Employment in America's energy technology and services sector increased by an estimated 8,002 jobs in June, a fourth consecutive month of growth, according to preliminary data from the US Bureau of Labor Statistics (BLS) and analysis by the Energy Workforce & Technology Council. The 1.3% growth comes after the sector added nearly 24,000 positions over the past 3 months after hitting a pandemic low of 591,413 jobs in February, according to BLS data. Gains over the past 4 months bring the sector to a net increase of an estimated 9,043 jobs in 2021. Texas far outpaced other energy-centric states in job growth. The state added an estimated 4,400 jobs over the 30-day period--more that the next 10 states combined, including Louisiana (745), Oklahoma (679), Colorado (362), New Mexico (334), California (327), and Pennsylvania (323)--over the same period.
Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.
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.
James Blaney is an engineer on a hydraulic fracturing fleet for Liberty Oilfield Services, and is based in the Permian Basin. He holds a bachelor's degree in petroleum engineering from the Colorado School of Mines (CSM). While at CSM, he was an active member of the CSM SPE Student Chapter. He volunteered regularly at fundraising events and was a member and captain of the CSM PetroBowl team.
Abstract Conventional resistivity models often overestimate water saturation in organic-rich mudrocks and require extensive calibration efforts. Conventional resistivity-porosity-saturation models assume brine in the formation as the only conductive component contributing to resistivity measurements. Enhanced resistivity models for shaly-sand analysis include clay concentration and clay-bound water as contributors to electrical conductivity. These shaly-sand models, however, consider the existing clay in the rock as dispersed, laminated, or structural, which does not reliably describe the distribution of clay network in organic-rich mudrocks. They also do not incorporate other conductive minerals and organic matter, which can significantly impact the resistivity measurements and lead to uncertainty in water saturation assessment. We recently introduced a method that quantitatively assimilates the type and spatial distribution of all conductive components to improve reserves evaluation in organic-rich mudrocks using electrical resistivity measurements. This paper aims to verify the reliability of the introduced method for the assessment of water/hydrocarbon saturation in the Wolfcamp formation of the Permian Basin. Our recently introduced resistivity model uses pore combination modeling to incorporate conductive (clay, pyrite, kerogen, brine) and non-conductive (grains, hydrocarbon) components in estimating effective resistivity. The inputs to the model are volumetric concentrations of minerals, the conductivity of rock components, and porosity obtained from laboratory measurements or interpretation of well logs. Geometric model parameters are also critical inputs to the model. To simultaneously estimate the geometric model parameters and water saturation, we develop two inversion algorithms (a) to estimate the geometric model parameters as inputs to the new resistivity model and (b) to estimate the water saturation. Rock type, pore structure, and spatial distribution of rock components affect geometric model parameters. Therefore, dividing the formation into reliable petrophysical zones is an essential step in this method. The geometric model parameters are determined for each rock type by minimizing the difference between the measured resistivity and the resistivity, estimated from Pore Combination Modeling. We applied the new rock physics model to two wells drilled in the Permian Basin. The depth interval of interest was located in the Wolfcamp formation. The rock-class-based inversion showed variation in geometric model parameters, which improved the assessment of water saturation. Results demonstrated that the new method improved water saturation estimates by 32.1% and 36.2% compared to Waxman-Smits and Archie's models, respectively, in the Wolfcamp formation. The most considerable improvement was observed in the Middle and Lower Wolfcamp formation, where the average clay concentration was relatively higher than the other zones. Results demonstrated that the proposed method was shown to improve the estimates of hydrocarbon reserves in the Permian Basin by 33%. The hydrocarbon reserves were underestimated by an average of 70000 bbl/acre when water saturation was quantified using Archie's model in the Permian Basin. It should be highlighted that the new method did not require any calibration effort to obtain model parameters for estimating water saturation. This method minimizes the need for extensive calibration efforts for the assessment of hydrocarbon/water saturation in organic-rich mudrocks. By minimizing the need for extensive calibration work, we can reduce the number of core samples acquired. This is the unique contribution of this rock-physics-based workflow.
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.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
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.
Frantz, J. H. (Deep Well Services, Matador Resources Company, Completion Team) | Tourigny, M. L. (Deep Well Services, Matador Resources Company, Completion Team) | Griffith, J. M. (Deep Well Services, Matador Resources Company, Completion Team)
Abstract In conjunction with the industry and basin-wide paradigm shift to drilling and completing extended laterals, Matador Resources Company (the operator) made significant plans in 2018 that would focus activity toward wells with laterals greater than one-mile. One operational hurdle to overcome in this shift change was the effective execution of removing frac plugs and sand at increased depths during a post-stimulation frac plug millout. Utilization of coiled-tubing units (CTUs) had been proven to be a successful millout method in one-mile laterals, but not without risk. Rig-assisted snubbing units coupled with workover rigs (WORs) provided for less risk with higher pulling strength capabilities and the ability to rotate tubing, but would often require operational time of up to twice that of typical coiled-tubing unit millouts. The stand-alone, rigless Hydraulic Completion Unit (HCU) was ultimately tested as a solution and proved to alleviate risks in extended lateral millouts while providing operational time and cost comparable to coiled-tubing units. The operator has since performed post-stimulation frac plug millouts on ~45 horizontal wells in the Delaware Basin using HCUs. The majority of these wells carried lateral lengths of over 1.5 miles. Results and benefits observed by the operator include but are not limited to the list below: 1.) Ability to safely and consistently reach total depth (TD) on extended laterals through increased snubbing/pickup force and the HCU's pipe rotating ability 2.) Ability to pump at higher circulation rates in high-pressured wells (>3,500 psi wellhead pressure) to assist in effective wellbore cleaning 3.) Smaller footprint which allows for the utilization of two units simultaneously on multi-well pads 4.) Time and cost comparable to a standard coiled-tubing millout, particularly on multi-well pads.
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.