bluuebunny/crossref_metadata_2025 huggingface dataset:
Effects of Alternative Water Sources on Formation and Proppant Pack Damage Reduction Properties of Near-residue-free Fracturing Fluid
Authors: Russell Aaron , Singh Dipti , Schnoor Eli
Published: June 2014

This paper examines how the use of high-salt-content waters (i.e., produced and flowback water) in conjunction with a recently developed, virtually residue-free (res-free) hydraulic fracturing fluid affects the cleanup properties of the system. The res-free fluid system is designed based on a naturally low residue polymer that, when breaking, causes significantly less damage to the formation and proppant pack compared to conventional guar-based fracturing fluids.

Since its introduction, guar-based fluid technology has grown to dominate the hydraulic fracturing industry because of its reliability and cost-effectiveness. However, guar gum contains a significant amount of insoluble residue that is not removed during its processing. The residue can cause damage to both the proppant pack and hydrocarbon-bearing formation when the broken fluid is flowed back following the fracturing treatment. This damage can impair hydrocarbon flow from the formation and through the propped fracture, resulting in lower production over time. The res-free fluid offers better cleanup when breaking than guar-based fluids; therefore, it offers significantly higher proppant pack conductivity and formation permeability in laboratory testing.

The res-free polymer exhibits sensitivity to certain ions present in the solution, both in terms of gel hydration and crosslinking behavior. Depending on the ions present in the water and their respective concentrations, manipulation of the crosslinked res-free fluid system chemical formulation can mitigate these effects and achieve a stable, highly viscous fluid suitable for hydraulic fracturing. This paper investigates whether the necessary reformulations impact the regained permeability and conductivity of the fluid system. Rheological data demonstrating how the reformulated fluid compares to standard formulations is presented. Additionally, test results are presented highlighting the effects of alternative water sources on res-free fluid regained permeability and conductivity data.

The use of produced and flowback waters for fracturing operations can substantially reduce both the economic and environmental impact of fracturing operations. The combination of the res-free fluid's ability to use these water sources and its excellent damage-reducing properties provides a system with significant advantages compared to conventional technologies in many applications.
Breathing Second Life into an Old Well through Coiled Tubing Cement Squeeze for Brownfields in Malaysia
Authors: Khor Y. Y. , Ismail M. S. , Prahawinarto B. , Mohamad M. H. , Sin N. H.
Published: June 2014

BY, an offshore oil field discovered in 1976, has been in production since 1984. Several production enhancement activities were continuously conducted throughout the production life of the field. This includes surveillance works to arrest the production decline and enhance the oil recovery.

A systematic investigation showed that a few wells were having anomalous high water production despite being located at the crestal area of the reservoir. Further investigations revealed that poor cement bonding behind the casing was the main cause of high water production in the up-dip wells. With this new information, an evaluation of the remaining reserves was carried to justify any remedial well work required to reactivate the wells.

A coiled tubing cement squeeze job was identified at BY field to unlock the well potential of the watered out well located at the crest of the reservoir. The well, WELL-X has been idle for over 20 years due to high watercut. After a successful job execution, the well was able to flow with more than 1000 STB/D at 0% water cut. This has opened up more opportunities for idle well reactivation of other idle wells with similar high water cut due to cement channelling issues behind casing.

This paper presents an established workflow and optimization cycle adopted in BY highlighting the methodologies/techniques used to identify potential production opportunities that may have been overlooked in a brownfield and a recommendation on the way forward. The systematic workflow applied displayed success in a well using rigless intervention and has achieved economic return in a short time.
Improving Coiled Tubing Operational Capabilities to Overcome New HP/HT Challenges in Mexico Offshore
Authors: Solis Ulises , Perez Jose , Franco Ernesto , Ortega Ruben , Marin Marlon , Murillo Andrea , Reichert Bruce , Grimaldo Carmen
Published: June 2014

Over the last years the oil and gas Mexican operator’s exploration and development programs are becoming more challenging due to the complex conditions where hydrocarbons are found today. One of the areas that have seen a decline on production over the years is the offshore. As an alternative to find new sources of oil that overcome the current production decline in the area, the operator is drilling new wells where the operational capabilities of the equipment are put out of their limits. These new wells are drilled at depths beyond the conventional 5,000-m (16,400-ft) with bottom hole pressures as high as 15,000-psi and temperature over 180°C requiring that the equipment providing the services over their producing life reach their own limitations and in some cases re-engineering of the design and process has to be done.

In some cases, minimum changes to the equipment or processes are enough; however, a service of such complexity as the use of Coiled Tubing (CT) requires a major review of all the components of the operation to be completed in order to reach the new targets without jeopardizing the safety of the operations and/or compromising the production of the well.

This paper details the CT string design criteria to reach the deeper vertical depths with high wellbore mechanical friction coefficients while withstanding high pressures; equipment selection, to allow greater CT length capacity on reel and higher pulling capacity on injector head; platform and crane specifications to withstand over dimensioned equipment, as well as, a case study to analyze equipment and CT string performance for interventions on these types of wells.
New Chemical Treatment Selectively Placed via Coiled Tubing to Isolate Depleted Upper Zone Allows for Access and Stimulation of Unproduced Lower Zone
Authors: Dashash Alaa A. , Malik Ataur R. , Mukhliss A. E. , Al Yaseen A. H. , Albuali M. , Haekal M.
Published: June 2014

Completed with 4.5 in tubing and 7 in Liner, the upper carbonate reservoir had previously been stimulated and produced until reaching its economic potential. To prolong the well life, the decision was made to permanently isolate the upper zone, then perforate, matrix stimulate and produce from the lower zone.

The challenge for this operation was that the existing upper zone had been stimulated, creating a large void behind the casing with known high fluid loss. It was determined that isolation with cement would have only a small chance of success due to the high leak-off in the previously stimulated reservoir. Also, this zone was at a 40° inclination, making it more difficult to place an uncontaminated cement plug with Coiled Tubing (CT) and clean out the cement after placement.

An inflatable packer was also considered to isolate the upper zone and perform acid stimulation on the bottom zone. The bottom-hole pressure and temperature (5,000 psi and 300°F) were beyond the operational limits of any inflatable element available in the region.

For this unique situation, a new method was designed and successfully implemented. The new approach included first filling the upper zone with calcium carbonate chips (CaCO3) to reduce or limit the fluid losses. Then, utilize CT to place a chemical isolation treatment. The product utilized was an organically cross-linked polymer (OCP) system capable of permanently sealing the target zone by forming a 3D rigid gel. It is effective for preventing water and gas flow in sandstone and carbonate formations from 100°F to 350°F (38°C to 177°C). A benefit of the treatment was the ease at which it could be pumped and placed via CT and then cleaned out. All that is required for cleaning is a nozzle and jetting action. The implementation of this chemical sealant procedure provided reliable zonal isolation of highly depleted upper zone and allowed full access (with CT, Slick Line and E-line) to deeper productive lower zone. The successful chemical isolation in this well has resulted in avoidance of expensive workover operations.

This paper discusses the pre-job planning, benefits, challenges, design, execution, evaluation and lessons learned for applying this novel isolation method.
Next Generation of Battery Operated Electromechanical Setting Tools Increases Reliability at High Temperatures
Authors: Zbitowsky Ron , Al-Buali Mustafa , Clemens Jack , Denmon Michael , Dove Johnny , Gordon Scott
Published: June 2014

As exploration wells reach new depths and environments previously unexplored, the need for intervention services at higher temperature becomes a critical decision point for the entire drilling and completion process. Traditionally, the ability to set wellbore devices at elevated temperatures relied heavily on electric line services due to the higher temperature rating of explosive setting tools or surface powered electromechanical devices. This, of course, relied heavily on the availability and logistical expediency of units, tools, and personnel to avoid any nonproductive time, which could result in costly delays. An alternative would be using drill pipe; however, this could result in an excessive number of hours being added to the intervention process, increasing the overall costs to the developer. Due to these factors, companies continue to try to develop cost-effective intervention solutions while increasing reliability when operating in more hostile environments. Memory tools are fast becoming a favorable and more economic option.

Battery operated electromechanical setting tools have been around for many years and continue to evolve. The latest generation of setting tools has allowed advanced memory and command logic to be incorporated, providing more flexibility in the intervention routine as well as a thorough understanding of the recorded downhole event. The tool also has the added feature of a flasking system, allowing a much greater operating envelope when exposed to high downhole temperatures. This makes the use of an alkaline battery powered setting device, deployable via a multitude of conveyance methods, a safer and more cost-effective method.

This paper will review the new features and designed uses of this industry respected tool. Case histories with the device to complement intervention needs and operational planning convenience will be submitted to support the inherent value added to the oil and gas industry.
Electric Line Tractor-Based Conveyance in High Temperature Wells: A Collection of Local Case Stories
Authors: Peoples Matt , Hammill Tim , Alferez Olivier , Murrill Gary
Published: June 2014

Texas and Louisiana are not typically thought of as extreme environments, but the Haynesville and the Eagle Ford do have some hot and deep areas that are being developed. High temperature environments require specialized, robust intervention tools designed to withstand longer periods of extreme heat.

The industry’s definition for ‘high temperature’ ranges from 300°F to 400°F. Working in this environment requires careful preparation, as well as proven, reliable service providers and equipment. Established electric line tractor-based technologies running on AC power, as well as DC equipment have proven their application in these harsh and unforgiving environments. They offer additional benefits like reduced personnel and less heavy lifting, making these technologies inherently safer.

This paper will share the learnings from a number of local operations in which this electric line technology has been deployed, including advances with DC electronics and some examples of AC electronics cases ranging from conveyance of logging tools to plug and perforating for fracture stimulations.

In addition, this paper will examine the differences between AC and DC electric line equipment, their application in high-temperature environments, as well as discuss current trends within electronics for electric line equipment and future outlook for high-temperature equipment.
Use and Placement of Resin Blends to Effectively Isolate Existing Perforations when Fracture Stimulated Productive Horizons are below Existing Perforations: A Case History from the Middle East
Authors: Sierra Leopoldo , Noguera Jose
Published: June 2014

Hydraulic fracturing is the preferred method for enhancing production rates and hydrocarbon recovery, as well as for maximizing the productivity of conventional and unconventional reservoirs. To optimize the effectiveness of the treatment and maintain wellbore integrity, the stimulation process should be designed and executed with both the wellbore configuration and target formations in mind. For wells in which multiple fractures are required, stimulations are normally performed sequentially, from the bottom layer to the top layer; however, open perforations above the target zone (whether fractured or not) can present significant challenges during the stimulation process. For these cases, the preferable solution has been to isolate the perforations using the cement-squeeze technique, but this process is not completely effective because of short penetration. The fragility of the cement slurry under typical stress cycles associated with the fracturing process or the complexity of the process could compromise the existing perforation integrity and the effectiveness of fracturing the lower zone. Alternatively, the well can be recompleted to isolate the zone mechanically, though this involves a rig operation, which, in zoned areas, is not cost-effective.

One effective method to isolate existing perforations and help ensure deeper penetration of the isolation system without pulling out of the completion is squeezing a resin-based system with sufficient plasticity to maintain the isolation integrity under normal stress cycles. This paper documents the first application of resin blends to isolate existing perforations for the fracture stimulation of deeper prospective horizons. This isolation and stimulation process follows these steps: (1) the resin blend is squeezed into the wellbore using coiled tubing (CT); (2) the remaining resin blend is cleaned up using CT and a pressure test is performed; (3) the deeper horizon is perforated; (4) a minifrac and temperature survey are performed to evaluate existing perforation isolation; and (5) the fracture stimulation and production evaluation are performed.
Recent Developments to Coiled Tubing Equipment Design Improves Efficiency and Safety
Authors: Thomson Iain
Published: June 2014

To meet the demand for energy, operators are turning to development of unconventional resources. It is estimated that there are more than 750 trillion cubic feet of technically recoverable shale gas and 24 billion barrels of technically recoverable shale oil resources in discovered shale plays in the US alone. Tight rock in the longer horizontal shale-oil plays requires both longer lateral wells and multistage fracturing to maximize oil recovery. Coiled tubing (CT) plays an essential role in post-frac cleanup, requiring both safe and efficient equipment.

Unconventional shale well construction has taken on a factory construction approach, with more than 20,000 horizontal wells being drilled each year in the US. These long lateral lengths require larger CT units (CTUs) with larger outside diameter (OD) strings, which often increases the number and size of the equipment loads necessary to service the wells. Service providers are being challenged with ways to increase the speed and efficiency of these larger service packages, while maintaining or improving safety performance.

This paper discusses how the unique design of a mast unit trailer and associated equipment meets this challenge with its 5 1/8-in. preassembled well control equipment (WCE) stack and its ability to contain a full milling assembly combined with a fluidic oscillator in its riser stack. The system has also been designed to be versatile and enables a variety of WCE sizes and configurations to be mounted on the trailer to help ensure customized solutions to many operational challenges.

The system offers substantial improvements in terms of rig-up time compared to a conventional CTU. Field trails have shown the preassembled WCE stack can significantly reduce rigup time by as much as 50% by reducing the number of bolts required to be made up and torqued on site.

The paper also explains how the unique design improves operational safety. With the reduced number of bolts required to be made up onsite, hand and finger injuries associated with hammer wrenches and dropped objects can be vastly reduced.

When the trolley is raised and latched into position, dangers associated with making up a bottom-hole assembly (BHA) directly under a suspended crane load have been removed. Even if the crane were to fail, the mast and trolley is designed to sustain the entire load of the injector, stripper, riser, and blowout preventer (BOP).
Coiled Tubing Operations on a Multi-Service Vessel for Deep Water Well Interventions in the Gulf of Mexico: A Decade of Experience
Authors: Rudnik Alexander , Torres Carlos Alberto , Ottolina Renny Alexis , Rourke Jonathan , Barber David
Published: June 2014

Demand for subsea well intervention work has continued to be strong for the last 10 years. Even though subsea well interventions from an intervention vessel represent only a fraction of the total well workover activity in the Gulf of Mexico (GoM), its operating environment poses challenges in meeting economic goals for the Operators. The Q4000, a purpose-built, multi-service dynamically positioned (DP) vessel, was first introduced in the GoM in April 2002 and has been extensively used to meet demand of subsea well intervention and abandonment. Coiled tubing (CT) intervention, along with Slickline and Electric Wireline, has been instrumental in supporting the Q4000 ability to maintain safe, reliable, and cost efficient subsea through tubing well interventions in such a demanding operating environment.

This paper will summarize the operational experience and will focus on the CT-specific best practices and lessons learned that have resulted from over than 10 years of continuous operations on the Q4000. The document will highlight critical stages in the learning curve, standardized procedures, synergies between the CT and the Q4000 crews, and their impact on safety, efficiency and cost reduction. The paper will also discuss the needs for further improvements that will be required to meet the new challenges that subsea well intervention will be facing in the future.
Challenging Through-Tubing Intervention Succeeds Despite Extreme Well Conditions
Authors: Colmenares Franklin , Lopez Andres , Qutob Anas
Published: June 2014

The subject well, located onshore in the Kingdom of Saudi Arabia, had approximately 9,000 ft of 2.00-in coiled tubing lost in the wellbore, and was requiring thru-tubing intervention to recover the parted string and subsequently abandon the well. The string was lost following a failed cementing operation that left the string stuck due to 2,000 ft of cement inadvertently setting in the coiled tubing-production tubing annulus. Additionally, the lost coiled tubing had an inconel fiber optic cable (IFC) running through it, which presented an additional challenge in recovering the tubing from the wellbore. Downhole conditions were extreme, with 42% hydrogen sulfide and 10% carbon dioxide emitting from the wellbore. Operational conditions were also a major constraint, as the drive fluid was mud with 16% solids content, along with mud which had "packed off" in the coiled tubing-wellbore annulus. These factors created great challenges, and meticulous planning and execution was required to prevent critical well-control problems throughout the intervention operation.

The operation began with a rig-less coiled tubing operation to polish the top of the "fish" and permit access for a fishing assembly to begin recovery of the string. This was followed by the deployment of a workover rig to provide a more effective and time-efficient platform to recover the string. Following the string recovery, the 4.5-inch heavy-walled tubing required severing to commence the abandonment process. This paper will describe the challenging operation to recover the coiled tubing from the wellbore and sever the heavy-walled tubular, with all cautionary measures taken to mitigate well-control hazards and avoid lost-time safety incidents.

The operation was concluded with most of the string recovered without any lost-time incidents. More than 62 runs were conducted, both rig-less and rig-supported, with the IFC coiled tubing string being recovered in 100- to 500-foot sections. Despite the heavy mud and high solids content, the heavy-walled tubular was cut successfully using a hydraulic cutter, which allowed for its subsequent recovery.

Given the extremely sour down-hole conditions, along with the multiple challenging operational factors, this case presents an application with a unique set of unconventional circumstances which usually prohibit the successful recovery of lost strings. This case also demonstrates how careful planning, round-the-clock technical support and effective execution were the cornerstones of a successful intervention with extremely challenging conditions.
Steel Coiled Tubing Defect Evaluation Using Magnetic Flux Leakage Signals
Authors: Liu Zhanke , Minerbo Gerald , Zheng Andrew
Published: June 2014

Mechanical defects, such as manufacturing imperfections, grinding marks, corrosion pits, slip marks, kinking, gouges, etc, whether occurred in the factory or in the field, can be readily found on CT strings. Extensive studies have demonstrated the detrimental effects of mechanical defects, over the integrity of the coiled tubing, both in the lab and in the field. Researchers in the field have been proposing theoretical models for the severity assessment of mechanical defects, particularly as it relates to the remaining fatigue life. For such models, the defect sizing is usually a prerequisite. In order to improve coiled tubing pipe management, it is important to assess the size of a defect, and its severity.

MFL (magnetic flux leakage) based devices are volumetric and non-contact technology that is now commercially available for inspection and monitoring of CT strings. These devices have been demonstrated to be sufficiently sensitive in identifying mechanical defects. However, defect characterization and evaluation based on the devices’ MFL signals is rarely seen. To fully utilize these MFL based inspection devices for coiled tubing pipe management, it is important to establish correlation between the MFL inspection signals and the geometry and severity of the underlying mechanical defects.

The current work developed a three dimensional Finite Element Analysis (FEA) model to calculate magnetic flux leakage for mechanical defects on steel coiled tubing. The fidelity of the FEA model was verified against analytical and experimental results over a series of benchmark defects. By using the analytical and FEA models, parametric studies were performed to evaluate how the MFL signals are affected by various factors. The results were used to identify defect geometry features based on MFL signals. Physical limits behind these results were identified and analyzed. Ways to overcome such limits were proposed. Further, a novel approach was presented and validated to reconstruct three-dimensional MFL field based on a single MFL component measurement. The benefit of using multiple MFL components was demonstrated for defect characterization.
Modeling and Validating Pressure Transient Effects on Inflatable Bridge Plugs during Coiled Tubing Conveyed Perforating
Authors: Xu Ron , Shamisheva Assem , Bucher Robert
Published: June 2014

It is known that the performance of inflatable packer is susceptible to the pressure change after it is set. When setting an inflatable bridge plug and then perforating nearby, it was "conventionally" believed that inflatable plug would fail when subjected to the perforating gun-shock loads. A common practice to protect the inflatable from these shock loads is to place an additional barrier to absorb these loads.

During one such instance, an offshore operator required setting an inflatable bridge plug and then stimulating the zone above it. However, after the plug was set, a contingency came up as it was not possible to open SSD of this zone. In order to stimulate this zone, perforating this zone was requested by the client. Due to the time and equipment limits, placing an additional barrier above the plug to protect it from the gun-shock loading was deemed impractical and seen as an unnecessary operational delay.

In this proposed perforating operation, the risk caused by the pressure surge from perforating to the inflatable plug had to be evaluated. Risk evaluation requires the modeling of the perforating-generated pressure surge. This paper presents a methodology to simulate pressure transients reliably both in magnitude and time and evaluate the risks involved with the inflatable plug. The impact of these pressure transients on the inflatable plugs can then be analyzed during job planning. This methodology enables engineers to evaluate the job risks, mitigate these risks, and then be able to optimize the operation design.

One case study will be presented in this paper. With the ability to predict the pressure surge, a decision, such as whether or not to need an additional barrier between the perforating gun and inflatable plug to absorb the pressure surge, can be made, and a successful operation of inflatable plugs with perforation can be expected.
Successful Application of Fiber-Optic-Enabled Coiled Tubing and Inflatable Packer Used for Testing the Formation’s Upper Zone
Authors: Gonzalez Carolina , Muñoz Johana , Orozco Natalia , Higuera Josue , Nava Dubrasky
Published: June 2014

Floreña field, located north of the Cusiana and Cupiagua fields, has been producing since 2001. Floreña field is part of the series of thrust sheets developed as result of the Eastern Cordillera uplifting.

In order to determine pressure depletion, establish connectivity between wells, reduce the risks of geological uncertainty along the field, and meet Ministry of Mines data acquisition commitments, we performed a pressure buildup test using inflatable packers as the isolation method.

In the past, when a pressure buildup test was required in the well’s upper formation, operators had to set up a bridge plug in the lowest part of the tested formation, set up a sand plug, and finally, pump a cement plug. These extra steps increased HSE risks and project costs.

A synergistic approach using real-time down hole measurements from fiber optic coiled tubing were combined with the cased hole inflatable packer to improve operation reliability while reducing risk of failure and time.

The availability of real-time logging casing collar locator (CCL), annular, coiled tubing (CT) bottom hole pressure, and bottom hole temperature data allowed the inflatable packer to be set properly. The measurements helped ensure adequate packer inflation, monitor the maximum draw down without exceeding the packer integrity, and perform a well test to a specific formation in just one run. In addition, the BHA configuration allows a memory tool down the packer to record the lowest formation static pressure.

After the pressure buildup test was performed, the results showed well connectivity with Florena Field. The test also confirmed reservoir pressure and permeability, which helped in future job and field planning.
Optimizing Horizontal Wellbore Design to Extend Reach with Coiled Tubing
Authors: Forrester J. , Yeung J. , Marzara F.
Published: June 2014

There has been a recent increasing trend in the number of horizontal wells being drilled in recent years. Wellbores are being drilled with various designs that often overlook challenges faced during the completions phase of the wellbore operation. As a result, wellbore intervention has faced some challenges when servicing wells. Although well engineering programs have been developed to optimize the design of the wellbore; one of the limiting factors of wellbore design has become coiled tubing reach capability and set down force at the end of the coil. To address this concern this paper looks to examine the effect of wellbore design on the set down force provided at the end of the coiled tubing string.
Optimizing Frac Plug Mill Outs in Horizontal Wells using Coiled Tubing
Authors: Pawlik Michael , Champagne Jonathan , Whitworth Jeff , Trebing Cody
Published: June 2014

Due to the current market price of natural gas, operators have needed to reduce the overall costs associated with completing a well. Specifically, steps have been taken to significantly lower the costs associated with the mill out of composite frac plugs and frac sleeves using coiled tubing (CT). Shell’s Eagle Ford group has successfully ventured away from traditional milling procedures that included numerous short trips, sometimes referred to as wiper trips. By incorporating a scientific approach and optimizing fluids system technology and bottomhole assembly (BHA) designs, these new methods have enabled us to eliminate short trips all together and produce cleaner wellbores. Ultimately, these new practices have achieved significant reduction in cost and time.

This paper will discuss the past coiled tubing performances and the need for changes. Analysis and theories used to implement and optimize Eagle Ford coil tubing operations will be reviewed. It will review and discuss the changes made such as fluid Quality assurance and controls (QA/QC) improvements, coiled tubing selection, and BHA design. These changes resulted in significant reduction in both cost and time per well and cycle time on a multi well location. These changes are now fully implemented and are the new standard for Shell’s Eagle Ford coiled tubing operations.
High Tension Electrically Controlled Release Device Improves Reliability Of Stuck Tool Release In The Gulf Of Thailand
Authors: Surapakpinyo Kittichai , Hanchalay Chutinthorn , Fundytus Nicholas , Ford Ronald , Pakdee Sawai , Sarian Serko , Battula Arvind , Nery Nadir
Published: June 2014

In a tool stuck situation, wireline conveyance systems incorporate a downhole mechanical weakpoint to safely release and retrieve the logging cable during or prior to pipe conveyed fishing operations. In wells with high tension profile and long open hole sections, the weakpoint strength should be carefully selected to ensure high pulling capabilities in shallower sections of the well while not exceeding the cable safe working load (SWL) in deeper sections of the well. To overcome this limitation, electrically controlled release devices (ECRD) were introduced in the past. Release is only possible with a surface command. As such full pulling capability is maintained at all times and depths. The swap however, introduced new sets of challenges such as full tension drop requirement for mechanical release and a labor intensive tool preparation procedure. As a result non-release incident rate increased leading to high risk and costly recovery operations. To minimize this risk, clients often have to reduce or cancel wireline logging programs leading to missed critical well data.

To address the limitations of ECRD type weakpoints, Chevron Thailand E&P, LTD commissioned Schlumberger to address such challenges. The project was completed in Dec 2011 with the introduction of SureLOC 12000. Improvements include release with 1000 lbf of cable tension, 12,000 lbf (up from 8,000 lbf) of safe operating pull and substantial reduction in maintenance and redress procedures. Reliability has since improved by 75% allowing Chevron to acquire full data in wells where logging operations would have been otherwise cancelled. The improved reliability and increased operational range of the new device have allowed Chevron to safely carry out Wireline logging operations and achieving well data acquisition targets with substantial financial benefits.
Improving Post-Stimulation Coiled Tubing Drillout
Authors: Asafa Kolapo A. , Williams Brandon T. , Gonzalez Armando , Wiskofske Michael T.
Published: June 2014

In the last few decades, coiled tubing has been widely employed for post-stimulation drillout of composite or cast-iron bridge plugs and isolation sleeves used in multi-stage hydraulic fracture stimulation in horizontal wells. Due to its inherent capability of continual deployment, coiled tubing technology has increased in popularity for this application over conventional jointed-pipe snubbing with rig-assist snubbing units. Despite the increasing use of coiled tubing units, drillout practices have typically been based on "art" rather than science, often resulting in drilling problems such as poor fluid efficiency and hole cleaning issues, lost circulation, stuck pipe, lost-in-hole tools, and parted pipe. Unfortunately, a greater percentage of stuck pipe incidents are directly related to poor hole cleaning, and it is not surprising that the causes of these problems are often not well understood. Thus, various approaches have been utilized to prevent recurrence based on incorrect assumptions. While some of these problems have been adequately dealt with in several publications, the determination of optimum fluid properties for efficient hole cleaning as well as the effectiveness of short tripping have been given minimal attention. To a large extent, fresh water, or brine, is mixed with various additives such as friction reducer for pressure loss and pipe friction, hydrogen sulfide scavenger and inhibitor, biocide, scale inhibitor, and polymer gel while drilling plugs. A common hole cleaning practice is the use of intermittent high-viscosity gel sweeps, wiper tripping to kick-off point after drilling a predefined number of plugs, and flowing back the well in an underbalanced condition while drilling and short tripping. The effectiveness of these practices is worth questioning based on the occasional drag and stuck pipe encountered while tripping out of hole.

This paper addresses the misconceptions related to coiled tubing hydraulics and hole cleaning, as well as reviews the common drillout practices and their cost implications including coiled tubing rig up, coil size selection, bottomhole assembly, fluids efficiency, and short tripping. Various best practices are recommended for improving post-stimulation drillout, with specific emphasis on how to minimize drillout cost.
Milling on Extended Horizontal Sections, Choice of Methods: Case Histories from the Chicontepec Area, Mexico
Authors: Ortiz Jose Ramon , Montes Efren , Ramirez Luis , Gutierrez Guillermo
Published: June 2014

The Chicontepec basin in the northern region of Mexico has experienced an increase in the application of completion technologies using fracturing sleeves (FSs) activated by baffles in long, extended horizontals. Because of the oil’s high viscosity in that zone and the inherent decrease in initial production, the milling of such FS baffles has become a necessity. Milling jobs have proven to be difficult using conventional coiled tubing (CT) milling methods, tools, and processes. Analysis of previous variables, well constructions, CT strings, and CT equipment led to the development of an unconventional work method that has been applied with success in more than 12 wells in the region.

CT milling operations rely heavily on two variables—the amount of effective weight on bit (WOB) that is applied over the obstruction and the torque generated by the tool. An intervention in a long, extended horizontal using CT implies the following constraints:

Normal force of CT in the extended section. Friction caused by the previous normal force. Friction pressure loss resulting from limited CT diameters and lengths.

While observing the long time intervals involved with most interventions and a few events in which the CT became stuck, a new intervention method was developed. Highlights of this method include the following:

Specific bottomhole assemblies (BHAs) for milling and cleaning of debris generated. Static friction reducers. Pressure friction reducers. Staged milling/cleaning work method of the total amount of FSs.

The first deployments of the combined work method were observed with caution and were not fully supported by the customer. The staged milling was supposed to increase the operating times in these interventions. However, by the time the third well was milled using this method, this perception began to change because of comparisons between the time lost during unwanted events, such as the tool becoming stuck and difficulty during milling. Previous events had reduced the occurrence of these issues in the last 12 wells and the use of associated FSs.

The importance of this work method is evident by the observed reduction in overall intervention time, delivering production earlier with no quality issues for the Chicontepec area.
Beyond Logging: Slickline Operations Can Now Provide a More Efficient and Cost Effective Alternative to Traditional Intervention Operations
Authors: Loov R. , Billingham M.
Published: June 2014

Digital Slickline’s capability and flexibility is providing operators with the opportunity to re-think traditional well intervention methodology. The technology provides both traditional mechanical Slickline services in addition to a range of real time downhole measurements enabled by a coated conventional slickline. Digital Slickline does enable multiple services such as production logging and perforating on demand but further significant value is being found when used performing conventional mechanical operations.

This paper will discuss carefully planned and engineered solutions where Digital Slickline was used. In one example it provided a means to accurately correlate the depths of completion components, allowing for the accurate setting of a mechanical isolation plug. The integrity of the plug isolation was verified by use of downhole pressure and temperature measurements. Additionally the upper zone sliding sleeves were located accurately, opened successfully and resulting desired production well flow verified by conducting pressure and temperature logging passes. In another example the technology was again used to prevent separate runs to perform leak detection. Mechanical plugs were set on the same run as logging passes for leak detection. In both examples the well intervention operation lead to a reduction in planned operational time and significant cost savings for the client compared to traditional workover rig operations.
Coiled Tubing Material Selection for Velocity Strings in Sour Brine Service
Authors: Ward I. , Lynn C. , Shaw R. , Hervo S.
Published: June 2014

Installing coiled tubing velocity strings is a common deliquification strategy used in gas wells in which the flowrate has dropped below the critical rate required to remove produced liquids from the well. Initially in Shell’s Groundbirch unconventional gas development, a standard carbon steel coiled tubing grade was used for these applications. Due to elevated levels of chlorides, carbon dioxide and in some cases H2S, a long-term inhibition schedule was then needed to minimize corrosion. Recently, however, a special CRA material has been employed, that Shell had previously helped develop for subsea applications (Li et al, 2002), which has eliminated the need for costly long term inhibition. This paper outlines the selection process and implementation of this material change.

Standard 13Cr alloys are well known in the industry but could not be used in the Groundbirch fields due to the high chlorides levels of the produced water as well as H2S levels sometimes above NACE thresholds. On this basis, higher chromium coiled tubing materials were evaluated based on their ability to resist corrosion, sulphide and chloride stress cracking, as well as their mechanical properties. A fit for purpose material testing program was used, combining standard NACE test protocols with unconventional specimen shapes and crevice corrosion assessments in simulated well environments. Factors such as the direction of primary loading stresses, mechanical deformation during installation, as well as coiled tubing manufacturing characteristics such as the longitudinal seam, bias welds, and orbital (butt) welds were also considered.

From this fit-for-purpose testing, not only was the preferred corrosion-resistant material, Nitronic 19D duplex-steel, selected for the coiled tubing strings, but an operating envelope has been developed for it, as well as manufacturing specifications have been defined for the strings for optimum performance. Installation guidelines to reduce the mechanical damage inflicted on the strings have also been created. Although the campaign startup was delayed due to manufacturing issues, once the campaign did start, the installations have been efficient, with future campaigns planned.

By selecting a single, robust material grade for CT Velocity String material for a variety of potential conditions (high salinity, CO2, H2S), and also developing some guidelines for their use, installations can be done efficiently in Groundbirch in large campaigns, with long term cost savings from eliminating the need for continuous inhibition. Furthermore, the long term integrity of the strings should benefit, ultimately leading to longer completion life, less production deferment, and less intervention issues due to corroded and failed CT strings.
Journey of a Coiled Tubing Catenary Operation: Best Practice at South China Sea
Authors: Wan Mohd Fablillah Wan Mohd , Abdul Ghani Sushila Siti , Ishak Mohd Fakhrurazi , Kasim Mohamed Heikal
Published: June 2014

In the Malay Basin area, 18 offshore oil and gas fields are operated by PETRONAS Carigali Sdn. Bhd (PCSB). Years after years of production, the challenges in managing these matured assets are becoming more and more complex. PCSB performs well intervention, integrity operations and maintenance on different type of platforms comprising of more than 800 strings. Allocation of sufficient resources is inevitable in ensuring continuous performance of our daily well intervention works. To sustain and enhance the production rate at some wells, it requires extra resources for well intervention works to occur especially related to small or satellite platforms in the region. The small and satellite platforms limit the normal coiled tubing operation in term of deck loading capacity, crane limitation and accommodation during the operation.

In year 2008, PCSB has experienced a significant breakthrough by conducting CT barge assisted operations for the first time in their operation and in Malay Basin of South China Sea. During that time, team faced a lot of hurdles at preparation and execution stage due to limited experience thereof. Many lesson learnt had been documented for future operation improvements.

The journey since 2008 until now has seen the total of four CT barge assisted operations at PCSB platforms in Malay Basin which involved cement packer, acid stimulation, nitrogen kick off & sand management operations. All the objectives of these four operations were successfully met and increased the total production of oil at about 2500 bbls/day and 30 MMSCF/day. Determined to improve the quality of each operation at the preparation and execution stage, the team has taken an approach to capture lessons learnt & best practices from one project and applied them in the subsequent projects.

A wide range of engineering and project assessments from each of the activities have been developed to help the next CT catenary operations to achieve the most optimized time, cost and quality. Furthermore, the findings of this study are valuable for identifying strength and weaknesses in current approaches. The paper will focus on the specific of each of the project’s operational challenges; lesson learnt and devised best practices which have allowed development of specific guidelines that now allow effective execution of CT catenary operations in different challenging conditions found in South China Sea waters.
A Systematic Approach to Horizontal Well Perforating With Coiled Tubing in the South China Sea, Malaysia
Authors: Tapia W. R. , Jenie J. R. , Sorman I.
Published: June 2014

For many years perforating in horizontal wells under variable conditions has been one of the biggest challenges in the South China Sea area. Being a critical step during the cycle of a well, operators have to identify the best perforating method to achieve desired results in the safest manner whilst remaining cost-effective. Perforating using coiled tubing (CT) conveyance provides a range of flexibility as an attractive method to convey long sections of guns in a single run; however, whether this technology can be considered the most appropriate solution in light of available alternatives developed in recent years, remains in question.

One of the operators in Malaysia faced this situation when preparing its first perforating campaign in a field with complex extended reach wells, where the main target was to produce the maximum quantity of gas available whilst avoiding sand production. The campaign was performed with a rig present and any delay due to failure meant a huge cost impact. The operator solicited a detailed technical design and a systematic evaluation of all available options in the market to perforate the pay zones successfully.

The solution implemented was based in part on the experience obtained during previous years in the Area, where different methods were used. An exhaustive statistical analysis was performed to determine the critical parameters to be the focus of the design and the selection of the most reliable technology to address the various scenarios that the campaign presented. Hydraulically actuated CT tractors, friction reducers, sterling beads, and creative use of buoyancy effect, together with using state-of-the-art CT technology were among the combinations proposed to overcome CT lockup and successfully convey the oriented guns to total depth (TD) in all wells.

The intent of this paper is to provide a strong guide to CT perforating under variable conditions in horizontal wells through a thorough requirements analysis, risk evaluation and proper selection of technology. A review of the results and lessons learnt are also included. The engineering process, which has since become the benchmark in the area, can be applied with confidence as evidence by the success of the campaign.