Job Performance Systems (United States)

Artificial lift challenges are as varied as the wells and reservoirs they support. Offshore, the focus may be on maximizing production from aging deepwater completions, while in shale plays the obstacles often involve high water cut and scale. True to form, the industry is developing novel ways to answer these problems. From adaptive gas lift systems, deep-set intelligent gas lift straddles, and nanoparticle-based fluids to surfactant-assisted gas lift, operators are deploying new artificial lift technologies in offshore and onshore settings to drive up production rates, as detailed during SPE’s Annual Technical Conference and Exhibition in October. Conventional gas lift has long been an industry go-to solution for increasing oil production, but some shortcomings associated with the approach prompted a North Sea operator to seek out a variation on the theme. Eivind Samuelsen, a senior petroleum engineer at Aker BP, said that after pilot testing by the operator on an adaptive gas lift system (AGLS) at a field offshore Norway, the technology had reached Technology Readiness Level 7 (TRL7), which is the highest readiness level. Speaking during an ATCE technical session, he said Aker BP plans to install AGLS in 11 wells in that same field to demonstrate the tech’s value. He told JPT the wells will have one-fits-all adaptive gas lift scenarios from day 1. Development of the AGLS started in 2019 as Aker BP strove to overcome limitations of conventional gas lift systems. One key constraint is limited gas lift depth: traditional injection-pressure-operated (IPO) valves require reducing casinghead pressure to close and generally conservative design practices, which limit injection depth and production. This is a drawback because deeper gas lift injections can add reserves, stabilize flow, and accelerate production. Another limitation of conventional gas lift systems is that the IPO and orifice valves must be pre-set based on modeling inputs or expected well performance. Such pre-sets can lead to underperformance, the authors wrote in SPE 228103. The fixed-valve design for a well’s 20- to 40-year lifetime is based on input and uncertainties, Samuelsen said, and “those inputs will probably be wrong.” That means it’s likely the well will underperform or require interventions to change the gas lift design, he said. “Out-of-target reservoir pressure, significant change in productivity index, and so forth. The field development plan, it’ll change. You’ll do infill drilling, you’ll do reinjection. So, what you pre-design is probably wrong,” he said. That made valve adaptability one of the key design requirements for the system Aker BP sought. Functionality specifications included a system compatible with current Intelligent Well Interface Standardization (IWIS) subsea low-power systems; a full range of available orifice valve sizes with automated control; high equipment durability; a two-way adaptive gas lift valve barrier; and a fully retrievable adaptive gas lift valve that could be recovered using a standard wireline tool in case of failure.

_ The oil and gas industry is writing a new chapter for hydraulic fracturing operations, defined by data, iteration, and a relentless pursuit of efficiency. In the Marcellus, an operator leveraged legacy data to refine its next-generation completions, while in the Permian, a four-well campaign showcased the power of iterative learning on successfully drilling out 4-mile laterals. Both highlight the industry’s growing reliance on data and experience to unlock value. Evolving Completions Approaches Targeted analysis of legacy Marcellus well data is helping Repsol shape its next-generation completion designs in the region for optimal business impact. Completions experts from Repsol analyzed data from two pads in the Marcellus to assess whether previous completions strategies—such as well spacing, completion intensity, and the number of clusters treated at once—delivered the expected results. They detailed their sometimes counterintuitive findings in SPE 223577. The research evolved from the question of which variables in the operator’s Generation 2 completions designs, used from 2021 through 2023, drive production results, Stephane Pichon, technical advisor at Repsol, said while presenting the paper at SPE’s Hydraulic Fracturing Technical Conference and Exhibition (HFTC) in February. The operator reviewed existing data from legacy pads, he said, and while the data indicated that about 70% of the clusters in certain wells were producing, the data didn’t indicate why the other 30% were underperforming. “It’s a bit of a disappointment” if reactive data acquisition fails to provide the answers being sought, he said. Analyzing data on the direction of perforations shots—whether from top to bottom, as is typically done, or from the side—revealed “interesting information” that raised the question of whether “we were shooting in the wrong direction,” he said. According to the paper, shooting perforations on the sides results in a 10% reduction in horsepower-hour consumption, easier pump-rate ramp-up, lower treating pressure, and higher pump rate. This approach also resulted in reduced resource usage and lower emissions. The next step for Repsol was to move toward proactive data acquisition. A field test, combined with data acquisition, was designed to answer a specific question and ultimately quantify the impact of key parameters to enhance asset development. Pads A and B were used to illustrate the concept. For Pad A, which is designed with a “fan-out” shape, the goal was to assess the impact of well spacing and completion intensity on well performance (Fig. 1). “What we wanted to know was, ‘Can we offset larger well spacings with larger completions? And how does water loading impact production?’” Pichon said. The three completion intensities assessed for Pad A were low at 1,600 lb/ft, medium at 2,000 lb/ft, and high at 2,400 lb/ft, with stage architecture remaining unchanged across all eight wells. Of the eight wells, five had high water loading, while three had reduced water loading but higher sand concentration. The team used production logs to measure the contribution of each stage to overall production. The paper stated that combining a larger completion size with wider well spacing resulted in higher gas production. The authors also noted that the results indicated that developing the field with fewer wells but larger completions was worth considering.

_ Shell’s entry into a project development agreement (PDA) with Argentina’s state-owned oil and gas producer YPF to initiate Phase 1 of the Argentina LNG export facility may have just reset the debate over whether Buenos Aires can reap the benefits hidden in its vast shale reserves. The facility proposed for construction at Sierra Grande, Río Negro, on Argentina’s Atlantic coast, is intended to use dedicated blocks in the Vaca Muerta shale formation in western Neuquén Province whose gas reserves rank as the second-largest technically recoverable shale gas resources globally. The US Energy Information Administration estimates 308 Tcf, located in approximately 30,000 km2. The PDA to jump-start the $50 billion Argentina LNG project obligates Shell and YPF to collaborate on pre-front-end engineering and design (FEED) activities until a decision is taken on FEED, YPF said in a press statement in late December 2024. Phase 1 envisions deployment of two FLNG units with a combined production capacity of 10 mtpa. Construction of onshore facilities would follow in Phase 2 and 3, raising total capacity to 30 mtpa with gas reaching the liquefaction facility via 580 km of dedicated pipelines, YPF said. Tax Breaks Lure Investments But Argentina LNG isn’t alone. Two other LNG liquefaction and export options are also now under study as Argentina seeks energy independence and a piece of global LNG revenues in the 2030s and beyond with projects driven by Buenos Aries’ new Basis Law which incentivizes investments to construct pipelines and export terminals associated with Vaca Muerta. Projects exceeding $200 million are guaranteed 30 years of legal and regulatory stability if 40% of the investment is made within the first 2 years; projects over $1 billion are eligible for tax breaks including export and import tax exemptions. The LNG initiatives now competing with Argentina LNG include - The Southern Energy FLNG facility championed by 50% BP-owned Pan American Energy, YPF, and shipping company Golar LNG would utilize the Golar Hilli vessel with a capacity of 2.45 mtpa. Independent energy company Pampa Energía recently took a 20% stake to make a foursome in the partnership. - A bid by Tecpetrol, the oil arm of Argentina’s TechintGroup, expects to complete FEED by mid-2025 on a proposed onshore, 4-mtpa modular plant, expandable to 20 mtpa, according to Argentina’s EconoJournal. Though a location has yet to be announced, Tecpetrol is reportedly favoring Bahía Blanca and an industrial park concept so infrastructure such as pipelines and port access can be shared with other companies. EconoJournal reported that Tecpetrol’s project could be integrated with a competitor and for Tecpetrol, its LNG exports would be complemented with gas shipments to Brazil. In August 2024, the government preauthorized Tecpetrol and TotalEnergies to export gas to Brazil whose state-owned oil and gas producer Petrobras still holds a 34% stake in the Rio Neuquén shale gas field in a venture with YPF and Pampa Energía.

This year’s Flow Assurance Technology Focus provides a trio of papers, selected by ChampionX’s Celestina Kissi, concerning the use of advanced techniques in detection, mitigation, and risk calculation. SPE technical conferences and meetings remain a critical conduit for the transfer of forward-thinking research and insight to both project developers and field practitioners who make certain that production is optimized and that goals are met. Paper SPE 216216 investigates asphaltene risks inherent in the gas-injection enhanced oil recovery (EOR) process. The authors’ research identifies what they term “stealth” asphaltenes, referring to asphaltenes detectable only by laser-light-scattering techniques and not by traditional microscopy. These asphaltenes are still flowable and can still pose risks to flow assurance. In the second selection, SPE 218101, the authors delve into the risks posed by hydrate formation in water-alternating-gas EOR operations, particularly during changeover operations, an area in need of further research in the literature. Additionally, the authors explore the effect of natural gas composition on these phenomena. Finally, paper SPE 218700 describes an operator’s development and deployment of a suite of cloud-based digital-twin tools designed to provide online, real-time calculation of scale risk and barrier health on a well-by-well basis. The complete paper includes four diverse case studies in which the described toolkit proved its value. As the technology used in the field sharpens, it will simultaneously overcome long-standing obstacles and discover entirely new ones, such as the challenge posed in the first presented paper. SPE technical conferences will continue to ensure that the flow of innovation reaches the page and the field with equal effect.

Around a decade of research and testing has passed by, and the unconventional sector has yet to show that natural gas huff-and-puff can scale effectively across tight-oil fields. This doesn’t mean enhanced oil recovery (EOR) in shale is a lost cause. Though it does suggest that the industry needs alternatives to the first and most well-known method. Proof of this can be found in North Dakota’s Bakken Shale where researchers, operators, and a firm called EOR ETC have tried to show that the water-alternating-gas method is a cheaper, less gas-intensive way of adding incremental barrels. EOR ETC has indicated on its website that ExxonMobil subsidiary XTO Energy is currently testing the technology. Chevron has also recently shared how it has rethought shale EOR methods by designing a program for production-boosting surfactant injections and gas injections that can be done with artificial lift instead of giant compressors. Another emerging shale EOR concept goes a step further, arguing that the unconventional sector should abandon natural gas injections altogether. Denver-based Shale Ingenuity proposes that liquid-hydrocarbon solvents should be used instead. Shale Ingenuity has patented a process called SuperEOR, which it claims delivered a strong showing during its initial field test in the Eagle Ford Shale of south Texas. After nearly a year of cyclic solvent injections, which began in early 2023, a horizontal well with a 4,400-ft lateral and 16 fracture stages produced 44% more oil than its previous total output. This resulted in a 30-fold boost in flow rate, from 13 to 391 B/D. Building on its initial success, Shale Ingenuity informed JPT that two private producers in the Permian Basin and the Eagle Ford have selected its EOR technology for upcoming projects. Both will involve single four-well pads, with EOR operations expected to begin in 2026. The solvents used in the pilot consisted mostly of natural gas liquids (NGL)—ethane, propane, butane, and pentane. Shale Ingenuity said formulations may include other hydrocarbon and nonhydrocarbon liquids. While the bulk of these products flow straight out of thousands of wellheads in the US shale sector, Shale Ingenuity emphasizes that the key to unlocking their potential for EOR lies in its proprietary method of blending, or “tuning,” the solvents based on formation and crude oil properties. This allows the injected solvents to quickly mix with and help mobilize the residual oil droplets that are trapped in tight-rock formations, according to the company. Robert Downey, founder and CEO of Shale Ingenuity, explained the process. “The tuned solvents we are using have a minimum miscibility pressure (MMP) of 700 to 900 psi, which means it doesn’t take much pressure to drive them into solution. When pumped into the well, they instantly become miscible with oil, and as the formation heats up and the well is reopened, the solvents expand back into gas at 100 to 200 times their liquid volume.” The effect of all this is what he describes as a “supercharging” of the solution gas drive mechanism that promotes the strong early well flow shale wells are known for. This is the energy released by dissolved gas in the oil as it expands during the pressure drop brought on by producing the well.

Rhythmic entrainment is a fundamental aspect of musical behavior, but the skills required to accurately synchronize movement to the beat seem to develop over many years. Motion capture studies of corporeal synchronization have shown immature abilities to lock in to the beat in children before age 5, and reliable synchronization ability in adults without musical training; yet there is a lack of data on full-body synchronization skills between early childhood and adulthood. To document typical rhythmic synchronization during middle childhood, we used a wireless motion capture device to measure period- and phase-locking of full body movement to rhythm and metronome stimuli in 6 to 11 year-old children in comparison with adult data. Results show a gradual improvement with age; however children’s performance did not reach adult levels by age 12, suggesting that these skills continue to develop during adolescence. Our results suggest that in the absence of specific music training, full-body rhythmic entrainment skills improve gradually during middle childhood, and provide metrics for examining the continued maturation of these skills during adolescence.