bluuebunny/crossref_metadata_2025_split huggingface dataset:
Downhole Mixing Fracturing Method Using Coiled Tubing Efficiently: Executed in the Eagle Ford Shale
Authors: Lindsay S. , Ables C. , Flores D. 
Published: March 2012

Abstract
The increased demand for natural gas from shale plays in the US has forced the industry to be more efficient and develop innovative methods for fracture-stimulation optimization. Pinpoint-fracturing methods represent a divergence from the conventional methods with minimal optimization needed to help maximize reservoir volume. Multiple-interval completions can be performed efficiently so that all intervals receive the designed proppant volumes, one interval at a time. To accomplish this efficiency, coiled tubing (CT) is used to hydrajet perforate intervals for individual fracturing treatments at predesigned depths. Using various methods, CT depths can be corrected to actual depths, resulting in the precise placement of the perforations. Proppant plugs are used not only for isolating previously stimulated intervals, but also for maximizing the near- wellbore (NWB) conductivity necessary for long-term production performance. These fracturing methods do not require removing the CT from the well between treatments, and contingencies for early screenout can be remediated immediately with minimal impact to overall completion costs. Treating intervals individually substantially reduces the amount of hydraulic horsepower required onsite.
The latest pinpoint-fracturing technique provides maximum engineering flexibility in the executionof these treatments by allowing downhole control of the proppant schedule; this can be used to optimize the stimulated reservoir volume (SRV) on- the-fly, in real-time, and with downhole control. The process also incorporates large-OD CT. A recent 25-interval completion in the Eagle Ford shale demonstrated the process and is discussed in this paper.
Concentric Coiled Tubing Well Vacuuming Provides a Solution for Flowline Hydrate Removal Offshore Brazil
Authors: Duque L. H. , Guimaraes Z. , de Almeida V. A , Chagas J. V. , Barros R. W. , Fonseca P. R. , Siqueira N. 
Published: March 2012

Abstract
One of the problems oil operators face in offshore fields in the production phase is the formation of hydrates in the production flow line, as well as in the gas lift injection line, on subsea wells. This problem is a consequence of the very common conditions in flow lines of submarine wells on production for some time, with high pressures, low temperatures and certain water in produced fluids. Once the hydrate is formed on either line, well production is compromised. Although several products and procedures have been applied to avoid this type of scenario, the problem persists, and operators must remove the hydrate plugs from gas lift and flow lines.
As those hydrate plugs are formed under high pressure (1400 to 2800 psi) and low temperature (2 to 4 ºC), exposing them to lower pressures even at the same temperatures will dissociate them. Hence, an operator offshore Brazil has for many years removed such plugs by injecting nitrogen in the lines and releasing the pressure at certain point, thereby reaching the lower pressures required to dissociate the plugs.
This procedure, although effective, is inefficient, as a floating rig is required to access the subsea Christmas tree and control over the pressure applied on the plugs is limited. As a result, most of the time the removal of thoseplugs takes weeks, making it a high-cost solution.
To find a more efficient solution, the operator and a service company joined in a technological cooperation agreement to test on two wells a field-tested concentric coiled tubing technology with a jet pump, to improve the control over the low pressure applied on hydrates formed in flow and gas lift lines.
This paper presents the case histories on those pioneering operations, the challenges found in offshore scenarios and the successful results of the application.
Intervention Operations in a Gas Salt Dome Storage Well Using E-Line Conveyed Inflatable Packers
Authors: Osorio Alejandro , Brooks Robert T. 
Published: March 2012

Abstract
A Natural Gas Liquid fractionation plant located in Ontario, Canada receives NGL feedstock from local industries in order to produce propane, iso-butane, and condensate. These finished products are stored in horizontal tanks and storage wells/salt caverns located within the chemical plant. One of these gas storage wells required two bridge plugs in order to create a barrier to enable workover operations to be undertaken.
The objective was to load the well with brine in order to perform a logging run and replace the wellhead. There were two challenges involved in this operation: the lack of a workover rig and ‘wellbore fluid’ for setting an inflatable bridge plug. TAM International’s SlikPak™ Plus inflatable bridge plug setting system was the optimal solution because its ‘carry fluid’ configuration is capable of transporting the necessary inflation fluid to set a bridge plug without a workover rig on location.
An additional challenge had to be overcome as well; both bridge plugs had to pass through a 7.6" (193.4 mm) ID wellhead restriction and inflate inside 13-3/8" (339.7 mm) casing. Therefore, during the first run, the inflatable bridge plug setting system had to carry twenty gallons (75.70 L) of inflation fluid within twelve 3-½" (88.9 mm) OD fluid chambers located along the toolstring in order to inflate and set the retrievable bridge plug. The client provided 105 feet (32 m) of lubricator and two cranes in order to perform a safe rig up of the 94 feet (28.65 m) long toolstring. The first bridge plug was successfully set at a depth of 2,040 feet (621.8 m) by stroking the mechanical Pull Intensifier. After the plug was set, the top section of the well was bled off and loaded with brine to enable the usage of the ‘wellbore fluid’ setting configuration, which successfully set the second bridge plug 31 feet (9.44 m) above the first one.
After the wellhead changeout took place, both bridge plugs were successfully equalized, deflated, and retrieved in order to re-enable gas storage in this well. It is expected that there will be similar operations on a nearby well in the future.
Ultradeepwater Riserless Subsea Slickline Intervention From Vessel of Opportunity: BC-10 Brazil Case Study
Authors: Gordon S. , Larimore D. R. , Cervo G. , Boechat N. , Klein M. , Buchan M. , Morris C. J. , Davis Scott 
Published: March 2012

Abstract
As the number of subsea wells in deepwater environments increases, companies who operate in these regions continue to seek safer and more viable economic solutions for improving value realization through well intervention. Traditionally, subsea well interventions are conducted from heavy-weight, mobile offshore drilling units (MODUs) with riser packages. Unfortunately, these intervention operationsinvolve significant operating day rates with consequent NPV negative results.
This paper discusses a riserless intervention that was performed from a dynamically positioned multi-support vessel (MSV) that involved setting and recovery of a mechanical flow-control device in a well with a water depth of approximately 1900 m in the South Atlantic Ocean. The technologies and methods used in this intervention proved that these difficult subsea operations can be performed in a much more flexible and financially viable fashion than previously possible with conventional methods. The techniques developed for this operation also mitigated safety concerns for personnel and equipment, while executing the potential high-risk riserless intervention with success.
The paper will cover the record-breaking, light-weight intervention and the technologies used on this campaign that eliminated the need for a traditional MODU. Of particular interest is the unique vessel interface that allowed the operation to be performed safely and efficiently with slickline.
This successful intervention opens new opportunities for safer and more economical interventions in the deep and ultra deepwater arenas.
Through-Tubing Sand Control Repairs Damage to Openhole Gravel Pack in a Subhydrostatic Well
Authors: Long N. , Moloney C. , Srisa-ard S. , Son N. H. 
Published: March 2012

Abstract
Remedial Sand Control is a challenging operation that requires economic judgment especially in brownfields. The operation turns into a greater challenge when the well, that needs to have a damaged gravel pack screen repaired is a sub hydrostatic well. We carried out pioneering repair project that was simple and cost-effective with minimum logistics using thru-tubing sand control. This method adapts thru-tubing tool advantages of coiled tubing to convey and set a smaller sand screen in a damaged gravel pack bore. The operation started by cleaning out in the deviated wellbore, controlling the well from kicks and deploying a long sand screen string in open-well conditions.
To use this technique, two main challenges had to be solved. First, a long sand screen string had to be deployed into the wellbore on a production platform without the assistance of the derrick or platform crane. We used a two-stage self-skidding jacking frame with a 4-ton hydraulic winch to deploy the screen string into the well. Each un-deployed component of the screen string was lifted up from the storage rack with an elevator and connected with the string in the wellbore above the Christmas tree by a hydraulic tong. The installed string was held above the Christmas tree by a pneumatic slip and bowl mechanism. Second, the method must control the well from unexpected kicks while the sand screen is being deployed. We used hydraulic hydraulic well control method, which involves spotting "damaged free" lost-circulation material (LCM) fluid along target intervals and topping up with kill fluid, we also prepared a mechanical solution as a back up during job execution.
Case Study: Successful Application of Coiled Tubing With Real-Time Data Communication System for Selective Reservoir Treatments Using Straddle Packer Assemblies
Authors: Oberascher R. , Breimer G. , De Jonge R. M. , Gesterkamp S. 
Published: March 2012

Abstract
Two gas wells in Germany showed a decline in production and wellhead pressures and were selected for acid treatments for skin removal. PLT measurements showed that certain reservoir intervals were not contributing to the gas production. To optimise treatment of individual zones a coiled tubing intervention with a resettable straddle packer assembly was chosen. Due to the depth-critical nature of straddle packer interventions, the use of an accurate depth correlation system was required.
Straddle packer well interventions were performed with real-time data communication, using a mono-conductor cable inside the coiled tubing. The robust data communication system provides real-time information from a Casing Collar Locator (CCL), down-hole pressure and temperature gauges and is suitable for use during acid treatments due to a protective jacket around the cable. Information provided by the CCL tool ensures depth correlations, whereas differential pressure measurements from the down-hole pressure gauges provide positive information about the setting and sealing conditions of the inflatable packer system. The combination of the down-hole real-time temperature and pressure readings allow full control during the injection process to avoid re-fracturing during acidizing. Furthermore, down-hole temperature readings can be useful for optimizing the corrosion inhibitor loading in acid recipes.
In this paper the real-time data communication system and the benefits in combination with straddle packers are discussed. Case histories in Germany illustrate the preparations, the execution and the lessons learned from selective treatment interventions with coiled tubing and real-time data communication in two gas wells.
After the treatments the production of the wells was increased by more than 10% in each well. The real-time in situ pressures and temperatures were a valuable input to the reservoir engineering model and further action will be based on the results. With the use of the resettable straddle packer several zones were treated in one run resulting in reduced operating time and thus a minimum in lost production.
Full-Scale Fatigue Testing With 130K Yield Tubing
Authors: Faszold J. , Rosine R. , Spoering R. 
Published: March 2012

Abstract
Coiled tubing (CT) is widely used in the well-intervention business as a practical and cost-effective means of servicing wells. Since CT’s inception, the use of continuous steel tubular has been the primary means of conduit for the applications required. The performance of CT has vastly improved throughout the years because of advancements in the tubing material and manufacturing processes, as well as extrapolated models predicting low-cycle tubing fatigue life. Because of these developments, CT has expanded to meet the increased demands of deeper and more rigorous wells. Utilization of new higher- strength grades of tubing plays one of the most essential roles for performing in these critical well applications.
This paper presents results from full-scale fatigue tests performed at several pressures on newly developed 130,000-psi (130K) minimum yield strength tubing. CT made with this new 130K material was cycled to failure in a real-world full-scale fatigue test setup. The collected fatigue-life values will help modify and validate the existing fatigue model used for CT job designs as well as lead to the development of a potential new model with further refinement for critical applications. This full-scale testing also verifies the correlation between tubing life observed in controlled, short-stroke lab-scale fatigue tests and real-world applications.
Selective Stimulation of Multiple Sets of Perforations With Straddle Tools: Lessons Learned Lead to Equipment and Methodology Optimization
Authors: Chow J. H. , Skaardal B. , Murphy R. , Fagley S. 
Published: March 2012

Abstract
Many of the more recent wells in the Ekofisk Field in the Norwegian North Sea have been completed as monobores with lengthy horizontal or high angle sections and several distinct perforation clusters – as many as 20 separate zones can occur. The early methods of stimulating these chalk reservoirs involved high volume acid jobs, featuring bull heading, and the use of frac balls to divert flow to the less permeable sections. However after collection and evaluation of much data it became clear that many of the perforated intervals were unproductive. In order to address this situation it was decided to change to a selective stimulation method using newly designed coiled tubing (CT) deployed straddle pack-off tools.
Subsequent evaluation of this method indicated that it was a more productive approach; however the reliability of the method was less than desirable due to equipment and methodology failures. This realization lead to a detailed study of these CT operations carried out over a period of 9 months involving evaluation of the results of stimulating 9 separate wells with perforation sets ranging from 7 to 20. The study involved review of equipment design and function, material choice and methodology such as pumping techniques, use of glycol trains, accuracy of depth measurements, reliability of pressure measurement equipment etc. with the objective of optimizing them for future operations.
In this paper the authors will briefly review the history and results of the initial stimulation of these wells and the decision to go to straddle pack-off methods. They will then describe in detail the results of the study to evaluate and improve equipment and techniques, the lessons learned and the changes that resulted, leading to more reliable and effective stimulation techniques that are now being used.
Influence of a Straightener on Coiled Tubing Fatigue
Authors: Tipton Steven M. , Smalley Ed , VanArnam Don 
Published: March 2012

Abstract
When coiled tubing exits the injector on its way into the wellbore, it contains residual curvature as a result of prior bending events (i.e. being wrapped around the coiled tubing reel). Coiled tubing straighteners are being used increasingly during field operations to remove this residual curvature in order to help delay the onset of coiled tubing lockup and successfully perform work in extended reach wellbores containing long horizontal intervals.
To straighten the coiled tubing, rollers are used above the injector to apply bending in the reverse direction of the residual curvature. After the tubing exits the straightener assembly, the residual bend of the tubing will have been mitigated and the tubing will spring back into a predominantly straight line. However, the reverse bend applied during the straightening process increases the overall strain range experienced by the tubing and should adversely shorten its fatigue life. Accurate estimation of cumulative fatigue damage along the tubing is critical for making decisions about retiring strings prior to tubing failure, which can result in injury to personnel, equipment damage, unplanned release of fluids at surface, as well as costly fishing operations.
This paper presents a methodology to quantify the incremental fatigue damage imparted on the tubing as a result of coiled tubing straightener use. An analytical technique is presented to compute the reverse bending radius required for tubing straightening and to quantify its subsequent influence on incremental fatigue experienced by the tubing. The analysis shows that only the radius associated with the tubing reel affects the residual curvature of the tubing under normal field operating conditions. It is also shown that it is not necessary to release the straightener during POOH operations to avoid incremental fatigue damage from straightener use. A case study is presented and fatigue life reduction is estimated on the order of 30% for the example tubing size and grade and the geometry of the deployment hardware. A test program is discussed to explore the influence of these parameters.
The Effects of Fluid Hammer Tools and Lubricants on Plug Milling Efficiencies - A Comparative Study
Authors: Schneider Christopher , Castro Luis , Craig Steven , Maddy Timothy 
Published: March 2012

Abstract
Long-reach horizontal wells with "Plug and Perf" completions are commonly used to achieve economic production in today’s unconventional reservoirs. After the multistage fracture stimulation operations are completed, coiled tubing (CT) is often used to remove the plugs. However as the lateral reach of wells increase, plug removal using CT becomes less efficient as weight on bit (WOB) decreases. Over the last few years, various fluid hammer tools have been introduced to the industry and have improved plug milling times significantly.
This paper will review the results and operational improvements observed from milling operations using both fluid hammer tools and/or lubricants. Data from shale formations across the U.S. (Eagle Ford, Bakken, Haynesville, Barnett and the Marcellus) is included. Analysis from the use of three types of hammer tools and/or lubricants will compare results to those of base case operations completed without fluid hammer tools or lubricants.
The paper will detail improvements in milling efficiencies, number of stalls, and stuck pipe incidents. Results will focus on when to run hammer tools and when to introduce pipe lubricant to achieve optimum efficiencies.
Many operators rely on word of mouth to design and perform extended-reach CT milling jobs. This can result in poorly executed, ‘non-engineered’ plug milling operations. This paper will provide data to assist operators in improving their completion efficiencies
Improving Coiled Tubing Plug Drillout Operations in Shale Gas Completions
Authors: Rowden Vanessa , Carlile Joddie , Chavez Manuel 
Published: March 2012

Abstract
The tight margin nature of shale gas plays puts the pressure on operators to strike that optimal balance between cost and production gained. This effect is magnified by the ‘manufacturing mode' mentality that operators are striving for to get the most wells in the ground efficiently, cheaply, effectively, and safely as possible. This approach of course extends to every operation in shale gas completions, including coiled tubing plug drill-outs (CTDOs). This paper reviews one operator's quest to achieve this ‘balance' in CTDO operations as well as overcome technical challenges in two different shale gas plays - the Haynesville and Eagle Ford Shales.
Production Logging on Coil Tubing in a Marcellus Shale Horizontal Completion
Authors: Mccluskey A. 
Published: March 2012

Abstract
Production logging plays an important role in understanding the impact that well trajectory, completion practices and trials, and well placement have on EUR. The data can further help to characterize the reservoir in new plays. This is particularly true in the case when both water and gas production deviate dramatically from expectations. Logging helps to answer the questions: Are all zones and perforating clusters producing equally? Is the toe unloading? What is the flow regime? Is water production isolated to a particular interval? Can it be shut off?
In traditional vertical wells, electric line logging is most often used to acquire production data. In a horizontal well, both active and memory tools can be deployed on coil tubing to acquire production data. Using coil tubing for production logging has its own unique challenges, one of which is getting to TD without damaging the tools. The difficulty of this challenge can be compounded by long lateral lengths and high dog leg severity.
Well trajectory, well flow regime, water rate, and gas rate all have an effect on choice of logging tools and method for deployment. This paper will discuss two production logging attempts: 3 successful logs with active tools and 1 failure with memory tools. The one failed attempt involved a low gas rate, low pressure, high water rate well with severe dog legs near the heel where the coil could not reach the logging interval.
The sections in this paper will discuss the role of an effective cleanout and how to achieve its success as well as best practices for acquiring high quality production data. Each of the four logging jobs will be discussed in detail with results provided.
Optimizing Coil Tubing Extended-Reach Capabilities Through the Application of Downhole Friction Reduction Tools
Authors: Hilling S. , Ayling G. , Yeung J. 
Published: March 2012

Abstract
The demand for drilling and completing horizontal wells in both conventional and unconventional oil and gas plays has drastically increased in recent years. A growing economic and environmental appetite for ever increasing horizontal lengths continues to apply pressure on drilling and completion technologies. Although well engineering programs have improved and adapted to solve some of these issues, coil tubing reach capabilities can, at times, become the limiting design factor for horizontal wells. To tackle this issue, the industry has developed and adopted the use of downhole friction reduction tools to optimize and extend the range of coil tubing.
Using case history from Shell Canada’s Groundbirch shale gas development, this paper will compare and analyse the effectiveness of three different downhole friction reduction tools currently available to industry. While this paper will discuss the use of Tubing Force Analysis (TFA) modeling software to obtain representative values for comparison, the focus of the study is to compare the overall effectiveness of the three friction reduction tools using actual field data.