This paper will highlight the advantages of multi-skilling intervention personnel on offshore installations. Crew members are from different service lines including Wireline, Slickline, Coiled Tubing and Gas Lift (completions). It will discuss how a multi-skilled crew is formed, specific scenarios on how they are utilized and how to develop and maintain the competencies of these personnel. Through Multi-skilling personnel there is a potential to reduce crew sizes up to 50% for some standard intervention operations. Multi-skilling personnel during the 2020/2021 global pandemic has become critical as personnel movements across regions have become limited or nonexistent in some cases. Reducing personnel on board has several benefits including lower personnel and logistics costs, lower carbon footprint of transportation of personnel, higher utilization of personnel, and motivating and retaining high skilled personnel as they learn new skills. It also allows for local personnel to be used for multiple operations permitting lower cost interventions to continue during a major global crisis.

The successful development of an oil and gas field relies upon the application of technology. Utilizing data-driven results improves drilling efficiency in extended-reach wells. Horizontal drilling of these wells is necessary for oil recovery due to the very low permeability of the reservoir and the presence of natural vertical fractures found in the Williston Basin. The reservoirs within the Williston Basin are generally tight with a relatively high pore pressure. A novel additive used during the drilling phase of the well was implemented and improved for coil tubing milling and cleanout procedure. Coil tubing application requires the use of robust fluid products due to the demanding environment. The novel additive was used to increase the lubricity improving friction on metal to metal contact where excess torque and drag led to the use of multiple tool runs and several short trips to decrease the drag forces. Novel water-based drilling fluid enhancer used in varying concentrations maximizes the performance, reducing the need for excessive short trips and an increase in tool life. This paper will highlight the planning phase for the engineering design, the equipment used, friction factor matching, and the challenges encountered using the additive during coil tubing applications. Operators have seen noticeable reductions in days reducing the amount of flat time with prior conventional application. The application case history shows introduction in the Williston Basin and lessons learned when introduced into the Permian.

New generation Polymer-filled and jacketed wireline cased hole cables eliminate all inherent bottlenecks of traditional wireline logging cables, enabling unprecedented operational efficiency with substantial reduction of well control risk and costly maintenance. This Technology enables a Mexico operator to deliver all their Operator Field wells ahead of time, without any HSE or well control incident while gaining 9 days of early production. Recently developed Polymer encapsulation and bonding technology completely seal Wireline cables electrical core and armors. The result is elimination of armor birdcaging (see glossary) and stranding, grease injection and associated equipment, cable gassing-up and well fluid related armor corrosion. Total armor torque balance and polymer outer jacket substantially reduce Chrome or glass coated completions damage, cable friction and maintenance requirements. The result is unprecedented well control safety, grease related environmental and reservoir damage elimination, higher operational efficiency with faster rig-up/down and tripping speeds, reduced tractor conveyance needs with improved well access in complex completions and proven early production gains. Contrary to conventional Wireline cables, the new generation polymer encapsulated cables come with a gas blocked core and a pressure balanced sealed cable termination. Potential well fluid migration through the cable cross section is thus completely prevented. Along with the polymer jacketing, well control risk is all but eliminated. During 2018, and for the first time in Mexico, 45 cased hole interventions, 130 descents and more than 1,000,000 feet in the well polymer cable deployments were carried in a North Mexico gas field. All Perforations, Production logging and other cased hole descents were completed totally free from HSE, operational or well control issues. Logistically challenging cable maintenance trips were all but eliminated, saving substantial time and cost to all parties involved. Compared to conventional wireline operations, time saved using polymer encapsulated Wireline cables represented a 50% reduction in rig-up and rig-down time, as well as 40% operational efficiency gain. With wells delivered early to production all contractual targets were exceeded, adding 9 days of additional production of gas and condensate. New generation Polymer encapsulated wireline cased hole cables have enabled the Mexico Operator plan and carry out efficient, safe, cost effective, and environmentally friendly Wireline Cased Hole operations, delivering producing wells ahead of time and exceeding contractual requirements.

The perforating deployment system significantly reduces rig time while maximizing the perforation length per run as compared with traditional systems, both on land and offshore, for rig or rigless interventions with very limited rig-up height. In limited rig-up height interventions, such as installations with short rig-up height or small cranes, to perforate long intervals it is necessary to use multiple short gun runs. To reduce the number of runs, short gun subassemblies are connected using a sealed ballistic transfer connector. The sealed ballistic transfer connector provides surface wellhead pressure containment sealing capability within the gunstring while also ensuring downhole ballistic transfer between guns subassemblies and the added value of optimizing perforating underbalance conditions. There is no limit on the number of sealed ballistic transfer connectors that can be used in one string. The sealed ballistic transfer connector allows deployment and reverse deployment under pressure in wells up to 103 Mpa, and it is qualified for H 2 S environments. The application of this technology allows significant rig-time savings and reduces personnel exposure via a remote operational console that enables personnel to connect and disconnect the guns under pressure from a safer distance. To date many jobs have been completed with this proven technology. One example presented in this paper is a horizontal well perforated from an offshore installation with an extremely short rig-up height, where there was only 16 m available to deploy wireline toolstrings. The limited height meant that a conventional wireline with tractor would allow deploying only a single 6-m-long gun carrier per trip. Using sealed ballistic transfer connectors enabled a 53-m gunstring (seven 6-m and one 3-m carrier plus adaptations) to be deployed in a single run using eight sealed ballistic transfer connectors. This was a record for the deployment conditions. More than 100 deployment and reverse deployment insertions were successfully conducted during this perforating job, reducing the required number of wireline runs from 59 to 10, and saving 51 days of operation and rig time. This paper demonstrates how the integrated application of the perforating sealed ballistic transfer connector technology, tractors, and polymer-encapsulated cables can reduce time in long perforating jobs with short rig-up heights both on land and offshore. In another presented example, the operator saved days of rig time, in addition to large economic and production time savings, and also reduced the exposure of personnel to lengthy, riskier tasks.

Research and field experience have given technical bases to accept the use of CT80, 90, and 100 coiled tubing (CT) for sour service, including their limitations. New higher strength Grades are now available (CT110 to CT140), but there is not enough awareness about potential issues, suitability, and boundaries regarding their use in H 2 S environments. This paper presents the potential issues and indicates the aspects that should be considered for the qualification of new CT Grades. This paper gathered research data from the review of technical publications related to CT and sour service since 1982, and also included field experiences regarding the use of CT in wells containing H 2 S, in order to establish the potential problems of working with CT in sour environments, and define what should be considered for the qualification of the new CT Grades available in the market, including the testing options that will cover the aspects needed for that qualification. The analysis of the information allowed establishing that the potential problems of using CT in sour service include the reduction of fatigue life available and different forms of H 2 S cracking. Considering this, it was established that the aspects that should be included for qualifying a CT Grade for sour service are: sour fatigue performance for pipe and bias weld, boundaries limits regarding H 2 S partial pressure, and finally the effectiveness of anti-cracking inhibitors for protecting the pipe against H 2 S cracking. The testing options proposed include bending fatigue testing of CT samples after being exposed to H 2 S, and small scale samples NACE TM0177 testing (Methods A, B, or C). More awareness about potential issues of using high strength CT Grades in sour service is required, and also there is no formal industry guidelines regarding their qualification for sour service. This paper summarizes the potential problems that can occur from the exposure of CT to H 2 S (lab data and field failures examples) and establish what should be considered for the qualification of a CT Grade to be used in sour service, including the testing options.

In the past few years, operators have been increasing the lateral lengths of horizontal wells to maximize the reservoir contact and production rates. However, the frictional forces between the coiled tubing (CT) and casing in those long lateral wells also increase, limiting the ability of conventional CT sizes to reach the end prior to lock-up occurring. Technologies such as lubricants, vibratory tools and tractors are usually used to extend the CT reach. However, the downhole performance of some of these friction-reducing technologies is sometimes unpredictable and inconsistent. In addition, with the current industry's trends to lower the overall intervention costs, lubricants may be considered too expensive in long laterals. This paper reports on the laboratory evaluation of the friction-reduction performance of a novel CT surface treatment. This surface treatment has been proven to be effective at reducing the frictional forces by altering the CT surface finish. After the treatment, the CT surface is smoother and has micron-size dimples that work as small reservoirs, preventing a lubricant from being easily washed off the CT surface. The new metal surface treatment was applied to several CT samples. The friction between the treated CT samples and various actual casing samples was studied in a laboratory on a linear friction apparatus. This instrument is specifically designed to measure the coefficients of friction between CT and casing at downhole conditions, such as with or without fluids relevant to coiled tubing operations and at temperatures as high as 100°C. Additionally, laboratory tests were performed to determine the ability of the treated and un-treated CT samples to retain lubricants when sliding on the casing surfaces. Currently, there are two main operational challenges of using lubricants for reducing the CT friction. First, to reduce the lubricant volume in long laterals, and therefore the intervention costs, many operators choose to pump lubricant slugs instead of pumping the lubricant continuously. However, most of the lubricant is consumed inside the CT, and only a small lubricant amount adheres to the outside CT and casing surfaces where the friction needs to be reduced. Secondly, even if the lubricant coats the outside CT surface, there is a risk of being quickly washed off, unless new lubricant is pumped continuously. The laboratory testing results obtained from this study have shown a reduction of the coefficients of friction after the CT metal surface treatment. These results prove the friction-reduction potential of manufacturing a CT with the new treated surface for extending the CT reach with or without friction-reducing technologies such as lubricants, vibratory tools and tractors. The advantage of utilizing the new CT metal surface treatment is that a lubricant remains longer in the micron-size pores on the CT surface and reduces the CT friction more consistently. The novel idea in this paper encompasses the fact that the CT metal surface treatment has the potential to reduce the CT friction by itself and further in combination with friction-reducing technologies such as lubricants, vibratory tools or tractors. The new CT surface is smoother and has micro-pores that can prevent a lubricant from being easily washed off the CT surface. The laboratory tests with the new CT samples have shown reduced coefficients of friction when comparing to conventional CT coupons with un-treated surfaces.

In the perforating industry, operators, service companies, and manufacturers are constantly looking to improve shaped-charge performance and product quality and reliability while ensuring the highest levels of safety. More recently, there has been a heightened urgency to deliver improved operational efficiency considering recent industry downturns and the need to become more cost efficient. A new wireline perforating initiation system has been developed that addresses current industry challenges by improving reliability and efficiency while also improving the overall safety of wireline perforating operations. The development of a new initiation system for the conventional perforating market has built upon existing technologies previously developed for the unconventional market. The initiator system follows the guidelines of API RP67, fourth edition (in review at the time of publication), and has undergone detailed testing and validation before introduction to the field. The design has been qualified as an APIRP67 Group 2 initiator, which allows use without requiring radio silence in the conventional exclusion area. Field testing has demonstrated that the simplification of the preparation and arming process significantly improves operational efficiency and reduces the risk of human error. Additionally, by eliminating parts and simplifying maintenance, system reliability and usability is further improved. Selective guns are much simpler to prepare and arm, making the utilization of such gunstrings more appealing in areas where, in the past, they may not have been viable due to the additional complexity and/or associated arming time. This new gun system is currently being deployed in several areas around the world and has shown that it can deliver step-change improvements in reliability and efficiency with improved operational safety when working with explosives in wireline operations. This will have a significant impact on perforating operations, improving the safety of the field workforce while simultaneously improving operational efficiency.

Production in mature offshore Mexico fields is mostly driven by gas injected from surface. With time, injected gas flows directly through natural fractures in the low-pressure carbonate reservoirs, leaving oil trapped in the low-permeability matrix and reducing crude production. Over the past few years, the gas-oil contact has rapidly moved across those fields making conventional gas shutoff techniques both unsuccessful and uneconomic. An innovative approach introducing a fit-for-purpose polymer foam system (PFS) and its accurate placement using coiled tubing (CT) real-time telemetry addresses those challenges with an unprecedented success rate while optimizing both logistics and operational time. To selectively shut off unwanted gas in these naturally fractured reservoirs, the PFS was designed to have a high foam quality and low density. Thanks to a delayed crosslinker, this formulation enables deep penetration along the fractures and fissures before the gel strength develops. To ensure effective placement of the PFS and its activation at the right depth, CT downhole gauges monitor pressure and temperature throughout the pumping stages. Any deviation from the downhole schedule can swiftly be addressed to maximize shutoff effectiveness at depth. Monitoring of downhole parameters is not only instrumental to the PFS placement, it is also critical to other services associated with conformance operations. Thanks to the casing collar locator and gamma ray signals, it enables accurate depth control during perforating and stimulation phases. This system also facilitates the evaluation of the wellbore response after each main stage of the intervention. Finally, it can help perforate new intervals with minimum impact to the already pumped conformance treatment through the use of a new perforating firing head whose activation is controlled through fiber optics rather than triggered by hydraulics. The introduction of this methodology in offshore Mexico led to an increased success rate in gas shutoff operations. Of the nine wells that had interventions performed in 2015, eight were initially closed to production due to high gas production. Following the shutoff interventions, those wells were put back in production with an average reduction of 8.0 MMscf/d in gas produced per well and an average increase of 600 BOPD in oil produced per well. Near the end of the campaign, average oil produced per well reached 830 BOPD thanks to further improvements in the operational workflow. This approach constitutes a significant step forward in terms of efficiency and economic sustainability. The use of CT to perform all the stages of conformance operations greatly improved logistics on the platforms. In addition, the real-time monitoring capabilities of the system and flexibility of its downhole toolstring enabled an enhanced level of evaluation throughout the interventions, which, in turn, optimized the outcome and saved days of operation.

Despite new deepwater project economics being strongly challenged by the halved oil prices, it is expected that the ongoing projects will continue, given the large, long-term investments that have already been made. In this challenging market environment, operators are required to reduce operating costs to balance expenditures with available cash flow. With the reduction in operator spending, coiled tubing (CT) service companies are further pressed to reduce service charges. Lowering service rates is not the ultimate solution because it neglects to consider a prevalent factor that often relates to excessive expenditures: inefficient performance. Improved operational efficiency holds significant cost-saving potential. Efficient performance in the areas of equipment loading, offloading, rigging up, pressure testing, in-hole operations, and rigging down enables substantial financial reward in the form of time savings. The importance of efficiency improvements in deepwater vessel-based CT operations, along with the key areas of improvement and performance solutions, were explained in previous papers, Ottolina et al. (2016) and Rudnik et al. (2014) . The objective of this study is to transform efficiency improvement into a repeatable process that can be applied to every aspect of CT operations to decrease operational risk, enhance performance and reduce intervention cost. Low-performance areas and locations of recurring non-productive time (NPT) were addressed with remedial work plans. Meanwhile, high-performance areas were analyzed to record the best practices for efficient execution to realize efficiency gains for the campaign's duration. These best practices were applied to areas of mediocre performance to elevate the percentage of tasks performed on an efficient level. To ensure continuous improvement and unbiased performance review, a performance tracking system and various performance metrics were created. To ensure consistency of performance and continuity between three offshore crews, the development of standard work instructions, process flow charts, and templates were created and deployed. The development of a total efficiency solution provided the framework for a step change in performance for seven well intervention operations. A consistent, systematic approach to CT operation efficiency improvement has resulted in reductions of 60% for average pressure testing time, 63% for BHA makeup with break test, and 30% reduction in rig up and rig down series. Additionally, improved consistency has accompanied increased performance as the online pressure testing success rate improved from 64 to 95%. These efficiency gains currently provide an estimated 22 hr total time savings for a typical 7-day CT operation.

In the coiled tubing (CT) business, it is a common practice to track the fatigue-life of CT strings to help avoid costly failures during operations. Existing fatigue-life tracking models account for parameters such as differential pressure, bending radius, tubing diameter, wall thickness, and materials grade. However, these models do not take into account the effect of localized damage, which is the leading factor contributing to premature failure. In the past years, models have been developed to account for the fatigue effects of mechanical defects. A key input for such models is the geometrical severity parameter, which is defined as a function of the defect geometries (length, width, depth, and shape). Normally, these inputs must come from manual measurements and prove-up. Most recently, a new technique was developed which does not rely on the manual measurements. The new technique utilizes inline magnetic flux leakage (MFL) technology to automatically determine the defect severity in terms of fatigue-life reduction. The current paper presents new development and results of enhanced fatigue evaluation by virtue of MFL measurements. A hybrid approach is proposed and demonstrated, in which the results of conventional fatigue tracking are coupled with the fatigue-life reduction determined based on MFL measurements on physical defects, to come up with a more comprehensive and accurate fatigue-life assessment. Experimental results are presented to support the validity of this hybrid approach. Also, the new approach is applied on a number of case studies to demonstrate its applicability in real-world CT pipe management.

Coiled tubing (CT) monitoring tools are being utilized on a larger percentage of field jobs now as compared to the past. They are being used on both CT intervention and CT drilling operations. The objective of this paper is to demonstrate how a wall thickness measurement device can enhance and improve the calculations made by a CT fatigue algorithm. Experimental work was done which shows how the wall thickness can vary depending on the pump rates, the fluid being pumped and the amount of tubing that is spooled on the reel. Reference four provides detailed information related to wall reduction in CT during pumping operations. Typically, fatigue models will utilize an estimated, nominal or minimal wall thickness to perform the fatigue calculations. The amount of wall reduction in CT can vary greatly and as a CT string acquires fatigue, there is a chance that the estimated wall thickness may not reflect the actual wall thickness of the pipe. Recent modifications to fatigue tracking software allow the user to incorporate the real-time (or recorded) measured wall thickness into the fatigue calculations. This paper will discuss the experimental work, the modifications to the model, and case histories in which the wall thickness measurement device was used. Calculating the CT fatigue using the measured wall thickness will increase the accuracy of the CT fatigue profile. This will allow CT service companies to operate at an increased efficiency. Operating companies will also benefit from this technology because there will be fewer fatigue failures at the well site due to the increased accuracy in the fatigue calculations.

The Buda formation in Texas presents extreme challenges to prevent formation damage during drilling operations. After using many fluid selection variations, several operators have determined that under-balanced drilling with native crude is the most optimum method. The initial startup project for coiled tubing drilling (CTD) operations in this formation has been completed, with more activity to come. However, as the preferred recirculation of the native crude drilling fluid presents two major challenges. First, the formation is up to 2% sour, and the native crude is relatively volatile with a low flash point and high vapor pressure. Recirculation of sour crude will lead to double-sided exposure of the coiled tubing, which historically has resulted in extremely short fatigue life. The use of active fluid property testing, in addition to scavengers and inhibitors with defined mitigation plans, reduces the risk to an acceptable level. Significant laboratory testing of the fluid properties as the material degrades with time, temperature, and mixing have been completed. Additional mitigation actions are utilized in conjunction with the laboratory results to further reduce the volatility properties. Internal technical and operational reviews, along with additional sourced subject matter expertise, have challenged existing safety, operational, and technical limits. Operational procedures have been continuously monitored and adjusted to compensate for the adverse dynamic wellbore conditions encountered during the campaign. The discussions within this paper detail the background challenges, laboratory testing, operational/HSE planning and mitigation practices to allow operations to commence. Additionally, the paper covers operational results as the wells are drilled. These results may provide a basis for future operations utilizing extreme fluid conditions in other applications within the industry due to the economic benefits from native crude.

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).

As part of an abandonment campaing started in Feb 2013, Chevron had decided to permanent plug 3 gas producer wells and 2 water producer wells in the Ballena Field, with the main challenge of the footprint of equipment to be used because the original locations were eroded by sea and there was no possibility to use a conventional work over rig. This document presents 2 case studies where a significant advance in the slickline technology that incorporates cutting-edge benefits such as real time visibility and interaction and control, while maintaining slickline advantage simplicity had overcome the project's challenges allowing time and cost reductions.

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.

Metal-to-metal lubricants used within the Coiled Tubing (CT) industry have become an essential resource for the successful completion of a variety of operations, most notably extended reach practices. A vast selection of metal-to-metal lubricants exist within the industry, which provides an abundance of options for CT applications. However, the effectiveness of these lubricants based on different well parameters is not well understood. The objective of this study is to provide a quantitative analysis comparing the friction reducing characteristics of various CT metal-to-metal lubricants used in optimized extended reach practices. Fourteen different lubricants commonly used in the Eagle Ford and the Bakken resource plays were tested using an OFITE EP (extreme pressure) and lubricity tester to determine their respective lubricity coefficient and film strength. The lubricity coefficient test used a torque arm which applied 150 in-pounds of force (the equivalent of 5,000 to 10,000 psi on the intermediate fluid) between two hardened steel surfaces (a block and a ring) rotating at 60 RPM. The EP test produced an indication of the film lubricant strength by applying a measured force to a torque-sensitive bearing cup with the torque arm. The EP test was performed at a high shear rate of 1,000 RPM with fluid pressures ranging from 5,000 to 100,000 psi between the steel surfaces. Tests with multiple solutions and various conditions were conducted to provide a better understanding of how the lubricant reacts in field applications. Each lubricant was mixed with fresh water, brine fluid, friction reducer, and 15% HCl fluid at different temperatures. The effectiveness of the top-performing metal-to-metal lubricants was validated by comparing the laboratory results with field data and computer modeling. The outcome of this analysis was used in conjunction with previously completed extended reach studies to further understand and improve the effects of metal-to-metal lubricants in CT operations. This paper provides a comprehensive analysis of the performance of the different metal-to-metal lubricants based on the applications and well conditions. A more in-depth understanding of the lubricants will help to improve accuracy when modeling and designing extended reach CT operations, which will result in improved overall efficiency.

World energy demand has led unconventional reservoirs to become a focal point for operators worldwide. In some regions, including North America, unconventional resources have been developed successfully, accumulating important experience and lessons learned in the process, allowing these resources to become important contributors to countries’ energy production. In an attempt to reproduce this effect in other regions, operators are also looking into important unconventional reservoirs outside North America. Currently the world’s third-largest shale oil and gas resources holder, Argentina has become a key focus for many operators initiating exploration and development operations. This brings many challenges to operators trying to take over this market as quickly, efficiently, and safely as possible. When developing unconventional reservoirs in the magnitude expected, one of the most important challenges for service companies and operators in Argentina is effectively grasping the global expertise, best practices, and lessons learned from these types of operations and adapt them to the local environment. This should reduce the learning curve experienced while starting a new development. A key component of these challenges includes all coiled tubing (CT) interventions involved in well completion; expertise in CT intervention is critical because of the risks concerning these operations, which include wellbore calibration, perforating, fracture plug drillouts (FPDOs), and sand cleanouts. Overcoming this challenge can translate into valuable time and cost reductions and allow operators to reach the efficiency that took years to attain in other parts of the world in much less time. Lessons learned and best practices incorporated from global experience, in addition to the local ideas, contributed to the implementation of CT interventions for the shale startup and beginning of the development phase in Argentina. Statistics and results from jobs performed in these reservoirs in its first year since startup reflect the changes and adaptations undertaken to successfully develop the shale resources in Argentina and to inform future plans for this rapidly evolving market.

The volume of fresh water being used to fracture oil and gas wells is of growing concern to operating companies because it is a significant expense that involves purchase, transportation, onsite storage, heating, chemical additives, and post-treatment disposal. Reducing frac water volumes is important to reducing the environmental impact and improving the economics of multistage completions. Current multistage methods include plug-and-perf and ball-drop frac sleeves. Both of these methods bullhead frac fluids and sand down the casing and consume large quantities of water. In recent years, fracturing techniques using coiled tubing have dramatically reduced the amount of frac water required while delivering equivalent or superior results. These techniques combine coiled tubing with sliding sleeves and resettable frac isolation. The coiled tubing provides a means of circulating fluids to the frac zone, as opposed to bullheading, and enables the sliding sleeves to be shifted mechanically without using pump-down balls. When the frac is pumped down the annulus between the casing and coiled tubing (annular fracturing), water use is reduced by as much as 20% compared to methods that do not use coiled tubing during the fracturing process. For many multistage completions, water volume can be reduced up to 50% by pumping frac fluids through the coiled tubing. This paper describes these systems and their deployment and includes a case history describing how one operator reduced water use significantly through the application of this method without compromising treatment volumes or stimulation design parameters, while still achieving all of the original completion objectives.

An operator had live perforating guns stuck in the casing at 14,100 ft. The wireline had been pulled out of the rope socket, leaving 67 ft of wireline tools, perforating guns, and plug assembly stuck in the wellbore with 8,300-psi surface pressure. To remediate this issue, a 144-ft tall snubbing unit rigup was employed using eleven 7 1/16-in. 15K-psi blowout preventer (BOP) cavities and 78 ft of riser spool. Job preparation included standard prejob planning analysis to help resolve work string buckling risks and to establish the work string’s maximum safe load limits based on the well conditions and operational requirements. This challenging high-pressure fishing job was executed as planned and without incident. The snubbing unit was rigged up, pressure tested, and operational within five days of equipment arriving on location. The snubbing unit crew successfully latched and recovered 97 ft of fish and work string bottomhole assembly (BHA) to surface under high pressure without incident. This paper explores the level of prejob due diligence analysis required for the basic planning of high-pressure snubbing work. Surface buckling analysis, work string condition, and pipe tension/collapse considerations are applied and discussed in this case history.

Sucker rod Pumping (SRP) has been among the most efficient artificial lift systems. This method has proven to be one of the most popular ones while having some modifications in the prime mover systems, using hydraulic, pneumatic or mechanical devices. However, one of the most frequently encountered problems with this system is that while the well is being produced, sand is dragged from the formation to the well. Whether it comes from the fracture (propant) or the formation itself, this interferes with the pumping system and the fluid flow to the surface. In SRP, fluid flow velocity is not enough to maintain sand suspended so that it could be brought up to the surface, ending up precipitated and being deposited on top of the pump causing a reduction in efficiency and premature wear of the pump components, if not stocking the pump at all. Due to this effect, the well must be scheduled for work over in order to remove the sand. This implies to move and de-move a work over rig which can take several days with the associated cost and deferred production. Using Coiled Tubing instead of a sucker rod string, maintenance can be achieved to the well through pumping and circulating fluids without having to remove the string and bottom hole pump, taking just about a couple of hours to perform the job. Production can be restored in few hours, reducing down time, maximizing well production. It also can be used in a preventive mode by pumping chemicals that will help fluid flow by preventing scale build up and viscosity reduction in the case of heavy and viscous crude oils. Coiled tubing string is designed to fit specific needs such as depth, pressure, and loads expected during the operation. It may vary in diameter, wall thickness, and stiffness. This paper describes the first time application in México for this technology which offers a great potential in mature fields. It also describes coiled tubing design criteria as well as string evaluation after the trial test performed.