Swellable Packers Research Articles

APPLICATION OF LINER SYSTEMS WELLABLE ELASTOMERIC PACKERS FOR WELL CONSTRUCTION

The application of liner systems featuring swellable elastomeric packers in well construction has emerged as a groundbreaking development within the oil and gas industry. This technology, which will be discussed in detail in this paper, addresses critical wellbore challenges, providing an in-depth exploration of its advantages and the transformative effects it has on well construction. Swellable elastomeric packers, a key component of these liner systems, play a pivotal role in overcoming various wellbore obstacles. Their unique design allows them to expand when in contact with wellbore fluids, establishing a robust and reliable seal. This characteristic renders them adaptable to a diverse array of applications, showcasing their versatility. These packers are particularly instrumental in creating a barrier between different geological formations or production zones within a well. By expanding and isolating specific zones, they effectively prevent undesirable fluid flow between them. This not only optimizes reservoir management but also enhances overall production efficiency. In addition to their zonal isolation capabilities, swellable elastomeric packers contribute significantly to the integrity of well casings. Acting as an additional protective layer, they guard against corrosion, high-pressure zones, and other challenges encountered in harsh downhole conditions. This protective function becomes especially crucial in ensuring the longevity and reliability of wells subjected to demanding environments. For wells prone to sand production, the deployment of swellable packers proves invaluable. These packers isolate and stabilize sand-prone zones, mitigating the ingress of sand and preserving productivity. Often overlooked in well completion design is the preparation for abandonment. The incorporation of blind pipe sections with swellable packers along the horizontal section of the liner in the new completion procedure has become an effective tool for safely and efficiently shutting down horizontal wells. A noteworthy advantage of liner systems with swellable packers is their cost-effectiveness in providing zonal isolation and ensuring casing integrity. By reducing reliance on traditional cementing methods, these systems offer economic solutions without compromising performance. Their adaptability allows for customization to specific wellbore needs, making them compatible with various completion techniques and wellbore configurations. In conclusion, the incorporation of liner systems featuring swellable elastomeric packers marks a significant leap forward in well construction technology. The versatility and effectiveness of these packers address critical wellbore challenges, providing solutions that optimize reservoir management, enhance production efficiency, and contribute to the overall integrity of oil and gas wells. The purpose of this article was to examine samples and establish the conditions for their application. Keywords: liner systems, swellable elastomeric packers, well construction, zonal isolation, swelling rate, liner hanger.

STUDY OF PACKER'S SWELLING RATE IN DIFFERENT LIQUIDS

Cementing is currently the only method used in oil fields to establish zonal isolation. Another method for zonal isolation involves the use of swellable packers. Swellable packers are designed using elastomeric components that have a unique swelling property when exposed to water, water-based fluids or oil. The swelling of the elastomer creates a tight seal. Swellable packers offer several advantages in well construction and maintenance. They can be used for a variety of purposes including preventing gas migration, shutting off water flow, and facilitating fracturing operations. Swellable packer technology involves the selection of elastomers that can expand in the presence of water, oil, or certain brines. It is assumed that the degree of swelling and rate of expansion depends on factors such as elastomer composition, conditions in the wellbore, and the salinity of the surrounding fluids. The use of swellable packers requires careful consideration of well conditions and the fluids present. Matching the packer's swelling properties to the intended well’s fluids is essential to achieve effective zonal isolation. Proper elastomer compatibility testing and evaluation is recommended prior to field deployment to ensure successful and reliable packer operation. in this regard, the purpose of this study is to experimentally confirm the possibility of expanding packers in fluid with different salt concentrations and oil. The study highlights the importance of conducting a comprehensive quality assessment of elastomers prior to their use in field operations. Keywords: cementing, zonal isolation, swellable packers, swelling property, salinity, elastomers, crude oil, swelling rate.

Modelling the Productive Life of Swellable Packers for Open-Hole Applications

Modelling the Productive Life of Swellable Packers for Open-Hole Applications

Concurrent 6. Presentation for: Effects of rapid gas decompression on coal seam gas swellables

Presented on Tuesday 17 May: Session 6 Thousands of non-stimulated coal seam gas (CSG) wells in Queensland’s Surat Basin rely on swellable packers as the first line of defence against interburden solids production and poor well run life. This paper is aimed at understanding some of the impacts of long-term well operations on swellable performance from rapid changes in downhole pressure. For the first time, rapid gas decompression (RGD) effects on CSG swellables were experimented on in a quantitative manner as an analogue to underbalanced workover and pump trip conditions. RGD has the potential to break down swellables due to rapid release of high-pressure methane diffused in the rubber matrix resulting in a flow path for interburden solids. Five commonly available swellables from the CSG market were lab-tested for rapid decompression with methane at operational conditions. Coupon samples were swollen to representative conditions and placed in an autoclave under high-pressure methane, then rapidly decompressed in cycles. Results of this study showed relatively low levels of physical degradation under test conditions but shrinkage effects varied between products largely grouped into material properties, confirmed with separate ambient shrinkage test. As such, the focus on swellable placement geometry remains paramount. To access the presentation click the link on the right. To read the full paper click here

Abrasive Jet Perforating Restores Productivity of an Inactive Oil Producer

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208988, “Novel Application of Abrasive Jet Perforating To Restore Productivity of a High-Potential Inactive Horizontal Oil Producer,” by Sadaf S. Chishti, SPE, Steven H. Craig, SPE, Baker Hughes, and Edward J. Wheatley, SPE, ADNOC, et al. The paper has not been peer reviewed. The complete paper illustrates a novel methodology that enabled the safe application of coiled tubing (CT) abrasive perforation to increase production in a sour horizontal extended-reach (ER) oil producer. The well was underperforming at 10% of the anticipated production rate because of a damaged lower completion. To avert a costly workover, abrasive perforation with CT was selected as a safe alternative to conventional explosives-based perforating conveyed on electric line. Introduction An offshore horizontal ER producer well was drilled with a total depth (TD) in excess of 24,000-ft measured depth (MD). During the completion phase, a 4.5-in. liner with 16 inflow control devices (ICDs) and eight swellable packers was run with the ICDs in the closed position. Swellable packers were placed after every two ICDs. To open these ICDs, an internal pressure of 2,500 psi was required, achieved by dropping a ball that would seat in the float collar. Multiple attempts were made to pressure up and open the ICDs without success. The decision was made to run the upper completion with a plan to activate the ICDs using rigless CT intervention. After a drift CT run, multiple attempts were made to run a through-tubing inflatable packer bottomhole assembly (BHA) on CT to isolate and pressure up the well. All attempts failed to reach target depth, with repeated holdup at approximately 20,273-ft MD. Production-logging passes performed in injection mode determined that the well interval between 20,262 and 20,300 ft was taking more than 80% of the injected fluid. In a subsequent CT logging run, a caliper log identified that the liner section in this interval was parted and identified an openhole section with washouts in excess of 7-in. inner diameter. The results from the log are shown in Fig. 1, with the enlarged section representing the parted liner/openhole interval. Because the ICDs remained closed along with a damaged liner section, the options of recovery leaned heavily toward a rig-based workover for sidetrack and recompletion. Considering time and cost constraints, studies commenced to identify an efficient alternative to establish flow contribution from the inactive compartments by adding perforations. CT was chosen as the conveyance method based on previous success in reaching TD, and three options were evaluated. Based on the lowest risk level and availability of resources, the safest and most-viable option was abrasive perforation with CT. This technique uses a sand jet perforator, a downhole tool that uses high-pressure abrasive-laden fluids to penetrate the casing, liner, and cement and extend a cavity into the reservoir.

Effects of rapid gas decompression on coal seam gas swellables

Thousands of non-stimulated coal seam gas (CSG) wells in Queensland’s Surat Basin rely on swellable packers as the first line of defence against interburden solids production and poor well run life. This paper is aimed at understanding some of the impacts of long-term well operations on swellable performance from rapid changes in downhole pressure. For the first time, rapid gas decompression (RGD) effects on CSG swellables were experimented on in a quantitative manner as an analogue to underbalanced workover and pump trip conditions. RGD has the potential to break down swellables due to rapid release of high-pressure methane diffused in the rubber matrix resulting in a flow path for interburden solids. Five commonly available swellables from the CSG market were lab-tested for rapid decompression with methane at operational conditions. Coupon samples were swollen to representative conditions and placed in an autoclave under high-pressure methane, then rapidly decompressed in cycles. Results of this study showed relatively low levels of physical degradation under test conditions but shrinkage effects varied between products largely grouped into material properties, confirmed with separate ambient shrinkage test. As such, the focus on swellable placement geometry remains paramount.

Case Study: Smart Liner Matrix-Acid Stimulation—A Cost-Effective Performance-Enhancement Technique for Carbonate Reservoirs

Carbonate reservoirs require effective acid stimulation to improve well productivity. For long horizontal wells, a complicating factor has previously been the difficulty of controlling acid placement along the reservoir section. The Smart Liner (SL) concept solves this problem. It consists of a number of small holes spaced in such a way so as to distribute acid evenly along the reservoir interval. Fig. 1 shows a schematic of the concept. Without the need of a coiled tubing, acid is bull-headed at a high rate from surface through the production tubing and enters the liner from the left. The liner does not have to be horizontal but very often is. When acid reaches the first hole, which typically has a diameter of 3–6 mm, the pressure drop across the hole is so large that only a small portion of the acid exits the liner through the hole; the remaining acid continues along the liner until it reaches the next hole where the process is repeated. Appropriate hole spacing ensures that acid is distributed with a given acid coverage (dosage) in barrels of acid per foot of reservoir section. The small cross-sectional area of the holes results in focused acid jetting at velocities often exceeding 20 m/s (65 ft/s). The jetting helps promote wormhole formation leading to substantial productivity enhancement. The hole-spacing design requires dedicated software which must take into consideration constraints pertaining to the reservoir, the well, and the pumping equipment while minimizing operational complexity. The tool should also yield a quick answer to enable the user to optimize the final design post drilling and provide a running tally consisting of the sequence of liner joints to be run in hole. In heterogeneous reservoirs, it is typically required to segment the wellbore with swellable packers to isolate sections with different reservoir pressure and/or fluid mobility, and the SL concept readily accommodates that. Also, since the subsequent stimulation relies on matrix acidization, the tool must ensure that fracturing pressures are not exceeded. The original limited-entry liner (LEL) technique dates to the early 1960s and was proposed for fracturing applications (SPE 530). Reviews by Somanchi et al. (SPE 184834) and Weddle et al. (SPE 189880) suggest that it is still widely applied for such purposes. In the late 1990s, Maersk Oil adapted the concept to effectively stimulate extended-reach wells in its North Sea chalk reservoirs on a large scale. Hansen and Nederveen (SPE 78318) refer to the technology as controlled acid jetting (CAJ). In the following years, the CAJ technique was implemented in more difficult formations such as a 0.1 mD chalk reservoir (SPE 144159) as well as in a tight, gas-bearing formation (SPE 123979). Balsawer et al. (IPTC 17611) designed multizone completions in ultralong wells in a giant field offshore Qatar, which comprised more heterogeneous limestone formations. Other field implementations have been described by Issa et al. (SPE 171779) for a super-giant reservoir offshore Abu Dhabi. Past deployments have concentrated on extended-reach wells with reservoir temperatures up to 210°F. Over the past year, ADNOC has significantly expanded the operational envelope of the Smart Liner concept. Fig. 2 summarizes the variation in completed reservoir length and average permeability for 80 well designs. Table 1 shows that reservoir temperatures vary from 140°F to 300°F.

Identification of Breakout Behind Casing: Methodology to Obtain Openhole-Equivalent Caliper Measurements Through Slotted Liner Using the Density Tool

Growth in the coal seam gas industry in Queensland, Australia, has been rapid over the past 15 years, with greater than USD 70 billion invested in three liquified natural gas export projects supplied by produced coal seam gas. Annual production is of the order of 40 Bscm or 1,500 PJ, with approximately 80% of this coming from the Jurassic Walloon Coal Measures of the Surat Basin and 20% from the Permian Coal Measures of the Bowen Basin. The Walloon Coal Measures are characterized by multiple thin coal seams making up approximately 10% of the total thickness of the unit. A typical well intersects 10 to 20 m of net coal over a 200- to 300-m interval, interbedded with lithic-rich sandstones, siltstones, and carbonaceous mudstones. The presence of such a significant section of lithic interburden within the primary production section has led to a somewhat unusual completion strategy. To maximize connection to the gas-bearing coals, uncemented slotted liners are used; however, this leaves fluid-sensitive interburden exposed to drilling, completion, and produced formation fluids over the life of a well. External swellable packers and blank joints are therefore used to isolate larger intervals of interburden and hence minimize fines production. Despite these efforts, significant fines production still occurs, which leads to the failure of artificial lift systems and the need for expensive workovers or lost wells. Fines production has major economic implications, with anecdotal reports suggesting up to 40% of progressive cavity pump artificial lift systems in Walloon Coal Measures producers may be down at any one time. The first step in solving this problem is to identify the extent and distribution of fines production. The wellbore completion strategy above, however, precludes the use of mechanical calipers to identify fines-production-related wellbore enlargement. A new caliper-behind-liner technique has therefore been developed using a multiple-detector density tool. Data from the shorter-spacing detectors are used to characterize the properties of the liner as well as the density of the annular material. This is particularly important to evaluate as the annulus fill varies between gas, formation water, drilling and completion fluids, and accumulated fines. The longer-spacing detector measurements are then used in conjunction with pre-existing openhole formation density measurements to determine the thickness of the annulus, and hence hole size, compensating for liner and annulus properties.

Integrated Approach to Well-Leak Diagnostics Meets Success Offshore Timor Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19448, “An Integrated Approach to Well-Leak Diagnostics: Case Study of the Successful Application of the Latest Leak-Detection Technology and Interpretation Offshore Timor Sea, South East Asia,” by Andrew Imrie, SPE, Brendon Negenman, Chung Yee Lee, Mahadevan S. Iyer, Sarvagya Parashar, SPE, and Mohamed Raouf Shata, SPE, Halliburton, and Sean Helton, SPE, ConocoPhillips, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. The identification of low-rate leaks along with low annular-pressure buildup rates in any type of completion presents challenges to well integrity. This paper emphasizes the importance of understanding well-diagnostic problems to determine feasibility, isolate interest zones, enhance stimulation strategies, and optimize the acquisition of high-resolution acoustical data from the wellbore with a new leak-detection tool. This case study discusses the methodology that underlies the successful determination of the depths and the radial locations in the outer casing strings of multiple leaks in an offshore well. Introduction The studied well in the Timor Sea offshore Australia was completed as a horizontal gas producer in 2010. The well featured a single packer completion with 7-in./9 5/8-in. tubing and a horizontal lower completion with a swell packer and pre-perforated 5-in. liner. The well contained a production casing (133/8 in.) with an A/B annulus (7-in./9 5/8-in. tubing×13 3/8-in. casing and 11¾-in./9 5/8-in. liners) and surface casing (20 in.) with a C annulus (13 3/8×20 in.). In late 2016, the pressure of the A/B annulus was observed to have decreased from 10 to 0 barg over a 4-month period, having previously been stable at 10 barg for 1 year. Multiple attempts were made without success to restore pressure by topping up the A/B annulus with inhibited water. In October 2017, the pressure of the A/B annulus was observed to have a slight vacuum effect of –20 kPa. Diagnostic testing was performed to confirm the issue. The A/B annulus was topped off with 46 m3 of inhibited brine. While filling the last 4 m3, with the A/B annulus confirmed full, the pressure plateaued at 4.25 barg while it continued to pump at 145 L/min, which confirmed a potential leak in the A/B annulus. After the pump was shut down, the A/B annulus pressure stabilized at 3.32 barg, and the fluid levels remained full. The A/B annulus pressure, with the well on line, steadily increased to only 4.2 barg, further confirming the presence of a leak. In December 2017, a well-integrity logging suite, consisting of an advanced array leak-detection tool and conventional production logging sensors, was conveyed on wireline to determine the A/B annulus leak location. The decision would be made to suspend the well on the basis of the logging results.

Down-hole isolation towards high-temperature reservoir using packing elements with swellable thermo-plastic vulcanizates

The well completion and fracturing towards deep unconventional high-temperature (HT) petroleum or natural gas reservoirs is considerably strict to the packer especially packing elements. However, existing packing elements including swellable packers usually are made from Hydrogenated Nitrile (HNBR) or Fluorine rubber (FKM) with drawbacks of great expense and difficult tripping into the horizontal wellbore. This paper proposes a compact isolating solution using swellable Thermo-plastic Vulcanizates (TPVs), which is prepared by blending HNBR, low-cost Polyamide66 (PA66) and Porous Super Absorbent Resin (PSAR) with enhanced nanoparticles. The TPVs were characterized by experiments and the system with Plastic/Elastomer Ratio (PER) of 45:55, tensile strength of 18.6 MPa and elongation at break of 635% upon aging (150 °C) was qualified for the packing element material. A novel enhanced packing element is put forward with corrugated-profile structure to address large-size and over-extrusion issues. The numerical study on packer components was conducted based on TPV constitutive model. The prototype with element length of 2.5–2.6 m was validated in the lab and rated as the sealing of more than 70 MPa. An optional disintegrating casing is adopted to avoid the premature damage risk of packers. For the field trial, the multistage fracturing tubular with improved packers was deployed into the horizontal open hole without severe pipe stuck. The fracturing operation was successfully performed and all packers functioned normally with the maximum pressure differential of 73 MPa. It concludes that the new solution exhibited high strength, heat resistance and structure integrity with low cost over the traditional packers towards HT environment.

Rupture of swollen styrene butadiene rubber

Elastomers have recently been explored to make swellable packers in the oil industry, which have many advantages over traditional cement packers. In the applications, the elastomers absorb solvent and swell against the confinement, which can seal zones in the borehole. In addition, swollen elastomers are usually subjected to a large pressure difference, which can cause fracture of the elastomer. In this article, we conduct experimental studies of the rupture behavior of an oil-swellable elastomer, styrene butadiene rubber (SBR), swollen in hexadecane. This combination of elastomer and swelling agent can be considered representative of oilfield applications. Pure-shear tests are used to measure the stretch at rupture and fracture energy of swollen SBR with different swelling ratios. It is found that swelling can significantly reduce both the stretch at rupture and the fracture energy of the swollen elastomer. Using the measured fracture energy, we have also successfully predicted the stretches at rupture of SBR for a simple extension test with different volume swelling ratios.

Interventionless Reservoir-Isolation Valve Removes Need for Intermediate Completion

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184706, “Interventionless Reservoir-Isolation Valve Removes the Requirement for an Intermediate Completion: A Case Study,” by Andrew Edwards, SPE, Euan Murdoch, SPE, and Christopher Munro, SPE, Weatherford, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, 14–16 March. The paper has not been peer reviewed. This paper focuses on the application of radio-frequency-identification (RFID) technology to enable an operator to eliminate an intervention run (or intermediate liner) for a 10,000-ft reservoir section. The case-study well has preperforated liner in two zones isolated with swellable packers and pressure-actuated annulus packers. The typical procedure is to straddle the annulus packers individually using an inflatable plug, but setting the lower annulus packer incurs additional risk while running in the horizontal for an extended distance. Here, an RFID-actuated reservoir-isolation valve (RIV) eliminates an intervention run. Methodology RFID is now a common technology used across various industries to provide a means of communication between a passive antenna and an active antenna. This technology has now been adapted and applied to actuate downhole tools in oil and gas wells. In the RFID portfolio, the installed equipment houses the active antenna and RFID tags that are deployed at surface and provide the passive antenna. The tool provides a secure, pressure-resistant encasement for the electronics required. The RFID tag contains a memory bank to store a command that is programmed at surface and a coil that takes power from the radio-frequency field generated by the active tool antenna. This power provided by the active antenna is passed directly to the passive antenna and allows the tag to transmit the programmed command to the RFID tool. The command is then decoded and processed within the tool and then acted upon. The command can include logic to tell the tool to function immediately, function after a delay, or switch operating modes to look for another trigger. The small size of the tag allows freedom of movement and easy integration with existing completions. Because RFID transmission is a close-proximity means of transferring data, it requires no direct contact between both devices. The communication can be made in a downhole context at up to 6 to 12 in. RFID technology has so far been used in drilling applications, in upper-completion equipment, and in the reservoir as an inflow-control-device sleeve or for providing a multizone stimulation sys-tem in slickwater or hydraulic proppant.

A 5-Year Journey of Advanced Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175330, “Five Years’ Journey of Advanced Completions for the Kuwait Oil Company,” by Mohammed A. Siddiqui, SPE, Ahmad K. Al-Jasmi, SPE, Menwer M. Al-Rasheedi, and Hashem F. Al-Abdullah, Kuwait Oil Company, prepared for the 2015 SPE Kuwait Oil and Gas Show and Conference, Mishref, Kuwait, 11–14 October. The paper has not been peer reviewed. With the objective of increasing its production to 4.0 million BOPD, the Kuwait Oil Company (KOC) is developing its fields with optimum technology solutions. One of these promising technologies is that of advanced completions—specifically, inflow-control devices (ICDs) and interval-control valves (ICVs). Application of this technology led to multifold increases in sustained production in horizontal wells in all reservoirs and a simultaneous reduction in water cut. Introduction The main reservoir objectives for applying advanced completions include decreasing the influence of heel-to-toe effects, controlling influx from high-permeability zones, delaying water/gas fronting, depleting the reservoir uniformly, and improving well cleanup and sweep efficiency. Advanced completions are applicable in both sandstone and carbonate reservoirs. The ICVs also provide the advantage of controlling production from multiple laterals in multilateral wells and controlling influx in layered reservoirs. KOC operates several prolific oil reservoirs with significant differences in geological and fluid characteristics (these are described in detail in the complete paper). ICDs (conventional or advanced) are passive flow-velocity restrictors and offer excellent regulation of flow through the constricted openings (Fig. 1). An optimal pressure drop can be achieved through this equipment in a comprehensive downhole completion design that includes ICD type, placement methodology, and well-thought-out and optimally planned reservoir segmentation with use of geological and petrophysical data. The compartmentalization of the lateral section can be achieved through swellable or mechanical packers. ICVs are intelligent well-equipment systems whose functions, in principle, are similar to those of the ICD in terms of reservoir management. Additionally, they allow operators to control flow into or out of a segmented reservoir interval wherever selective control over production or injection is required.

Tandem Downhole-Isolation-Valve System Eliminates Snubbing

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173043, “First Ever North Sea Deployment of Tandem DIV System Eliminates Snubbing—A Case Study,” by Gary Mueller, Weatherford, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. The operator of an offshore jackup rig in the North Sea required safe and efficient deployment of the completion string without killing the well during tripping. A solution other than a snubbing unit was needed because of the length of the completion string, which included 12 swellable packers for 13 zones. To provide for a safer, less-expensive, and efficient method of tripping pipe, the operator chose a downhole-isolation-valve (DIV) solution that allowed for the process to be performed in a conventional manner under conditions of complete well control. Introduction During the past decade or so, the industry has developed drilling methods to address more-complex and - challenging prospects such as ultradeep prospects, deepwater applications, and high-pressure/ high-temperature wells in order to continue meeting the worlds’ demand for energy. This seemingly insatiable demand has led to the development and widespread use of unconventional techniques such as underbalanced drilling (UBD) or near-balanced drilling and various forms of managed-pressure drilling, including pressurized-mud-cap drilling (PMCD) and constant- bottomhole-pressure drilling with their attendant well-control and safety challenges. Some of these challenges are Moderate to severe lost-circulation conditions and consequent nonproductive time (NPT) Formation damage as a result of having to kill the well before tripping pipe Pore-pressure and fracture-gradient similarity leading to kick and loss cycles and well-control problems A necessity for snubbing techniques to trip the pipe in and out of the hole above the “pipe light” depth, with the attendant added cost and risk Overall operational safety and environmental issues Operational economics and the effect of resulting NPT As a result of these challenges, mitigating drilling hazards has become an extremely important facet of drilling operations and has prompted the development of procedures and equipment designs to address them, one of which is the DIV.

Technology Update: Flexible, Single-Skin Completion Concept Meets Well Integrity, Zonal Isolation Needs

Technology Update As deeper and more complex well designs proliferate throughout oil and gas fields, well completion methods are challenged and new technologies are emerging to ensure safe, cost-efficient, and optimized completions. The Welltec Flex-Well completion concept is a flexible, single-skin (monobore) system that allows fit-for-purpose completion designs that can be as minimal or intricate as needed for optimal reservoir drainage and do not require the use of cement or swellable packers (Fig. 1). Reliable and effective annular barriers continue to be crucial to well management for safety and performance. Cementing has been the industry’s conventional means of creating these barriers, having been used for almost 100 years (American Oil & Gas Historical Society 2015). However, the industry is not drilling and completing wells the way that it did a century ago. The advances in drilling, particularly those related to horizontal well technology, have led to well designs and completion environments that often exceed the capabilities of cement to provide a reliable annular barrier that will last as long as the well. Efforts to overcome the challenges of many of today’s wells with cement can lead to complicated, expensive, and time-consuming operations. The use of certain swellable packers has arisen as an accepted alternative, primarily because of time savings. However, their degradable polymer content has a significant risk of failure in harsh downhole well environments. Wells with swellables have been shown to leak approximately 50% of the time after 5 years from the time of installation (Plessing and Arnskov 2011). With more than half of the world’s rigs drilling highly deviated or horizontal wells, and an increasing number of mature fields with depleted well zones, the challenges of such wells call for barriers that not only are cost-efficient but will also remain effective throughout the well’s lifetime. Expandable Annular Barrier A key component of the flexible, singleskin completion system is the Welltec Annular Barrier (Fig. 2), an all-metal expandable barrier with a large expansion ratio that was developed for a wide variety of applications in well construction, including well integrity and zonal isolation. Designed for the specific well during its construction phase, before the well is spudded, the barrier delivers reliable annular isolation and maximizes the ability to handle pressure change across the entire borehole, without internal restrictions, over the life of the well.

Technology Focus: Hydraulic Fracturing (March 2015)

Technology Focus Hydraulic fracturing is a necessary enabler to exploit oil and gas from moderate and tight reservoirs. Numerous novel technologies and state-of-the-art procedures have been applied recently. These include drilling technologies, completions assemblies, stimulation fluids, fracturing proppant, and pumping sequences. The goal of these approaches is to improve the efficiency of hydraulic fracturing, increase reservoir contact with the wellbore, expedite cleanup, and enhance well productivity. Among the tools and techniques being used to exploit hydrocarbons efficiently are real-time geomechanics to avoid wellbore instability, multistage openhole or plug-and-perforate (PAP) completions to induce multiple independent fractures, high-strength proppants to overcome fluid damage and sustain conductivity during the depletion stages as stresses rapidly increase, clean fluids to ensure permeability stays high and fractures clean up quickly during production while enabling proppant transport and fracture propagation, and pump-stage pulsing to induce open channels to enhance fracture conductivity further. The widely used resin-coated proppants that prevent proppant flowback during production but contribute to lower conductivity are being replaced by irregularly shaped proppants with grains that bond to one another, thereby preventing proppant movement while providing high conductivity. Initiating and propagating independent hydraulic fractures is challenging in an openhole completion because fractures tend to cross zonal-isolation boundaries, particularly during acid fracturing. Swellable-packer assemblies, which are much longer than conventional mechanical packers and can assume the shape of the hole, have addressed this challenge somewhat successfully. Swellable packers compress the rock at a much lower pressure than mechanical packers, thereby eliminating rock cracking and the creation of unintentional fractures. Completing and stimulating wells with PAP technology has gathered attention because zonal-isolation problems are readily solved and multiple independent fractures are generated easily. The challenge is to know and accurately perforate the sweet spots and drill out the plugs efficiently after the treatment. To stimulate long intervals with high heterogeneity and variations in reservoir properties, fluid additives such as chemical and fiber diverters are being improved continuously to achieve near-equal distribution of acid throughout the stimulated interval. The challenge of breaking down very tight and high-stress formations without reaching tubing pressure limitations and compromising integrity remains, and several processes—including higher completion grading, the use of chemicals and progressive propellant pretreatments, and enhanced perforation techniques—are being investigated. Improvement in well-stimulation and hydraulic-fracturing processes is dynamic. The USD-30-billion industry contributes to a giant share of the total world energy market. It is truly a great sign and encouragement to see that the industry has the talents needed to optimize the technology. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 170743 Minimizing Overflush Volumes at the End of Fracture- Stimulation Stages—An Eagle Ford Case Study by Wadhah Al-Tailji, StrataGen, et al. OTC 24975 Numerical Analysis on the Interaction Between Two Zipper Frac Wells Using the Continuum Damage Method by Xinpu Shen, Halliburton SPE 163975 Evolving Khuff Formation Gas-Well Completions in Saudi Arabia: Technology as a Function of Reservoir Characteristics Improves Production by Zillur Rahim, Saudi Aramco, et al. IPTC 16580 Rock Mechanical Properties of Shale Gas Reservoirs and Their Influences on Hydraulic Fractures by Qinghui Li, China University of Petroleum, Beijing, et al.

KINETICS OF SWELLABLE PACKERS UNDER DOWNHOLE CONDITIONS

Swellable packers have been widely employed in various oil-field applications. Examples include zonal-isolation, water shut-off, and multi-stage fracturing. Key factors required for these applications are how fast the packer can seal the borehole as well as how fast a certain amount of contact pressure can build up. These factors, which are generally measured from full-scale packer tests, can be estimated through numerical simulations together with lab-scale experiments. In this work, we have developed a three-dimensional continuum level model and simulation capability to study the behavior of swellable packers affected by various downhole conditions. Such conditions include the borehole type, i.e., permeable or non-permeable borehole, and downhole uncertainties, i.e., variations of borehole size and borehole temperature, which are studied systematically through numerical simulations.

Flow Segmentizers Reduce Erosion of Standalone-Sand-Screen Completion

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25019, ’Reduced Erosion of Standalone-Sand-Screen Completion With Flow Segmentizers,’ by M.S.A. Zamberi and S.N.A. Shaffee, Petronas Group Technical Solutions; M. Jadid, Z. Johar, and I. Ismail, Petronas Carigali; and C.Y. Wong and C.B. Solnordal, CSIRO, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Standalone-sand-screen (SAS) completion, especially in horizontal gas wells with high potential for sand production, typically suffers from premature failure caused by sand erosion resulting from high velocity in the annulus near the heel section. This paper describes the work conducted to understand in detail and quantify the erosion risks to SAS completions in horizontal gas wells and to pursue a proof-of-concept assessment of using swelling-elastomer packers to segmentize the flow in the annulus as a means of reducing erosion risks near the heel. Introduction During the production phase, decreasing pore pressure will cause a concentration of stresses around the wellbore and perforations, leading to failure of the rock and subsequent transportation of sand particles from the wellbore to the sand-control- equipment interface (e.g., sand screens and gravel pack). In scenarios when downhole sand control is no longer effective, the produced sand will be transported to the surface, leading to other issues such as sand deposition in pipelines and erosion of surface flowlines and equipment. In gas-dominant systems, as gas is produced from the bottom of the hole to the surface, the volume of gas increases with decreasing pressure, resulting in a significant increase in gas velocity in surface flowlines and equipment, from approximately 1 m/s at the heel section downhole to more than 10 m/s in surface flowlines. Compared with liquid-dominant systems, the relatively low viscosity and density of the gas will cause the sand present in the gas flow to easily escape from the bulk fluid-flow stream and affect surfaces at high velocities, thereby posing significantly higher erosion risks. It is important to ensure that any downhole sand control applied in gas-dominant systems is reliable, with features that reasonably reduce the risk of premature failure. In the case of SAS completion, most authors and researchers have concluded that screen erosion is by far the most common failure mechanism. It has also been noted that annular flow plays a significant role in the erosion and failure of sand screens in horizontal gas wells. Despite these technical challenges, application of SASs, as opposed to gravel packs, in horizontal openhole completions has the potential to significantly reduce capital expenditure, expedite well development, and improve productivity (skin). With these factors as the motivation, a proof-of-concept project involving experimental and computational-fluid-dynamics (CFD) models was conducted to assess and develop a methodology to use swellable packers to reduce annular-flow velocity, thus reducing the erosion risk on SAS completions.

Fiber Optic Feed-Through Packer Technology Assists Multizone Fracturing and Production Monitoring

Young Technology Showcase Fiber optic pressure and temperature (P/T) sensing technology for multizone fracturing and production monitoring is enabled by a new feed-through (FT) technology that integrates the optical fiber within the multiple elastomer elements of a compact, swellable openhole packer system to achieve competent zonal isolation. It is important that a continuous length of optical fiber be installed across the multiple zones isolated by the swellable packer system. Splicing the fiber is problematic because the process is time c4onsuming, and the splice point degrades faster than uncut fiber. Over time, the splice presents a weak point that can limit system life. This is compounded in long, multizone completions that may require as many as 40 isolation points along the well. Weatherford’s Fraxsis FT technology facilitates deployment of continuous lengths of optical fiber across multiple zones as part of a modular packer system made up of short (24-in.) swellable elastomer sections that provide high-pressure zonal isolation. The FT technology is also a key enabler in the development of a faster, spoolable fiber deployment capability. Fiber optic monitoring of a fracture stimulation and the resulting production across every stage of the completion provides engineers with the information to improve stimulation and completion design, and optimize production over the life of the well. The FT technology enables fiber-optic monitoring using a proven packer technology that achieves high-pressure zonal isolation with a much shorter inflatable element, which reduces packer stiffness and makes the system easier to run. Technical Details The FT packer design is based on a modular approach that uses single or multiple swellable elastomer elements to create isolation points for the completion (Fig. 1). Each element incorporates a proprietary metal backup system to achieve a higher pressure rating with less than half the length of a conventional swellable packer. The metal backup system expands concurrently with the elastomer to prevent extrusion of the rubber element and form a higher pressure seal. Depending on the completion’s pressure requirements, 24-in. elastomer sections are added to the packer system to achieve 1,500 psi (one element), 3,000 psi (two), and higher-pressure specifications. As a result, the technology allows a packer only 7 ft long to seal up to 5,000 psi with the same hole-conformance of traditional swellable packers.

Water and Sand Control Technology Successfully Applied in Jidong Oilfield: A Case Study

In order to solve the growing water production problem of screen pipe completed horizontal wells in unconsolidated sandstone reservoirs, water and sand control screen pipe was developed. By combining swellable packers, installing different sized nozzles, and assorting corollary tools, a water and sand control completion string was formed and then field tests were carried out. The field application shows that water cut of water and sand control screen pipe completed horizontal wells raises much slower compared to conventional screen pipe completed horizontal wells.