bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cost-Effective Approach in Stimulating Openhole Water Injectors Using Real-Time Flow Measurement A Case Study
Authors: Al-Houti Nasr , Al-Matrouk Y. , Al-Othman M. R. , Al-Mehanna H. S. , Al-Haddad M. N. , Mahmoud Wael A. , Ramondenc P. , Chaabouni H. 
Published: February 2017

Abstract
A few years ago, following an extensive field study in North Kuwait, several wells were sidetracked and converted as horizontal openhole water injectors to support reservoir pressures as part of a secondary recovery plan. Production improvement was immediate, but injection rates soon started to decline and injection pressures were rising, eventually jeopardizing oil recovery. Conventional acid stimulation only led to short-lived improvements, and more elaborate methodologies rapidly became uneconomical. A new stimulation strategy was needed.
In these carbonate reservoirs, marked, sustainable improvements in injectivity can only be obtained through accurate placement of stimulation fluid across the entire interval, away from high-intake zones that develop as a consequence of repeated blind acidizing practices. A real-time, pump-through downhole flow measurement tool was used with coiled tubing (CT) to profile the openhole sections and identify thief and tight zones prior to treatment. The tool enabled adaptation of the stimulation strategy and was then used to ensure proper fluid placement during the pumping stages. Both profiling and pumping were performed in just one trip.
This innovative tool and its cost-effective workflow unlock a new level of operational efficiency. Whereas previous approaches required mobilization of additional equipment, the proposed methodology allows profiling horizontal sections and treating them in a single run with the same bottomhole assembly (BHA). For the water injectors presented in this study, this represented a saving of 3 days of operations and the associated logistics costs as compared to using logging tools and tractors for profiling. Moreover, real-time downhole flow monitoring with CT opens new avenues for treatment optimization, and ultimately, stimulation effectiveness. It allows for a better control of fluid resources and placement while the treatment is in progress. Flow sensors can be used to obtain the initial injection profile in lieu of distributed temperature sensing (DTS), which typically requires long acquisition times in water injectors. In this study, the wells treated with this approach showed a sustained 100% increase in injection rate, with the injection pressure dropping to nearly 0 psi. The volume of stimulation fluid needed was also lower than expected, yielding additional cost savings.
By providing direct, real-time downhole flow measurement, this new tool brings acid stimulation execution to a new level of effectiveness, an advance necessary to the sustainability of many production enhancement projects in Kuwait. Furthermore, the use of this new monitoring capability is more cost-effective than conventional stimulation approaches that have proven either inefficient or detrimental to wells in the long run.
Subsea Well Plug and Abandon Intervention Using a Coiled Tubing Conveyed Inflatable Packer A Case Study
Authors: Akbar V. , Fuad M. 
Published: February 2017

Abstract
Failing to properly abandon a well can create significant safety and environmental hazards, lead to noncompliant status with regulatory agencies, and harm the operator's image. This case study follows the plug and abandon interventions of five subsea wells located offshore East Kalimantan, Indonesia that had been left shut in since the 1980s after they stop producing. The questionable well integrity and limited circulation paths of these older subsea wells had the potential to generate additional hazards unless properly addressed.
An inflatable packer run on coiled tubing (CT) was chosen to address the challenge of well integrity because the packer was able to isolate the upper completion and subsea tree while cement was being injected into the reservoir. Hence, exposure of the well components to pressure was minimized, which consequently minimized the risk of having a well control issue due to overpressure. Another challenge stemmed from the difficulties of placing cement in the casing–production-tubing annulus as the return line on the annulus side was removed due to corrosion. A CT-conveyed inflatable packer set in between two punch holes on production tubing allowed for accurate cement placement in the casing–production-tubing annulus.
The operation was successfully performed. The reservoir in each of the five wells was safely plugged with cement and the inflatable packers were left in hole as additional barriers. Every cement plug placed in the wells was tested to 1,000 psi to prove the integrity of both the cement and the packer. The ability to place cement in the annulus ensured full coverage of the wellbore without the need to cut and retrieve production tubing. Inflatable packers allowed cement to be pumped down through CT to the annulus through the lower punch hole, and the return to go back to the surface through upper punch holes and up through the production tubing. Twenty inflatable packers were deployed in five wells for both purposes mentioned above, thus proving the reliability of the inflatable packer application in this type of intervention.
Novel Technology Improves System Safety in Wireline Perforating
Authors: Fayard Alfredo J. , Goodman Kenneth 
Published: February 2017

Abstract
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 API RP67 Recommended Practice for Oilfield Explosives, second edition(API 2007, reaffirmed 2015), including a third classification for primary-explosive-based detonators with enhanced RF protection.
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 Improved Method for Shifting Sliding Sleeves on ICD Screen Completions in Extended- and Mega-Reach Applications Combining a Novel Shifting Tool with Coiled Tubing Well Tractor Technology
Authors: Areepetta Mannil A. , Lobov M. A. , Buyanov M. , Chang K. , Silva L. , Kazakov A. , Eliseev D. , Zemchikhin A. 
Published: February 2017

Abstract
Korchagina and Filanovskoe oil fields in the north Caspian Sea have many extended- and mega-reach wells that uses inflow control device (ICD) screen completions with sliding sleeves. This completion technique empowers the operator with the ability to shut off unwanted water/gas breakthrough and allows for more control of injection or inflow with unlimited number of stages or zones. This paper describes a new verified workflow to successfully intervene these wells and manipulate (open/close) these sliding sleeves using coiled tubing (CT).
It has proven challenging to shift these sliding sleeves using conventional methods with CT owing to the limitation of available weight on bit (WOB) at the toe end of those extended-reach wells, even when using large-size CT strings. The new proposed workflow uses a well tractor operated in tandem with a hydraulic shifting tool to generate the required shifting force downhole. The bottomhole assembly (BHA) also includes a novel flow control sub, assembled between the shifting tool and the tractor, with the ability to control the flow to selectively activate the tractor, the shifting tool, or both, based on surface commands by manipulating pump rate.
To verify the methodology, a realistic well scenario was simulated at a test site by installing two ICD screens with sliding sleeves at the end of a 1,000-ft-long horizontal flow loop. The sleeves on each ICD screen required approximately 4,000 lbf set-down force to open. The available WOB at the end of horizontal loop with 2-in. CT was only 1,000 lbf; applying more than 1,000 lbf set-down load could have detrimental effects, including CT buckling. The 3⅞-in. OD well tractor used for the job was able to generate 6,000 lbf of pulling force downhole, which was more than enough to shift the sleeves open. Both sleeves were successfully opened by tractoring down while maintaining both the tractor and the shifting tool in the on position, which was achieved by manipulating the flow control sub using pump rate cycles. Both sleeves were then successfully closed, one after the other, by pulling with the CT with the tractor turned off while maintaining the shifting tool in the on position, again achieved by manipulating the flow control sub. Live downhole pressure and force measurements were key in confirming proper functionality of the tractor and identifying different tool modes. Having real-time data is also crucial for proper depth correlation using casing collar locators (CCL) or gamma ray measurements to ensure activating the correct sleeves.
This marks the first time that a workflow was verified on the use of pull force generated by a well tractor to manipulate completion accessories in extended-reach well interventions using CT. The technology, preparation, results, and prospects of implementation are discussed in this paper.
Coiled Tubing Cementing Best Practices for Successful Permanent Well Abandonment in Deepwater Gulf of Mexico
Authors: Giam David , Santiapichi Jorge , Bogaerts Martijn , Herrington Darby 
Published: February 2017

Abstract
In deepwater Gulf of Mexico, cement placement through coiled tubing (CT) has been proven over several decades to be a valuable, versatile, and cost-effective tool for the through-tubing plug and abandonment of depleted oil and gas producers. In this paper, several present-day recommendations and best practices in relation to CT cementing for well abandonment are described.
CT cementing is typically used for well abandonment when leaving part of the production tubing in place is deemed beneficial from an economic or operational risk standpoint. As demand for the reliable placement of permanent cement barriers during well abandonment continues to grow, the importance of optimal design methodology, laboratory practices, and placement techniques associated with CT cementing has also increased. For instance, one of the most important aspects is to design a thin yet stable cement slurry. In addition, thickening time tests must account for the time a slurry is in the CT reel at surface before travelling downhole. Fluid placement techniques should account for the use of any downhole tools and be adjusted accordingly.
In recent well abandonments, a high success rate in the placement of cement plugs through CT has been observed. The main contributor to this success is the consistent manner in which the best practices described in this paper were followed. These methodologies also include some that have slowly evolved over time. For example, during well abandonment, one procedure that appears to be gaining popularity in some situations is the running of inflatable cement retainers with the ball on seat. In regards to CT cementing, this has often resulted in modified strategies, with fluid placement techniques counteracting the inability to pump any fluids through the CT prior to setting the retainer.
This paper is based on several recent abandonment campaigns using an intervention vessel in the Gulf of Mexico in 2016. Throughout the course of these particular campaigns, a total of 32 cement plugs were placed through CT, all of which were successfully verified, thus avoiding costly remedial placement. Although different conditions and well-specific challenges can slightly alter the approach taken, there are several steadfast techniques that appear to be effective in the consistent delivery of desired results.
An Alternative Method for Cement Squeeze in North Kuwait: Case Study
Authors: Al-Houti Naser , Al-Othman Mohammad , Al-Qassar Khalid , Al-Ebrahim Ahmed , Matar Khaled , Al Hamad Abdulla 
Published: February 2017

Abstract
This paper presents the application of a unique gelling system for perforation shut-off operations that can help reduce operational time by 50% and can also be used as an effective water- and gas-migration control agent. The system combines a conformance sealant (based on an organically crosslinked polymer) with non-cementious particulates. The particulates provide leak-off control, which leads to shallow matrix penetration of the sealant. The filtrate from the leakoff is thermally activated and, as a result, forms a three-dimensional (3-D) gel structure that effectively seals the targeted interval after exposure to the bottomhole temperature (BHT).
The traditional method for recompleting wells into newer layers, after the current producing zones have reached their economic limit, involves several steps. The first step is to squeeze off the existing unwanted perforations using cement, drill out the cement across the perforations, and then pressure test the squeezed zones to help ensure an effective perforation seal has been achieved. The new zones are then perforated and completed for production. The entire operation can require four or more days of rig time, depending on the success of the cement squeeze. In cases of cement failure, the required time can extend to over one week. Common challenges associated with cement-squeeze operations include leaky perforations, fluid migration (gas or liquid) behind the pipe, or compromises in the completion. Attempts to remediate these issues must be repeated until all objectives are met.
The new perforation plugging system can be bullheaded into the well (spotted at a desired location in the wellbore), allowing for easy placement and calculation of the treatment volume. The limited and controlled leakoff into the matrix during the squeeze results in a controlled depth of invasion, which allows for future re-perforation of hydrocarbon-producing zones. The system can be easily washed out of the wellbore, unlike cement, which must be drilled out. The temperature range of the particle-gel system is 60 to 350°F, which makes it versatile.
To date, more than 500 operations have been performed with this system globally. This paper presents the results obtained from laboratory evaluations, the methodology of the treatment designs, and four case histories from Kuwait. A salient case is the successful use of the sealant/particulate system, resulting in shutting off all perforations after six failed cement-squeeze operations.
The prospect of reducing the required time to perform remedial cement-squeeze operations by 50%, as well as the ability to repair casing leaks and seal off thief zones, make this sealant/particulate system a valuable alternative to standard cement-squeeze operations.
Evolution of Coiled Tubing Descaling Interventions in Saudi Arabia Depleted or Subhydrostatic Gas Wells
Authors: Duaij Ahmed , Al-Buali M. H. , Ahmed Danish , Arifin Mohammad , Sa Rodrigo , Dehingia Madhurjya , Santali M. , Pochetnyy V. 
Published: February 2017

Abstract
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.
Evaluation of Lubricants Performance for Coiled Tubing Application in Extended Reach Well
Authors: Yeung John , Li Jeff , Lee Jane , Guo Xiaole 
Published: February 2017

Abstract
Coiled Tubing (CT) intervention operations in extended reach wells (more than 10,000 ft in the lateral length) have become quite common in North America. In general, a 2.0″ CT has enough weight to reach the target depth in a 5,000 ft lateral. Therefore, to reach a 10,000 ft lateral, the use of metal-to-metal friction reducer (MFR) or lubricants will be required to work in conjunction with downhole extended reach tools. However, in some interventions, only lubricants can be used, without the downhole extended reach tool.
Various lubricants are available in the CT industry. Based on field operations, a typical lubricant could reduce the coefficient of friction (CoF) by about 20%, while a high performance lubricant could reduce the CoF by up to 50%. In order to reach the bottom of a long lateral well, it is imperative that coiled tubing operators are using the most optimal lubricant in correct applications.
In this paper, a linear friction apparatus was introduced and used to evaluate the friction reduction performance of 7 lubricants at various concentrations. With a test fixture, both the static and dynamic CoFs were measured. In addition, the performance of the lubricants was also evaluated with the introduction of polyacrylamide (a fluid friction reducer, FR), the salinity, and sand in the fluid system.
The test results indicated that only a few lubricants could effectively deliver CT extended reach. In general, the static CoF of the lubricants was 10% to 30% higher than the dynamic friction. An increase in water salinity and the presence of sand in the wellbore had a negative effect on the performance of the lubricant.
A higher lubricant concentration resulted in a lower friction coefficient, especially for the high salinity and sand conditions. However, the use of a fluid friction reducer could be detrimental to the lubricant friction performance when the FR concentration is more than 1%.
Mitigating Gas-in-Riser Rapid Unloading for Deepwater-Well Control
Authors: Yuan Zhaoguang , Morrell Dan , Sonnemann Paul , Leach Colin 
Published: February 2017

Summary
In deepwater wells, if gas comes into the riser, a rapid unloading event may occur if removal of the gas is not carried out properly. Oil-based muds (OBMs) present an even greater challenge when compared with water-based muds (WBMs) to avoid gas-in-riser events, because the gas dissolves in the mud and may not be detected until it breaks out inside the riser near the surface.
A study with a dynamic multiphase-flow software simulated a rapid unloading event and determined the gas fraction in the riser annulus and the effect on riser-fluid levels. New procedures, such as shutting in the riser or proactively applying surface pressure, were simulated to evaluate the effectiveness of riser-top equipment to mitigate risks of rapid riser unloading. The effects of gas volume and mud type (WBM vs. OBM) on water hammer and riser top pressure during the shut-in were analyzed with a simulated case with a riser in 8,000 ft of seawater.
The analysis shows there is no significant pressure increase at the moment of rapid unloading in a shut-in well. The reliability of the simulation results is verified with a field test conducted at 1,200-ft water depth. The simulation results show it is possible to safely manage gas-in-riser events for large gas fractions with available managed-pressure-drilling (MPD) and riser-gas-handling equipment.
It should be possible to safely and efficiently manage events involving even relatively large gas influxes in risers by use of new proposed procedures, which mitigate the rapid unloading and can help industry develop new guidelines for deepwater-drilling operations.