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The Biden administration called for new protections under the Endangered Species Act for an iconic bird of the Great Plains, a move with major consequences for the oil and gas industry. US Fish and Wildlife Service officials proposed listing as endangered a portion of the lesser prairie chicken's population living in Texas and New Mexico, whose range overlaps with the oil- and gas-rich Permian Basin. The agency stopped short of awarding the same protections to the birds' northern population, in Oklahoma and Kansas, on the grounds that their numbers had declined less drastically. The decision, one of nearly two dozen new conservation measures the administration has adopted in the past four months, underscores President Biden's push to unravel his predecessor's environmental policies. In a separate move, the Environmental Protection Agency abolished a rule restricting what sort of studies the agency can use in crafting public health rules.
Abstract The Delaware Basin encompasses 6.4 million acres throughout Southeastern New Mexico and West Texas. With large players such as ExxonMobil, Shell or Oxy typically grabbing headlines, it's easy to forget the multitude of smaller public and private E&P operators who exist in and around the acreage positions of the aforementioned companies. Regardless of the size of the acreage holding, a consistent theme is that a typical horizontal well drilled and completed (D&C) will yield water cuts of 60-90% at any given period in its productive lifespan. Saltwater production, handling and disposal (SWD) is a drag on lease operating expenses (LOE). SWD costs via trucking, pipeline, or on-lease SWD wells can range between $0.50-$3.00/bbl. As existing infrastructure is exhausted, water handling costs have been projected to rise to over $5.00/bbl. Additionally, restricted access to SWD could cause production curtailments and thus impacting operators beyond direct LOE. Well completion operations are impacted by freshwater procurement costs starting around $0.75/bbl. Regardless of final frac design, water consumption during fracturing operations typically exceeds 500,000 bbls or $375,000 per well. Significant value exists for recycling produced water via an on-lease pit and utilizing it for future frac operations. The produced water turns into an asset if the operator can efficiently manage to substitute higher and higher percentages of freshwater with produced water. Many smaller operators (defined as less than 50,000 acres) may view produced water recycling as an operation best left to large E&P's with their massive capital budgets and contiguous acreage. Fortunately, even a 5 well, section development plan can yield returns from an on-lease produced water recycling program.
Abstract Successful field trials of surfactant-based Production Enhancement (PROE) technology in different shale plays including Permian Basin, Bakken and Eagle Ford indicate that specially tailored surfactant formulations can improve the unconventional well productivity during flowback and production. One major challenge for the operator is to further optimize the surfactant dosage to maximize the economic return. Analysis of the residual surfactant concentration in the produced water (PW) might provide a new path to optimize the surfactant application in the field. Such quantitative measurements can help understand how much surfactant is consumed in the downhole and how much surfactant is in the flowback, and possibly correlate back to the well performance. Additionally, surfactant partitioning and adsorption behaviors can be studied through residual analysis, which will further provide guidance to develop next generation of surfactant formulations. In this study, a liquid chromatography-mass spectrometry (LC-MS) method was developed to accurately measure the residual surfactant concentration in the produced water. The liquid chromatograph (LC) separates the surfactant from sample matrix and avoids the possible interference, and then the mass spectrometer (MS) detects the separated surfactant, signal correlating to the residual concentration. This analytical method provides unrivalled selectivity and specificity compared to other methods reported in the literature. In addition, a Methyl Orange method was developed and can potentially be used in the field for quicker measurements. Produced water samples collected from a Huff-and-Puff treatment in the Permian Basin were evaluated using both methods. Our results indicate that both methods can successfully capture the trend of residual concentration vs. production time. The deviation between LC-MS and Methyl Orange measurements was due to the presence of ADBAC (alkyldimethylbenzylammonium chloride) in the produced water, which is a cationic amine surfactant typically used as biocide in the well stimulation. It produces positive interference and thus leads to a higher residual detection in the Methyl Orange test. Notably, the residual concentration of surfactant in produced water decreased with time after the well was placed back to production, which is consistent with the concept that more surfactant will adsorb to the rock surface or partition into the oil phase over production time. In summary, we believe the LC-MS and Methyl Orange methods can potentially be used to detect residual concentration for any type of surfactant-based applications in unconventional reservoirs including Huff-and-Puff, completion, frac protect, surfactant flooding and re-frac. The field application of surfactant-based chemistry followed by this type of residual analysis can help understand the underlying mechanisms of the surfactant and provide further guidance for production optimization of shales.
BP plans to spend approximately $1.3 billion to build a massive network of pipes and infrastructure to collect and capture natural gas produced as a byproduct of oil wells in the Permian Basin. The company said the new Grand Slam facility near Orla, Texas, will mark a significant step in its aims to reduce emissions and enhance production while improving the reliability of its Permian operations. BP also will announce its plans to eliminate routine flaring of natural gas in the Permian Basin by 2025, according to its website. Grand Slam, reportedly the largest infrastructure project to date for BP's US onshore business, BPX Energy [formed after BP completed a $10.5-billion acquisition of BHP's American shale assets], and a leading design concept, is an electrified central oil, gas, and water-handling facility that uses a separation and compression system to recover gas that would typically be flared at the wellsite. This allows BP to commercialize the gas instead of flaring it.
Removing carbon dioxide from the air is seen as crucial to reducing the worst impacts of global warming, and the world's largest effort to do that on a commercial scale is coming from an unlikely source: a Texas oil company. Occidental Petroleum's CEO Vicki Hollub said she plans to transform her oil and gas business into a carbon management company and to break ground next year on a direct air capture facility that will suck carbon dioxide out of the atmosphere in the Permian Basin, the country's most prolific oil field. The idea is to help the environment and make money at the same time. Occidental has been capturing carbon dioxide from its oil and gas operations for 40 years, injecting it underground to help recover more oil from its reservoirs. But Hollub's ambitions are bigger. Under her leadership, Hollub has invested an undisclosed amount developing a new direct air capture facility that can remove a million metric tons of carbon dioxide from the atmosphere per year; that's compared to thousands of tons per year that most current direct air capture plants remove.
Breakwater Energy Partners finished construction of its 80-acre produced-water-recycling facility, the Big Spring Recycling System (BSRS), in the Texas Permian Basin between Howard and Martin counties with a throughput capacity of more than 250,000 B/D of recycled produced water.. The BSRS is the largest produced water recycling facility in the Permian Basin serving commercial operators, according to the company, with frac water blends of up to 100% recycled water and access to disposal capacity of more than 100,000 B/D. The facility integrates hundreds of thousands of barrels of produced water into a central point which provides the option to recycle, store, or dispose of water. It has already recycled nearly 5 million bbl of produced water in Q3 with 1.5 million bbl of commercially permitted treated-water-storage capacity, generating almost 10 million data points within its proprietary cloud-based water balancing and data management system. Commercially viable solutions for handling produced water in the Permian has been a challenge for producers well before the economic downturn of 2020.
Shell said this week that in July it inked a deal with Baker Hughes' drone venture company, Avitas, to expand drone-monitoring services at its unconventional assets in the Permian Basin. Shell is one of the fastest adopters of drone platforms which are still considered an emerging technology by much of the oil and gas industry. Last year, the company said it was using them on a daily basis both onshore and offshore. In the Permian, the operator will leverage the drone technology's optical gas-imaging camera and laser-based detection system to bolster its methane-leak detection and repair program. The drones will play a critical role in Shell's goal to limit emissions at its North American operations to below 0.2% of its produced natural gas volumes by 2025.
Pioneer Natural Resources announced this week new greenhouse-gas (GHG) emissions-reduction targets across its Permian Basin operations. The plan, rolled out in the company's new sustainability report, calls for a 25% reduction of GHG emissions by 2030 and a 40% reduction in methane emissions by 2030. The Irving, Texas-based shale producer has also committed to flaring less than 1% of its associated gas and aims to eliminate routine flaring by 2030, and possibly as soon as 2025. By 2022, the new flaring limit will apply to the assets Pioneer is acquiring through its purchase of Parsley Energy. Pioneer announced it was buying the smaller Permian player in a deal valued at $4.5 billion in October.
The recent drop in oil prices has created controversy about the future of most of the E&P and services companies, but how will this affect the oilfield water management market specifically? At the end of 2019, IHS Markit estimated that the oilfield water management market was going to grow 5% in 2020, mainly driven by the increase in activity in the Permian Basin, with WTI prices projected to be between low-50s to mid-40s per barrel. However, a few months after our publication, the industry conditions look completely different and so our view of the oilfield water management market has changed. Following this price collapse, E&P companies quickly began to revise and reduce capital spending for the remainder of 2020. The E&P response indicates that the industry could reach spending around 2016 levels, which means a reduction of drilling and completion (D&C) activity by at least 40% during 2020 when compared to 2019.
Occidental Petroleum's latest endeavor is about as far from traditional oil investments as you can get--a high-tech firm founded by a Harvard University professor, backed by a Silicon Valley billionaire, and housed in a converted warehouse in a Canadian logging town. Oxy signed a deal earlier this year with Carbon Engineering, based in Squamish, British Columbia, to design a plant capable of pulling 500,000 tons of carbon dioxide annually from the atmosphere. It's one of several that Oxy has signed or pursued with high-tech companies that aim to pull CO2 from the air or from industrial emissions. The company is also the first to announce initiatives tied to expanded federal tax credits for carbon storage, including the world's largest planned air capture plant in the Permian Basin. Although that project is tied to an oil field, it's not an obvious play for an oil company.