this paper, the authors study the stress status of CT string held by gripper blocks, the axial force distribution of gripper blocks, and the longitudinal resonance of CT strings in vertical wells. Introduction The overwhelming majority (greater than 80%) of CT failures have been classified into four categories: corrosion, mechanical damage, string-manufacturing issues, and human error. Of these, failures caused by mechanical damage constitute almost 30% of all CT failures. Further study of these types of mechanical damage reached the following two important conclusions: LPMs, which are injector-related, account for 46% of mechanical damage observed on CT strings from 2006 to 2017. Recent periods that have seen dramatic increases in mechanical damage coincide with plug milling and higher-grade-CT operations. The authors propose that the pressure in the CT string plays a role in mechanical damage. Contact Status Between CT and Gripper Blocks The gripper blocks carried by chains are used to hold CT strings in place. The gripper blocks are divided into single-pitch and two-pitch categories. The engagements between the CT string and the gripper blocks are sometimes suboptimal. The contact area between the gripper and CT string is only at the end-point of the arc, and the contact stress is much higher there than at the point at which the gripper blocks grip the original CT string. According to the von Mises yield criterion, if the von Mises stress is larger than the yield stress at any point, the material at that point will yield and plastic strain will be produced. Distribution of Gripper-Block Lifting Forces in the Injector Commonly, several pairs of gripper blocks engage the CT string to provide the friction forces needed for deployment and retrieval of the tubing into and out of the wellbore. How the axial loads of these pairs of gripper blocks are distributed is essential to safe operation and avoidance of CT damage. To obtain the axial load distribution of all pairs of gripper blocks, a mechanical model is created by the authors and discussed in the complete paper.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189947, “Using Ultrasonic Imaging Technology To Evaluate a Lateral-Entry Module,” by Marianne Solberg, Archer; Michael Sullivan and Steve G. Drake, ConocoPhillips; Tarjei Rommetveit and Duncan Troup, SPE, Archer; and Joel Johns, SPE, Quintana Energy Services, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. Several attempts to enter the upper lateral of a multilateral well operated by a major oil company in Alaska had been unsuccessful. In May 2017, an ultrasonic imaging technique based on medical ultrasound imaging was used to inspect the lateral-entry modules (LEMs). This paper presents the data collected by an ultrasound downhole scanner, demonstrating a novel method for diagnosing multilateral wells. Background The West Sak field is a viscous-oil deposit within the Kuparuk River Unit on the Alaskan North Slope. The reservoir was deposited in a lower shoreface to inner-shelf marine environment and consists of highly unconsolidated sandstones that have a gross thickness of approximately 500 ft and an average net thickness of 90 ft. The reservoir consists of three major producing intervals, the West Sak D, B, and A sands. Since original development in 1997, West Sak has been an active waterflood site. As technology improved and additional studies were completed, field development transitioned from a sand- exclusion strategy to a sand-management strategy. Completion strategy shifted to both producers and injectors with multilateral horizontal slotted liners. These multilateral completions have higher productivities than vertical wells but are subject to producing sand, and, over time, matrix-bypass events (MBEs) have been noted. These events occur when the rapid breakthrough of offset water injection through nonmatrix flow causes the affected producer’s water cut to jump instantly to 100%. Once an MBE occurs, the affected injector is shut in and the affected producer is left on-line to dewater. Eventually, the oil production returns, but, because of the lack of waterflood support, oil-production rates rarely return to those seen before the MBE. Problem Outline An MBE occurred between a West Sak multilateral injector and producer well pair. The standard diagnostic process of locating the MBE began. An injection profile log (IPROF) of the main bore in the injector determined that the MBE occurred in the D-sand (upper) lateral. An IPROF of the D-sand lateral was attempted using coiled tubing (CT) but was unable to exit the lateral junction. To gain lateral access, several different CT bottomhole assemblies were used and cleaning of the junction was attempted. These attempts were unsuccessful. The decision was made to run a downhole video to investigate the D-sand lateral junction better. Evaluation of the video data indicated that a portion of the LEM may have shifted, covering the upper section of the lateral window. This slight shift in downhole equipment may have been the only issue impeding CT from entering the lateral. Analyzing the data led to the idea of creating a specialized whipstock to allow CT to mill the obstruction to provide access to the lateral.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189956, “Successful Creation of Permanent Reservoir-Isolation Barriers Using Coiled Tubing on the Norwegian Continental Shelf,” by Iain Thomson, Halliburton, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. Plug-and-abandonment (P&A) operations can be expensive, leading to negative net present value. Historically, P&A operations in the North Sea—estimated to hold some 3,000 wells of declining production—were performed with either drilling or workover rigs. In many cases, wells drilled from fixed platforms in the North Sea no longer have operational drilling rigs, requiring recommissioning of existing facilities or mobilization of workover rigs. The complete paper discusses an alternative approach to P&A using coiled-tubing (CT) processes and techniques to create permanent reservoir barriers. Barrier Requirements Permanent abandonment of a well can be defined as the activities involved in securing a well that will no longer be used, to ensure containment and no harm to the environment. Standard details of how permanent reservoir barriers are to be created are provided by the Norwegian petroleum industry through NORSOK Standard D-010 . Section 9 of this standard details requirements for the creation of permanent reservoir plugs in abandonment activities. The creation of these reservoir plugs typically is dependent upon the condition of the well, the formation type, the quality of cement behind the casing, and the number of potential inflow sources. Similarly, two cross-sectional barriers must be provided across any inflow source together with a surface well barrier. The permanent plug (typically cement) should have a length of 100 m (50 m in casing with a mechanical plug), be positioned as near the inflow source as possible, extend 50 m above the source or casing shoe, and extend to the full cross section of the well (i.e., rock to rock). The cement should provide well integrity for the foreseeable future and should be impermeable; materials used should not have shrinking properties. Additionally, the cement must withstand mechanical impact and loads; be resistant to chemicals, such as carbon dioxide, hydrogen sulfide, and hydrocarbons; and be wet, to help ensure bonding to steel casings. Field P&A An operator determined that wells in an uneconomic field on the Norwegian Continental Shelf needed to be plugged in preparation for abandonment. The field, located off the west coast of Norway, comprises 22 wells from a 24-slot fixed-jacket production platform. Of these 22 wells, 17 were oil producers (five still producing/12 shut in), one well was an active water-injection well, two were active wastewater- disposal wells, and two wells were previous P&A wells that required removal of the conductor and surface casing. The P&A operation would be split into five phases, the third of which (setting primary reservoir plugs) would be performed with CT. Well parameters varied, but primary reservoir barriers were generally set in 5½-in. or 6 5 / 8 -in. completions at depths of between 2400 and 4400 m with inclinations between 85 and 90°.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189904, “Underbalanced Drilling With Coiled Tubing: A Case Study in Marginal Shallow Wells,” by Adam Miszewski, SPE, and Toni Miszewski, SPE, AnTech, and Peter Hatgelakas, Chuck Henry Energy, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified as adjacent to a recently drilled vertical well using a lateral sidetrack. The project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well. The Economic Equation The target of the project was to define drilling efficiency in terms of cost per production rate. This measure takes the initial production into account and ties together the ability of the driller to make hole in the direction required with the ability to select a productive part of the formation. Recognizing that each stage of well construction can affect another, a multidisciplinary approach was adopted that included input from geology, geophysics, reservoir engineering, and drilling and completions engineering. Local experience with offset wells also was an important input, allowing for the fact that this experience was limited to vertical wells drilled with air or in an overbalanced condition. Well Selection The area chosen for the case study was in a well-understood area containing numerous offset wells with which to compare production and a known geology against which to plan the well. The wells typically do not exceed 2,500 ft in depth and were exclusively vertical. Four such wells had been drilled in the immediate vicinity in the previous year, three of which are currently on production at the time of writing at rates ranging from 10 to 25 B/D with varying levels of associated water production. Although one of the wells showed promise of production, the well turned out to be dry and the planned 4½-in. production casing string was not run and the well was not completed. The uncased well was chosen for the case study because it had the shortest payback period if it could be made to produce at a rate similar to those of neighboring wells. A 3D seismic survey of the area had identified a subsurface ridge that could be acting as a trap (Fig. 1). This ridge was selected as the target of the new well. A well path was planned that tracked approximately 15 ft below the top of the reservoir and along the top of the ridge, a depth low enough to access the reservoir but not so low that it might access the oil/water contact believed to be 40 ft below the reservoir top.

Technology Focus Coiled-tubing drilling (CTD) was a very active area of operations years ago, but it seems to have gone through a lull recently, certainly in terms of active geographic areas. However, if the papers presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition this March are anything to judge by, then CTD seems to be regaining some interest in the broader market. The application of CTD in the papers featured in this issue and in the recommended additional reading highlight its use in more niche areas. Paper SPE 189904 details the use of CTD to access marginal and bypassed reserves. Although the fields may be marginal, the effect within the US is not. As stated in the Interstate Oil and Gas Compact Commission’s 2012 report, “The hypothetical elimination of $30.8 billion in marginal oil and natural gas production in 2012 would trigger an estimated direct loss of 95,442 jobs and $4.62 billion in earnings within the oil and natural gas industry.” Accessing these potential resources spawned several projects sponsored by the US Department of Energy in the mid-1990s. A well re-entry and sidetrack CTD operation in New Zealand is reviewed in paper SPE 189930. A niche CTD application in Australia is explored in paper SPE 189918, which revisits the placement of the coiled-tubing reel directly above the injector, with some new, unique features. Another operational area that is enjoying a continued level of high activity is milling with coiled tubing. This is being combined increasingly with real-time downhole telemetry made available at surface. Real-time communication with coiled-tubing bottomhole assemblies has enabled engineers and operations personnel to evaluate and optimize milling through increased understanding and interpretation of data streams. Papers SPE 189910 and SPE 189942 both detail such applications, each using differing telemetry methods. In the oil and gas industry in general, a considerable focus is being placed on well abandonment and its associated cost, especially offshore. Around the globe, well operators are developing alternatives to using traditional rigs, and, in many instances, coiled tubing is being used to perform partial or full well plugging. Alternative well-plugging materials and methods continue to be developed that could be used with coiled tubing. A 13-well, 10-month campaign of well abandonment in Norway is reviewed in paper SPE 189956. Recommended additional reading at OnePetro: www.onepetro.org. SPE 189918 The Coiled-Tubing-Drilling Rig for Mineral Exploration by S. Soe, Deep Exploration Technologies Cooperative Research Centre, et al. SPE 189930 Coiled-Tubing Drilling: Case Study, New Zealand by Soheil Kariminejad, Tag Oil, et al. SPE 189942 First Time Coiled-Tubing Milling in 7-in.-Monobore Gas Well Using Downhole Real-Time Measurements by W.R. Tapia, Schlumberger, et al.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 189945, “Dendritic Acidizing Update: The Light at the End of the Tunnel,” by C. Dean Wehunt, SPE, Stefan K.K. Lattimer, SPE, and Darren R. McDuff, SPE, Chevron, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. Dendritic acidizing (DA) has a long history in the oil industry, going back at least to the 1980s. Significant technical advances include single-trip multitunnels using only acid-pumping equipment and a coiled-tubing (CT) unit, simultaneous tunnel creation, and improved parameter modeling and optimization. This paper provides an update on recent advances for DA methods, also known as acid tunneling, presenting a comprehensive review of published information for three different tunneling methods. Introduction A well with multibranching major tunnels and a superimposed structure of wormholes emanating from the main tunnels has been called a dendritic well. This paper refers to methods that include the use of acids to construct such a well as DA. DA methods can be thought of as a hybrid between multilateral wells with many short branches with low skin factors and matrix acid jobs with very long primary wormholes and many branching wormholes from the primary wormholes. A conceptual example of a horizontal well section with formation tunneling and DA with branching wormholes adjacent to the primary tunnels is shown in Fig. 1. Many different methods are used to form small-diameter lateral branches from a parent wellbore. The methods are differentiated by characteristics such as requirements for workover rigs, CT rigs, and deflector shoes for tunnel initiation; acid use in the process; and primary tunnel creation method. Method A Method A uses a proprietary small-diameter CT unit to deploy a jet nozzle on a flexible, retractable hydraulic hose. The method uses mechanical energy to blast the formation during tunnel creation and, in some cases, also uses acid either while jetting or while retrieving the jetting nozzle to chemically assist with tunnel creation and reduce the skin factor adjacent to the formation tunnels. Method A can be applied in either openhole (OH) or cased-hole completions. In cased-hole applications, a deflection shoe must be run on a work string using a conventional workover rig, and then a hole must be cut in the casing with a separate milling tool. After the milling tool is retrieved by the proprietary CT unit, the jetting nozzle begins jetting a tunnel perpendicular to the well. Although the milling step is not required for OH applications, the deflection shoe must still be used. The jetting nozzle is deployed on a flexible tool that is kept perpendicular to the well by tension on the hose. The tension is also what pulls the hose into the tunnel, so Method A is a pull-the-nozzle method. Hose tension is created because there are rearward-discharging jets with greater discharge area than the erosional jet discharging toward the tunnel tip.