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_ Early January brought with it significant changes in the environmental side of the oil and gas industry. ExxonMobil and Chevron, the two largest US oil producers, announced they will exit California, and the Biden administration froze LNG export approvals. After 50 years of producing oil in California, ExxonMobil will take a $2.5 billion writedown of the value of some of its California properties to be recorded in its fourth-quarter earnings. The company said the decision is primarily related to its Santa Ynez operations off the coast of Santa Barbara. Its US Securities and Exchange Commission (SEC) filing said, “While the Corporation is progressing efforts to enable a restart of production, continuing challenges in the state regulatory environment have impeded progress in restoring operations.” After the Refugio oil spill in May 2015 (approximately 100,000 gal), resulting from a leak from a pipeline owned by Plains All American Pipeline, ExxonMobil acquired the damaged asset in October 2015. Just a few months before the purchase, the Santa Barbara County Board denied ExxonMobil’s request to truck its oil produced off the coast of Gaviota to its Las Flores Canyon processing facility and on to refiners located in Pentland, California. Seeking an alternative, ExxonMobil planned to replace two stretches of the 112-mile corroded pipeline for transit of its oil. Met with opposition to replace the damaged pipeline and denied permission to repair and restart production at the site (halted since 2015), ExxonMobil is now selling the Santa Ynez operation to Sable Offshore, a blank-check company created in 2020. The company will loan Sable the money for the purchase of its three offshore production platforms, pipeline, and onshore processing facility. Sable’s agreement with ExxonMobil requires production to be started by early 2026 or the assets and liabilities revert to ExxonMobil. Chevron, headquartered in San Ramon, California, will write down $3.5 billion to $4 billion in assets, citing its home state’s regulations that “have resulted in lower anticipated future investment levels.” The company intends to continue operating its oil fields and related assets. In the SEC filing, Chevron wrote it also will incur fourth-quarter charges related to decommissioning of US Gulf of Mexico assets that have reached the end of their productive lives. The company sold some of those assets, but US law stipulates that previous owners may be responsible for those costs if the current owner declares bankruptcy. Chevron wrote it’s “probable” that it may see such costs. January closed with another unexpected announcement on 26 January. The Biden administration paused decisions on permits to export LNG to non-free trade agreement countries to review current projects seeking approvals. US Energy Secretary Jennifer Granholm stated, “We must review export applications using the most comprehensive, up-to-date analysis of the economic, environmental, and national security considerations.” She added that this was not a ban on exports and would not affect already authorized exports, which when combined with existing plants, total 48 Bcf/D. “Within this decade another 12 Bcf/D of US export capacity already authorized and under construction will come online,” Granholm said. While environmental impact (greenhouse gas emissions including CO2 and methane) was one of the reasons for the decision, along with market, economic, national security, and energy security, Granholm pointed out that facilities totaling 22 Bcf/D of capacity have been approved but have not yet started construction. This capacity, combined with existing infrastructure, is “more than enough to make the US a ‘behemoth’ in the LNG field,” according to Holland & Knight in an analysis dated 29 January. The international law firm said this raises the question of whether further development of LNG facilities could hurt US citizens as higher percentages of produced gas are exported. “This line of thinking follows the historical rhetoric on this issue as domestic users of natural gas want to ensure their feedstock price is stable. To support those claims, recent studies have concluded that ‘higher LNG exports create a tighter domestic natural gas market (all else held equal), increasing domestic natural gas prices.’” Could unintended consequences of these recent announcements rear up in the future? And could they be a behemoth for the US or global markets? For Further Reading Growth in 2022 US LNG Liquefaction Capacity Hits Top of the Charts by Pat Davis Szymczak, SPE Oil and Gas Facilities.
- North America > United States > California > Santa Barbara County (0.25)
- North America > United States > California > Contra Costa County > San Ramon (0.25)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, “Enhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,” by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed. _ The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented. DTT DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals. In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall. A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.
As bottomhole-assembly and drill-bit design and operation have embraced new technologies such as artificial intelligence, new materials and manufacturing techniques, and improved design software, the industry continues to research methods of optimizing delivery and understanding of already globally used technologies. It is this approach that has long allowed service companies, operators, and drilling contractors alike to improve drilling performance, as highlighted in the papers summarized here. In the first of these papers, paper SPE 210723, finite element fatigue simulation has been used to minimize the risk of twistoffs in jars, something that many of us in the drilling community have experienced. This paper can help us reduce those unplanned events and lost time. Many rigs worldwide have moved to using autodriller-type control systems, and, in many cases, these systems have shown improved performance. In the second paper, paper SPE 214997, the optimization of these systems is discussed in the review and modification of driller procedures to minimize damage to bottomhole assemblies and the drill bit during drilling. Finally, while many papers have discussed high-frequency torsional oscillations and their effect on the bottomhole assembly and drill bit from an operational or a theoretical view point, the final paper, paper SPE 212566, discusses full-scale laboratory experiments to qualify the drill bit’s influence on this effect. All three of these papers highlight increased understanding in the operation and evolution of existing technologies to improve drilling delivery. In the evolving world of drilling where the final objectives and uses of wells are changing—whether for repurposing; carbon capture, use, and storage; or geothermal uses—these approaches to optimizing existing technologies in conjunction with the introduction of new technologies can help oilfield drilling teams pivot into this adjacent energy environment to deliver successful wells. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212438 Building a System To Solve the Challenges of Drilling Hot Hard Rock for Geothermal and Oil and Gas by Anthony Pink, NOV, et al. SPE 212559 Machine Learning-Based Drilling System Recommender: Toward Optimal BHA and Fluid-Technology Selection by Gregory Skoff, SLB, et al. SPE 212109 World’s First Application of Steel Body Bit in High-Chloride Formation With Water-Based Mud by Bekbolat Uandykov, Zhigermunaiservice, et al.
- Well Drilling > Drillstring Design > BHA design (1.00)
- Well Drilling > Drill Bits (1.00)
Though disparate locations, outer space and the oil field have much more in common than one might think. Both can be taxing on operations and often redefine the idea of an isolated and, at times, hostile work environment. Harsh atmospheric conditions and wide-ranging pressure regimes call for unique technological applications and operations to achieve the best performance and results, whether it’s the gravitational and meteorological challenges of another planet or the crushing pressures and changing meta-ocean conditions of the deep offshore. Despite the obvious differences, operating in both the terran oil field and the blackness of space offer hurdles that can be cleared by similar means. Shared technologies between the two industries have been around for decades and center around disciplines like automation, robotics, and remote sensing. The National Aeronautics and Space Administration (NASA) itself has dabbled in oilfield studies, especially when it comes to greenhouse gas emissions and their impact on the atmosphere. In 2021, the agency’s Jet Propulsion Laboratory, along with the University of Arizona and Arizona State University, completed a study to identify methane super-emitters in the Permian Basin. The month-long, airborne study concluded that fixing the worst leaks identified in the area’s infrastructure could cut methane emissions by 55 tons an hour, equivalent to 5.5% of the US Environmental Protection Agency’s estimates of all methane emissions from hydrocarbon production across the entire US. The study pointed to malfunctioning equipment as the likely culprit for the 123 sources found. Conversely, NASA has also tapped into oilfield technology for some of its planned drilling operations on the moon. It will be the first such operation on any planetary body outside of the Earth. One of the earliest directives of NASA’s Artemis program is to try and find water near the lunar South Pole. Polar Resources Ice Mining Experiment-1 (PRIME-1) will be the first in-situ resource utilization demonstration on the moon. For the first time, NASA will robotically sample and analyze for ice from below the surface. PRIME-1 will use TRIDENT (The Regolith and Ice Drill for Exploring New Terrain) to drill in a single location at a site with a high likelihood of having water, whether in liquid or ice form. TRIDENT was developed and supplied by Honeybee Robotics, which also supplies geotechnical tools and sensors, among other tech, to the oil patch. The system, to be integrated into VIPER, NASA’s first robotic moon rover, will drill about a meter below the surface, each time bringing up samples that NASA will analyze with a mass spectrometer. The launch of the NOVA-C, which carries the PRIME-1, was previously delayed. At press time, the payload was due to blast off on board Space X’s Falcon 9 rocket in early 2024. NASA said in October the VIPER will reach its destination at Mons Mouton near the lunar South Pole in November 2024.
- Government > Space Agency (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211175, “An Innovative Method of Water Management by Desalinating Produced Water Using Thermal Renewable Energy,” by Sharifa M. Al-Ruheili, Felix Tiefenbacher, and Khansaa H. Almahrami, ARA Petroleum Exploration and Production, et al. The paper has not been peer reviewed. _ The operator is adopting a method to manage high-salinity produced water in an environmentally sustainable way by extracting potable water from produced water and reducing discharge water volume by at least 50%. For desalination of the produced water, a combination of forward and direct osmosis technology is used. This process is driven mostly by thermal energy, which is provided to thermal collectors that are 100% solar. This technology uses renewable energy and will have no carbon footprint. Technology Description The technology involves concentrated solar thermal (CST) power plants that provide 100% renewable water desalination. Forward osmosis (FO) and direct osmosis (DO) can desalinate highly saline and polluted water, such as produced water, mainly with solar thermal energy. A pneumatic solar thermal plant consisting of two HELIOtube collectors, each 121 m long, provides the thermal energy for the desalination process. The plant includes a mirror technology based on CST, a cost-effective heat-transfer system using pressurized water as heat transfer fluid (HTF), and a low-maintenance thermal energy storage (TES) system allowing nighttime operations of 35 m3 volume with an operating temperature of 180°C using a pressurized water tank at 10-bar operating pressure. The desalination system will contain a pretreatment unit for the produced water and a desalination (FO) and brine-concentration (DO) unit. The unit will be integrated with thermal power to operate the desalination plant. In addition, a fully automated control system with a live backup will be installed. The system is classified as having low maintenance and cleaning costs because of its encapsulation features, rotatability of 300°, and convex shape. Fig. 1 of the complete paper shows the planned plant layout. The desalination plant will feature two outputs: fresh water of potable quality and brine. The fresh water will be used to serve the company’s freshwater demand, with excess water used for agricultural purposes or mixed with water in an injector well to improve injectivity. The other output, the highly concentrated brine (20% salt), will be collected in the existing evaporation pond where two main research and development studies are ongoing, one related to mineral extractions and the second related to salt monetization (using salt as a drilling additive).
- Water & Waste Management > Water Management > Water Supplies & Services (1.00)
- Energy > Renewable (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Reuse (0.35)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211167, “Selective and Reversible Water-Shutoff Agent Based on Emulsion System With Nanoparticles Suitable for Carbonate Reservoirs at High-Temperature and High-Salinity Conditions,” by Masashi Abe, SPE, Jumpei Furuno, and Satoru Murakami, Nissan Chemical Corporation, et al. The paper has not been peer reviewed. _ The complete paper presents the evaluation results of a water-shutoff (WSO) agent based on an emulsion-type chemical material with nanoparticles. The WSO agent, which the authors call an emulsion system with nanoparticles (ESN), has several advantages to existing polymer and gel materials, including high thermal stability, low sensitivity to mineralization, thixotropic characteristics, selectivity of blocking effects for oil and water, and reversibility of blocking effects. In WSO applications, these properties of ESN could be well-suited for improved oil recovery. Introduction ESN is recognized as a proven technology for carbonate reservoirs. However, the reservoir under study did not feature harsh conditions; therefore, this work evaluated ESN potential for carbonate reservoirs in the UAE typically having high-temperature and high-salinity conditions. A primary purpose of the technology, aside from improved oil recovery, is contributing to greenhouse-gas emission reduction and building competitive low-CO2-intensity oil-brand value. In general, produced water volume dramatically increases in maturing oil fields. Reducing water production also can contribute to saving water injection from a reservoir-voidage-replacement viewpoint. Therefore, the functional chemical WSO concept has a significant effect on contributing to the International Energy Agency’s sustainable development scenario. Materials and Physicochemical Property Tests Oil, Water, and Carbonate Core. Dead oil is sampled from an offshore carbonate field in the Middle East containing light crude oil (32.3 °API). Brine and plug core properties are summarized in Tables 1 and 2 of the complete paper. For thermal-stability tests, both brines were used for making the ESN. The WSO coreflood tests used the ESN made with injection water. Advanced Features of ESN. Rheology. The viscosity of ESN is controllable by changing the water/oil ratio; viscosity becomes lower with increasing oil content and higher with increasing water content. These components were stirred, and two ESN samples were prepared using Crude Oil A (from Oil Field A, UAE) or diesel oil. The samples are referred to as Crude Oil A-based ESN and Diesel Oil-based ESN in this paper. Both ESN samples showed similar viscosity curves; such thixotropic characteristics are an important property of ESN. ESN is flowable at stirring conditions. In particular, the viscosity of ESN can be decreased to less than 50 cp at high shear rates, so it can be injected into the reservoir by pumping. On the other hand, ESN becomes highly viscous and less flowable when no energy is applied to it (the ESN surface looks semisolid in this condition). In field operations, the viscosity of ESN decreases depending on the pressure generated by injection pumps on the surface. However, the injection pressure also releases in a radial direction from the bottomhole zone. As a result, ESN recovers a high-viscosity state because of decreasing shear rate with pressure release.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212443, “Real-Time Anomaly-Detection Methodology for Drilling-Fluid Properties,” by Moacyr N.B. Filho, Thalles P. Mello, and Cláudia M. Scheid, Federal Rural University of Rio de Janeiro, et al. The paper has not been peer reviewed. _ Online drilling-fluid-measurement technologies have become an essential tool for drilling automation. While online density measurements are widespread, the availability of rheology measurements is increasing quickly, and additional properties are central to ongoing field trials. The complete paper presents the concept of supervisory and advisory systems dedicated to support the detection of abnormal events and to provide guidelines for fluid treatment. Introduction The Laboratory of Fluid Flow of the Federal Rural University of Rio de Janeiro and Petrobras developed a flow loop for the proposal and validation of online sensors for the measurement of drilling-fluid properties. In previous work, the authors described the development of a set of online sensors to measure fluid properties with control of operational conditions of temperature, pressure, and fluid flow rate. Following previous research, this study proposes a new method using a technique based purely on data to diagnose and detect deviations in drilling-fluid properties. The method proposed applies principal component analysis (PCA) for detecting anomalies in drilling fluids. Method PCA-Based Anomaly-Detection Technique. This method consists of the linear transformation of the space of monitored variables, which generates a new space of variables called principal components, in which each principal component is a linear combination of the process variable. This allows the new space of variables to be linearly independent—that is, the principal components are linearly independent, allowing the calculation of process monitoring statistics. The ability to detect anomalies in drilling-fluid properties is necessary to train the system in the normal state of operation. The training based on the normal state of operation was performed through the calculation of the principal-component matrix and the selection of the reduced principal-component matrix. Once the process model was trained, the monitoring of new samples was performed with the help of two statistical tools that described the health of the process operation: T² and Q statistics. The T² statistic measures variations in the main space. T² only detects variation in the subspace of the first principal components larger than those attributed to the dynamics of the process. The Q statistic denotes the change of events not explained by the principal-component model. It is a measure of the difference, or residual, between a sample and its projection on the model. The failure-detection procedure based on the use of PCA consisted of continuous assessments of whether process statistics were within or outside an acceptable range. A method previously proposed in the literature used control systems based on fuzzy logic to monitor properties of drilling fluids and propose corrections, which are performed automatically by an experimental unit containing actuators for additions of drilling agents as thickeners and viscosifiers. The application of fuzzy logic depends on inference rules, which must be provided to the system by the programmer. This is a limitation of corrective systems based on fuzzy logic.
Today, the industry faces tremendous challenges related to safety, efficiency, sustainability, and socioenvironmental responsibility. At every stage, well-construction projects must be concerned about those aspects to establish measurable barriers for preventing issues. Therefore, drilling and completion fluids are critical for achieving project goals and ensuring operations are executed as planned. Drilling and completion fluid selection is a complex process in which addressing future downhole conditions for predicting potential problems is vital to eliminating nonproductive time. Conventional deep high-pressure/high-temperature wells in South sub-Andean Bolivia or unconventional long horizontal wells in Argentina are pushing drilling-fluid design to its limits with regard to keeping equivalent circulating density (ECD) as low as possible while preventing formation damage. Paper SPE 211539 describes several successful applications of low ECD organophilic clay-free inverted emulsion fluid in reaching project goals in challenging environments. On the other hand, constant monitoring of drilling-fluid properties also is necessary. Fluid properties must be monitored so additives can be adjusted to prevent problems. Even though conventional monitoring relies on humans for performing periodic tests, recent technology developments offer a solution for complex drilling operations by allowing continuous real-time monitoring of drilling-fluid properties using sensors and artificial intelligence, as fully described in paper SPE 212443. Finally, discussion of drilling and completion fluids must mention solids-control equipment. Ensuring that fluid properties are within acceptable ranges without discarding valuable additives is the main objective of any solids-control-equipment arrangement. Things become more complicated when working with low-density drilling fluids, where a comprehensive understanding of solids-removal techniques and their customization for a particular application requires research and laboratory-scale trials, which are rare in the literature. Paper SPE 212470 provides relevant and novel information through a full-scale test program for solids-control-equipment efficiency optimization focused on treating low-density muds. Recommended additional reading at OnePetro: www.onepetro.org. SPE 211509 High-Fluid-Loss Squeeze and Reticulated Foam Lost-Circulation Material Plugs 40,000-Micron Laboratory Simulated Fracture/Vug Opening by Sharath Savari, Halliburton, et al. SPE 214171 Using Cerium Oxide (6.0 SG) as Weighting Material in HT/HP Drilling Fluids by Gholam Reza Soori, Cahya Mata Oiltools, et al.
- South America > Bolivia (0.41)
- South America > Argentina (0.26)
_ Having had the privilege of living on three continents, working across multiple industries, and conducting business in several countries, I have seen the impact digital technology has on business, people, and communities. Throughout my career, I have witnessed lifesaving and life-changing digital innovation that changes the trajectory of organizations and industries. As someone who entered the workforce during the dot-com era with a background in computer science, I continue to be amazed by how yesterday’s differentiation becomes today’s necessity … and tomorrow’s obsolescence challenge. The pace of innovation in digital is unprecedented in the annals of human innovation. Personally, I only need to look at my kids to get a sense of that. While we learned to ride a bicycle the same way despite a 3-decade gap, the way we communicate, interact, learn, and create is radically different, enabled by digital platforms that permeate every aspect of life. It is natural therefore to envision that the generations that grow up in these digitally enabled environments will expect, demand, and enable the same degree of digital connectivity in business as they come into and subsequently lead our industry. Oil and gas is an industry that is not just impressive in size, scale, and scope. It is also a sector that deploys technology across the spectrum of breadth and depth. It is unique in that it enables the convergence of several technology domains, including mechanical, material science, hardware, software, automation, instrumentation, artificial intelligence (AI), and others. That, too, in some of the most extreme conditions of temperature, pressure, and accessibility on the planet. Natural business drivers like operational efficiency have been complemented by workforce changes and sustainability agendas to enable this array of technological prowess. In the recent years, companies have leveraged digital as a competitive advantage. Digital technologies have enabled cost efficiencies, speed of operations, and safety enhancements. However, like in other sectors, there are fast followers as well as disruptors who can leapfrog advances. As a result, the industry is embracing digital technology as not just a differentiator, but as an enabler of innovation. The simple reality is that if one doesn’t, they risk being out of the game. Generational Changes One of the biggest drivers I see in the changes taking shape across our industry stems from a convergence of several shifts in the workforce. It is well known that the sector has an aging workforce, and the Great Crew Change is upon us. That, coupled with the fact that we are seeing labor shortages in some markets and that it has become increasingly harder to attract talent into this space, necessitates change. For example, in the post-COVID-19 pandemic era, we are seeing an increased desire to work from home vs. take on rotational work—the jobs that are based in the field are not as appealing as they were a generation ago. In addition, the incoming generation demands that large corporations do more to make a positive impact on the world. And they’re right. We have a duty to act responsibly, to improve quality of life, and reduce environmental impacts. We must think and act differently if we are going to continue competing for top talent—the type of talent that will continue revolutionizing the industry. So, what does that mean? From my perspective, there are a several key areas our industry must continue investing in.
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.90)
While refracturing has maintained a backseat role in the US shale sector, with capital overwhelmingly flowing toward new well programs, there’s been a notable exception brewing in the Barnett Shale. Last year, from within the asset that holds the very well that ignited the shale revolution, gas producer BKV Corp. announced that it had become the top refracturing operator in the US. From November 2020 through February of this year, covering a span of just 28 months, the Barnett Shale operator completed an eye‑opening 369 Barnett refracs. The breath of life BKV pumped down those north Texas wells was enough to temporarily arrest the decline rate of the most mature of all shale plays. BKV reports that the Barnett refrac program has generated 371 Bcf/e of newly proved reserves with a finding and development cost of $0.79/Mcf/e. But putting these figures aside, what else stands out about the campaign is how it was done. To rejuvenate many of the vintage wellbores, the Denver‑based operator, a subsidiary of a Thailand‑based energy conglomerate, said it developed an innovative approach called the “hybrid expandable liner system.” “It is very simply a combination of both bullhead and liner methods where we attempt to minimize the downsides and maximize the positives of both,” Kevin Eichinger, a senior completions engineer for BKV, explained at a recent SPE gathering in Houston. The concept involves installing as little as a few hundred feet of expandable steel patches over a well’s original heel‑side perforations to allow for several new plug‑ and‑perforation stages. The toe‑end of the wellbore is left unlined but new perforations can be added before it is stimulated using a bullhead treatment. Eichinger, who leads the operator’s refrac candidate selection and job design efforts, described the end result as “liner‑like performance without the cost of a full liner.” The completions engineer outlined these and other details while presenting a technical paper he recently coauthored. The subject of a number of industry meetings since it was first published in June, URTeC 3855094 discusses BKV’s inaugural hybrid refracturing trial that achieved twice the average output of neighboring bullhead refracs while also besting legacy liner refrac performance achieved from operated legacy wells. The success of this first attempt paved the way for hundreds of subsequent jobs in the Barnett where the company operates or holds interest in more than 6,900 wells across 460,000 gross acres. More on BKV’s hybrid refracs follows, but worth noting is that the firm is in the midst of a “quiet period” pending the outcome of a potential move to become a publicly traded company in the US and has refrained from issuing updates about the current state of its operations in either the Barnett or the Marcellus Shale in Pennsylvania.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)