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A ball-activated sliding sleeve design for multistage cemented lateral completions has been developed that allows multiple frac sleeves to be opened using the same diameter ball, significantly increasing the total number of sleeves available in the completion design. This paper discusses the sleeve design, the challenges associated with cemented laterals, the results of initial field installations, and the ramifications for completion design and execution. Ball-activated sleeves were introduced to overcome limitations of plug and perf designs and facilitate longer and more complex completions. As these completions have evolved, the technology has reached inherent design limitations. This is especially true in cemented lateral completions. These installations require a series of incrementally smaller balls and ball seats that reduce wellbore ID and ultimately limit the total number of sleeves that can be used in the completion. To further extend lateral length and accommodate the cemented laterals, a sliding sleeve device has been developed that allows multiple sliding sleeve valves to be opened with the same size ball and seat. The sliding sleeve design allows up to 90 individual sleeves to be opened as a single point of entry completion without dropping a ball diameter smaller than 4.00-in. in 5.500-in. casing, or a 3.25-in. ball in 4.500-in. casing. This increases wellbore ID over the length of the completion, and increases the total number of sleeves or sleeve clusters that can be employed in the completion design. The higher number of available sleeves affects the completion design, whether it uses single sleeve per stage or clusters of sleeves. In addition, lateral length of the completion is not constrained by the number of sleeves or the reach of coiled tubing. Cemented installations in the US Marcellus, Utica Shale, and Spraberry plays have enabled single-point-of-entry stimulations that optimize hydraulic fracturing pressure and provide a focused frac. In some applications, this has reduced pump rates and surface horsepower requirements by as much as 50% and also reduced the overall frac time. Experience also indicates these completions reduce water requirements by minimizing over-flushing of the formation. These cemented installations illustrate the potential of continued changes in completion designs and the viability of longer laterals. This paper is the first published examination of field performance in the initial installations of the sliding sleeve technology. Field results and data from sleeves installed in Marcellus, Utica Shale, and Spraberry completions are presented. Based on performance in these applications, the paper reviews completion design considerations facilitated by the ability to install larger numbers of sliding sleeves over longer cemented laterals.
A ball-activated sliding sleeve design for multistage cemented lateral completions has been developed that allows multiple frac sleeves to be opened using the same diameter ball, significantly increasing the total number of sleeves available in the completion design. This paper discusses the sleeve design, the challenges associated with cemented laterals, the results of initial field installations, and the ramifications for completion design and execution. Ball-activated sleeves were introduced to overcome limitations of plug and perf designs and facilitate longer and more complex completions. As these completions have evolved, the technology has reached inherent design limitations. This is especially true in cemented lateral completions. These installations require a series of incrementally smaller balls and ball seats that reduce wellbore ID and ultimately limit the total number of sleeves that can be used in the completion. To further extend lateral length and accommodate the cemented laterals, a sliding sleeve device has been developed that allows multiple sliding sleeve valves to be opened with the same size ball and seat. The sliding sleeve design allows up to 90 individual sleeves to be opened as a single point of entry completion without dropping a ball diameter smaller than 4.00-in. in 5.500-in. casing, or a 3.25-in. ball in 4.500-in. casing. This increases wellbore ID over the length of the completion, and increases the total number of sleeves or sleeve clusters that can be employed in the completion design. The higher number of available sleeves affects the completion design, whether it uses single sleeve per stage or clusters of sleeves. In addition, lateral length of the completion is not constrained by the number of sleeves or the reach of coiled tubing. Cemented installations in the US Marcellus, Utica Shale, and Spraberry plays have enabled single-point-of-entry stimulations that optimize hydraulic fracturing pressure and provide a focused frac. In some applications, this has reduced pump rates and surface horsepower requirements by as much as 50% and also reduced the overall frac time. Experience also indicates these completions reduce water requirements by minimizing over-flushing of the formation. These cemented installations illustrate the potential of continued changes in completion designs and the viability of longer laterals. This paper is the first published examination of field performance in the initial installations of the sliding sleeve technology. Field results and data from sleeves installed in Marcellus, Utica Shale, and Spraberry completions are presented. Based on performance in these applications, the paper reviews completion design considerations facilitated by the ability to install larger numbers of sliding sleeves over longer cemented laterals.
Geo-mechanics has always been a challenge during drilling process. It has also been a common observation that 40% of the over-all capex is given away during drilling process. Moreover, it also damages the land mass at large, loads of drill cuttings are generated from subsurface which are disposed on the earth surface, simply affecting the topography. Even, drilling does not prove to be successful in various cases as most of the exploratory wells are found to be dry this issue requires an ultimate solution. A well known technology called microhole drilling has been introduced to cope up with such concern. No doubt, all these specifications are achieved with the help of micro instrumentation.This study reflects the estimation of all the solids as wastes that are generated during the drilling process and imparts the environmental destruction. Microhole has been used effectively so far to hit the wells up to 700ft. Further, serious drilling issues are encountered but with the help of micro instrumentation it can be taken up to 5000ft or even farther. The main aspect that was found during the study that is microholes are drilled with the help of coiled tubing rig which consumes less disturbance area. In order to prove the metal of this technology a geo mechanical simulator is developed and model of microhole is even built on the developed software. The specifications and lithology of lower goru reservoir coordinates were used as input. Later, the results were compared to evaluate the recommended technology to avoid environmental issues and optimize the drilling program.
In 2015, Devon Energy spent $60 million on post-stimulation drillouts. The average cost of a drillout was $250,000 when no issues were encountered. However, drillouts with significant issues cost an average of $1.7 million. In November 2015, the Drillout Group (DOGs) was formed to study and find solutions for issues associated with coiled tubing drillouts. The team consisted of 15 completions and drilling engineers directly involved in coiled tubing drillouts. The team met for eight months and invested more than 1,000 hours of engineering time. The DOGs visited with more than a dozen vendors, took three field trips and conducted laboratory experiments on various fluid systems. This paper examines the history of coiled tubing drillouts at the operator and how stuck events were considered to be a normal aspect of operations. The DOGs team was tasked with engineering a solution to coiled tubing drillouts and formulating a Best Practice (BP) to apply companywide to minimize "train wrecks." The primary focus of the DOG team was to create standards for coiled tubing jobs including the target Reynolds numbers, annular velocity, chemicals, viscosities, torque and drag, early warning signs and corrective actions to prevent stuck pipe. The paper evaluates the implementation of a real-time monitoring station and the results from 50 wells drilled out following the DOG best practice. The new best practice and live monitoring station resulted in average savings of $100,000 and average drillout time of 21 hours per well with zero stuck or sticky events recorded.
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