Among different industries, there is a lack of consensus with regard to wireline initiation safety with explosives. In the oil industry, procedural methods, such as electrical before ballistic arming (EBBA) and safety keys, have been used successfully for many years. However, the industrialization of fracturing has increased the volume and speed of the operations, and it is now common to have new hazards, such as multiple radio frequency (RF) sources and electric fracturing equipment. This work attempts to clarify wellsite safety requirements and proposes new solutions.
RF radiation can create accidental detonation of an electro-explosive device (EED), which can be catastrophic if the device is connected to a wireline perforating gun. Strict adherence to safety procedures including radio silence during perforating jobs and other controls have mitigated most RF risks.
Perforating safety standards are being updated at the writing of this paper with a major overhaul of the current
The explosive manufacturers and service companies are aware of this trend and are developing new products to add engineered controls for the hazards. As the market transitions from procedural to engineered solutions, competing claims and counterclaims make it difficult for end users to understand the risks. This will continue until effective engineered controls become common and best practices in the industry are adopted.
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.
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.
After an operator confirmed wellbore integrity failure in a well located on a small platform, a coiled tubing (CT) catenary intervention was urgently required. However, the production facilities of the platform were not authorized to operate, which represented an impediment to receive returns from the wellbore. This paper documents the analysis and implementation of nonconventional flowback methods and the actions taken to perform the intervention using a state-of-the-art fly-by-wire CT catenary package in a setup that had never used before in this field.
After a shut-in period, the subject well faced integrity issues that could end in an uncontrolled situation. To remediate this situation, milling and plug-setting runs were designed using a catenary system with a fly-by-wire CT unit set for first time completely on the vessel and leaving only the injector head on the platform. To address the flowback limitation, technical and economical assessments were performed on three options: using slope barges to receive fluids in storage tanks, setting conventional flowback equipment on board the catenary vessel, or using the gas injection pipeline available on the platform.
After analyzing each alternative, the options to use slope barges and flowback equipment on the vessel were discarded after confirming that they represented an additional risk and generated higher costs for their implementation. The use of the gas injection pipeline involved the modification of many resources on land and at the offshore facilities, and a detailed plan was needed to utilize the lines in a different way from their initial design. Additionally, weather conditions played a major role during the job execution. Consequently, a special focus was placed on elaborating contingency plans to address emergencies during the operation taking into account that the method implied handling hydrocarbons at surface under uncommon situations. The coordination and collaboration in the operation enabled the operator to achieve the expected results, recovering the wellbore integrity in a cost-effective way, while also eliminating the exposure of additional vessels or sophisticated equipment on location.
The paper presents the large amount of information that was amassed during the implementation of the solution, which could be used by other locations facing similar conditions where conventional production facilities cannot be used during well interventions. The document also includes contingency plans for every stage of the project, safety measurements, lessons learned, and details of the modifications done to the gas injection system and the CT equipment.
Many coiled tubing(CT) operations involve passage through the production tubing. However, due to the adverse wellbore trajectory or tubing geometries, especially in helically buckled tubing, the CT operations are still encountering various bottlenecks when it is pulled or lowered through the tubing. In this paper, a new concept "local model", which provides a sophisticated description of CT deflection in buckled tubing from local perspective, is proposed to help supplement the integral torque-drag model. Firstly, the CT can pass through the buckled tubing freely without any deformations. According to the constrained geometric relationship between the tubing and CT, the maximum CT length and maximum outside diameter can be calculated. Secondly, when the CT dimension parameters are beyond the scope of the above rigid dimension, the CT can pass through the tubing flexibly with deformations. So a beam-column model is established to analyze the CT deflection and bending behavior in snaky and helically buckled tubing. The results show that the buckled tubing configurations have significant effects on the CT passage dimension. Once the CT dimension parameters are out of the range of rigid dimension, it would contact the tubing at some points with large buckled tubing amplitude. Moreover, the contact forces and bending moments are influenced by the axial force and buckled tubing amplitude. This "local model" analysis results can be implemented in the torque-drag modeling to optimize the CT extended reach and axial force transfer.
Achieving effective fluid coverage of stimulation operations in deepwater frac-pack completions is often challenging due to a variety of factors, including, but not limited to, the length of screened intervals, the uncertainty of damage mechanisms, and the ability of diversion materials/fluids to divert beyond the screens and into the formation. This case study demonstrates a successful technique used in conditions not previously attempted.
This treatment in a deepwater, frac-packed well with fiber-optic-equipped coiled tubing (CT) and a rotating, hydraulic high-pressure jetting tool achieved the successful stimulation of a 500-ft-long frac-packed zone after several previous failures using different techniques. By using a CT equipped with fiber optics and downhole measurement tools, engineers were able to perform a data-driven operation based on real-time bottomhole measurements and distributed temperature surveys.
This successful treatment improved productivity by 75% compared to the well before treatment. Typically, treatments of this nature are investigated and techniques for a field or region are refined over the course of multiple stimulation operations of large numbers of similar wells in the area. However, in deep water, most fields have only a very small number of wells. The costs associated with gaining wellbore access to conduct an acid treatment and with handling produced stimulation fluids are very large compared with costs in other geographic areas. Each individual well has a high productivity, and improper stimulation is an enormously costly lost opportunity for the operator. This makes it very important to ensure that every job is performed as optimally as possible, without resort to iterative or empirical methods. This method increases the opportunity to produce a successful treatment the first time and expands the technical envelope of application. These enhancements should allow other operations of this type to be conducted that previously would have been too high risk to consider.
This was a high-pressure application compared to previous operations. It was one of the longest fiber optic cables injected into a CT reel. Modifications were made to the CT reel to support the expanded weight. A stronger type of fiber optic carrier had to be utilized. A customized testing and validation procedure had to be used to extend the operating envelope of the fiber-optic-enabled downhole tools to perform reliably.
A drill-bit supplier provided mills and bits for drilling out fracturing plugs for a new project in the Vaca Muerta formation in Argentina; however, it was difficult to locate information on similar experiences elsewhere. This paper presents the experience gained during execution of a completions project that included fracturing plug drillouts.
Several technologies were used, and their performances are reviewed, including mills, roller-cone bits, and polycrystalline diamond compact (PDC) bits. Drillout times, size and shape of debris, hole cleaning, and tool dull grades are analyzed. All operations were performed with coiled tubing (CT) equipment. Other parameters considered in the analysis include drilling parameters, number of runs to complete a well, plugs per run drilled, and tolerances with respect to casing drift. Some problems that occurred during project execution are discussed, such as motor stall and casing deformation.
The operations were performed in a combination of horizontal and vertical wells. More than 500 fracturing plugs were drilled out in more than 60 wells, gaining sufficient experience to derive significant conclusions. To help reduce drilling time, improve economics, minimize risks, and reduce CT system fatigue, the five to six-blade PDC bit was verified as the best option in this context. This drill type has an acceptable rate of penetration (ROP), does not risk losing moving parts, and minimizes motor stall. When tolerance with respect to casing drift is correct, the five to six-blade PDC bit also minimizes debris size, which helps reduce stuck-in-hole risks and improves subsequent well production.
Several statistics, images, and resolved issues are presented to advise future CT and well intervention projects. Conclusions regarding various plug types, materials, and drillout procedures are also explained to aid similar projects.
Duaij, Ahmed (Saudi Aramco) | Al-Buali, M. H. (Saudi Aramco) | Ahmed, Danish (Schlumberger) | Arifin, Mohammad (Schlumberger) | Sa, Rodrigo (Schlumberger) | Dehingia, Madhurjya (Schlumberger) | Santali, M. (Schlumberger) | Pochetnyy, V. (Schlumberger)
This paper describes the evolution of descaling interventions via coiled tubing (CT) performed in Saudi Arabia gas wells in the Ghawar field. Throughout these operations, the introduction of new technologies and improved surface equipment has significantly enhanced the efficiency and effectiveness.
CT is the preferred choice for descaling interventions in wells whose reservoirs are underpressured/ depleted because it can accurately place fluid and deploy mechanical tools at the specific depths where scales are present. High leakoff into the formation and hydrogen sulfide (H2S) released at the surface are two main challenges that occur in this well type. Therefore, it is paramount to continuously monitor and control both downhole and surface parameters. The aforementioned challenges can be addressed by optimizing real-time fluid placement or by manipulating the choke size, among other parameters. A chemical plug can be pumped to isolate the reservoir before commencing descaling interventions, but this process may require stimulation or re-perforation of the reservoir system after the treatment. Therefore, it is preferable to use a system that is flexible enough to execute a wide range of operations, from reservoir isolation to descaling treatment, while maintaining the well in balanced or marginally overbalanced conditions.
Previously, CT descaling operations were executed relying only on surface parameters. Today, new technologies are available that can provide live downhole parameters such as pressure, temperature, load, and torque, and these technologies have advanced descaling interventions. Although downhole parameters via downhole tools have been available for years, tools providing such parameters were limited with respect to pumping rate, working pressures, temperature, and ability to sustain high torque and vibration. To address these issues, a new tool was developed that can acquire downhole parameters during milling and clean out operations. The ability to monitor downhole parameters enables field personnel to act instantly to any change in downhole conditions. At the same time, introduction of advanced surface equipment has helped in better handling of returns from the well and in maintaining a constant wellhead pressure irrespective of dynamic returns. Therfore, the treatment is executed within its defined limits and risks of service quality events are mitigated.
This paper describes the evolution of CT descaling intervention treatments and the technologies used. It details how the introduction and integration of new technologies have enhanced descaling operations in Saudi Arabia where real-time decisions were made to optimize treatment, make the operation safer, and prevent formation damage.
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.
Drilling activity in remote, complex environments has increased in Alaska as operators seek to combat falling production in existing wells and shift to commercialization of natural gas and condensates. The completion of these wells often requires coiled tubing (CT) intervention, whereby CT is used for various applications, including wellbore cleanout, milling, fishing, and acidizing operations. To complete multiple high-pressure wells in a remote field, an operator required a CT contingency to shift formation isolation valves.
A new collaborative approach was implemented in which the operator and CT service provider closely worked together on the technical job design from the onset of the project to optimize planning and execution. The planned intervention was part of a large project in which a single company provided most of the services. This allowed the CT service provider to work closely with the operator and third-party providers, such as the fluid supplier and completion equipment supplier, to complete key technical design elements, including CT string design, fluid design, and downhole tools selection. In this way, an integrated, fit-for-purpose solution was delivered to the operator.
Many key challenges were associated with this intervention. The biggest challenge was the absence of previous such experience in a well in Alaska where maximum allowable surface pressure (MASP) exceeded 8,500 psi. The intervention would require well control equipment and other pieces of treating equipment and downhole tools rated for 15,000 psi that were not readily available in Alaska. In addition to the well's high MASP (8,564 psi), other key challenges included being ready to perform a CT milling operation of a formation isolation valve in large casing (7�? in.) in an environment with 30-ppm H2S and 4.55% CO2 where ambient temperatures could drop as low as−50° F. A 2-in. CT string with a length of 19,000 ft was designed to provide sufficient weight on bit and overpull to complete all required contingency CT operations. A fluid system was designed to not only control the high pressure in the well but also be pumped through the CT string at circulating pressures that did not exceed the limits of the pipe. Furthermore, a test was completed prior to the mobilization of equipment to location to determine the optimal design for milling the formation isolation valve with CT.
This paper presents the job design and preparation processes completed for the first planned CT intervention contingency in Alaska, in addition to lessons learned that can be applied to future high-pressure CT operations requiring well control equipment rated to 15,000 psi.