Going Long – Overcoming Challenges in Completing 3600m Laterals
Abstract: Recent trends in unconventional oil and gas developments have seen longer horizontal wells drilled to achieve greater reservoir contact while minimizing cost and surface impact. Challenges for completing longer laterals include achieving effective fracture stimulation and performing clean out of the well bore after stimulation is complete. A case study was performed in Shell Groundbirch, an unconventional gas development in British Colombia, Canada, focusing on stimulation and extended reach cleanouts. Five lo… Show more
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Cited by 3 publications
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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.
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.
The requirement for intervention operations in extended-reach wells continues to grow. It is estimated that globally around 30-40% of the end sections of the extended-reach wells are inaccessible by the current coiled tubing (CT) friction reduction technologies, such as lubricants, vibratory tools, and tractors. Although many of the extended-reach wells are open-hole, there is a lack of understanding in the industry regarding the predictable and consistent friction reduction performance at downhole conditions of the existing CT technologies in those open-hole wells. Conventional friction reduction techniques for CT operations have been focused around mechanical or chemical methods for cased wells. For instance, following an extensive laboratory testing research program, a lubricant was recently developed that lowers the CT coefficient of friction between 40 and 60% in new, clean wells (Livescu et al. 2014; Livescu and Craig 2015; Livescu and Craig 2018). Friction reduction of this magnitude roughly translates in doubling the CT lateral reach. However, the friction reduction performance of lubricants is diminished in wells filled with sand of proppant. In addition, very limited studies are available for open-hole wells. To reach the remaining 30-40% un-reachable length of open-hole wells and cased-wells with sand or proppant, lubricants are required to work in conjunction with other technologies such as vibratory tools and tractors. The instrument previously used for metal-on-metal friction reduction research was modified to mimic the downhole conditions of CT sliding movement in open-hole wells and cased-hole wells with sand or proppant. That is, the coefficients of friction between the CT metal surface and the non-metal surface of a rock and sand or proppant layer can be measured. This instrument was designed for researching the effects of temperature, pressure, CT sliding speed, surface roughness, and fluid composition on the coefficient of friction. For clean cased-hole wells, the effects of pressure and sliding speed were weak in the laboratory tests, while the effects of temperature, surface roughness, and fluid type and composition were strong. For the friction reduction in open-hole wells, several rock samples taken from formations and reservoirs with different properties, such as porosity, permeability, pore size, etc., were used. The tests were performed with several CT coupons of different grades and both proprietary and third-party lubricants, to better understand the factors affecting the lubricity in open-hole wells. It was found that, at downhole conditions, the friction performance of the lubricant previously developed decreases from 40-60% for cased wells to 30-40% for open-hole wells. This is the first study available in literature consisting of laboratory friction tests performed with lubricants to mimic the CT operations in open-hole wells and sand/proppant-filled cased-hole wells. Detailing the testing procedures and results are of significant help to the industry for understanding the downhole factors affecting the CT friction in extended-reach open-hole wells and for obtaining predictable and consistent friction reduction results for CT operations in those wells.
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