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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 Potash minerals are a source of potassium, which is used for the manufacture of gunpowder and fertilizer. Commercial potash mineralization is often discovered when petroleum wells are drilled through evaporite sequences and the Gamma Ray log “goes off scale”. This is because potassium is one of the naturally occurring radioactive elements, emitting gamma rays from the K isotope, in its decay to Ar. However, not all potash minerals may be commercial sources of potassium via underground mechanical or solution mining techniques and Potassium is not the only radioactive element. For example, the mineralogy of the McNutt “Potash” member of the Salado Formation in SE New Mexico, is extremely complex, consisting of multiple thin (i.e., less than 10 ft thick) beds of six low-grade (radioactive) potash minerals, only two of which are commercial. There are also four non-radioactive evaporite minerals, one of which interferes with potash milling chemistry, and numerous claystones and Marker Beds (shales), with GR count rates comparable to the low-grade potash. Because of this complexity, traditional wireline and Logging While Drilling Potash Assay techniques, such as Gamma Ray log-to-core assay transforms, may not be sufficient to identify potentially commercial potash mineralization, for underground mining. Crain and Anderson (1966) and Hill (2019) developed linear programming, and multi-mineral analyses, respectively, to estimate Potash mineralogy and grades. However, both of these approaches require complete sets of multiple log measurements. In SE New Mexico, petroleum wells are drilled through the McNutt “Potash” member of the Salado Formation, with air, cased and drilled out to TD in the underlying sediments, with water based mud. Complete log suites are then run from TD to the casing shoe, with only the GR and neutron logs recorded through the cased evaporite sequence for stratigraphic and structural correlation. As a result, numerous oil and gas wells, in SE New Mexico, have cased hole gamma ray and neutron logs, through the Salado Evaporite. Logs, from these wells could provide a rapid Potash screening database, if used properly. A simple screening cross-plot technique, the Potash Identification (PID) plot, utilizing only Gamma Ray and Neutron Porosity, is proposed and successfully demonstrated, as a potential screening tool. This technique can be used with both open and cased-hole petroleum well logs, as well as core hole wire-line logs, and provides discrimination of commercial potash mineralization from non-commercial (potash and nonpotash) radioactive mineralization. Case histories of the use of PID cross plots in the evaporite basins of Michigan, Nova Scotia, Saskatchewan, and SE New Mexico are described. The technique may also be useful in screening potential potash deposits in China, Europe, North Africa, and South America.
Oilfield equipment that emits smog-causing pollution would be targeted by New Mexico environmental regulators under a proposed rule made public by the state Environment Department. The release of the proposal marks the next step in a process that started nearly 2 years ago as Gov. Michelle Lujan Grisham and other top Democrats in the state announced their intentions to curb emissions across the oil and natural gas sector. The state created a working group made up of industry, environmentalists, and other experts to help in crafting the regulations. The rules proposed by the state Environment Department are part of a two-pronged approach, which Environment Secretary James Kenney touted as the most comprehensive effort in the US to tackle pollution blamed for exacerbating climate change. State oil and gas regulators adopted separate rules earlier this year to limit venting and flaring as a way to reduce methane pollution.
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.
The routine flaring and venting of natural gas in New Mexico is now prohibited and operators in the state will in the coming years be required to capture at least 98% of the gas they produce. These developments are part of a major rule change approved last week by the state's Oil Conservation Commission that will come into full effect at the end of 2026. The adoption of the new measure follows an executive order from New Mexico's Governor Michelle Lujan Grisham to reduce industry emissions and the waste of natural gas resources through flaring. Policymakers have also emphasized the state's need to address climate change as a key driver behind the tighter regulations. Under the rule, upstream operators could face the denial of new drilling permits if the state's gas-capture target is not met.
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.
Officials in New Mexico will no longer grant approvals for the use of fresh groundwater sourced from state lands in oil and gas operations. Announced this week by the New Mexico State Land Office, the order will primarily impact unconventional oil and gas producers that require several millions of gallons to drill and later hydraulically fracture each horizontal well. The State Land Office cited water scarcity as the primary driver behind the policy shift. Oil output in New Mexico has soared over the past 5 years, making it the third largest producer in the US. Most of the state's 3 million B/D come from the Delaware Basin, one-half of the prolific Permian Basin that extends eastward into Texas.
The New Mexico State Land Office announced in December that it will be halting the practice of allowing fresh water to be pumped from state trust land and sold for use in oil and gas development. Land Commissioner Stephanie Garcia Richard detailed the shift in policy in a letter to companies that hold easements that grant access to trust land for pumping fresh water. Under the change, existing easements will not be renewed once they expire and no new easements will be issued. She pointed to the scarcity of fresh water resources in New Mexico, saying the policy is aimed at encouraging the industry to use recycled water or produced water, which is waste water that result from oil and gas operations. The agency cited data reported by companies to FracFocus, a national registry, that indicated nearly 14.5 billion gallons of water were used for overall production in New Mexico in 2019, with recycled or produced water making up only a fraction of the total use.