Permian Basin Research Articles

Geoscience Poster G7: The search for new oil and CO

Poster G7 Residual oil zones (ROZs) could present a new, potentially large and commercially viable oil resource for Australia and provide an avenue for geological storage of carbon dioxide (CO2) through CO2 enhanced oil recovery (CO2-EOR). These reservoirs, which can contain a moderate amount of residual oil and resemble water-flooded oil fields, can be associated with conventional fields (brownfields) or occur with no associated main pay zone (greenfields). Both types of ROZ are currently produced commercially through CO2-EOR in the Permian Basin, USA, and are of growing interest internationally, but our understanding of the occurrence and economic viability of oil production from ROZs in Australia is limited. We are employing geological and petrophysical methods to identify, map and quantify the potential oil resources of ROZs, initially in central Australian basins. Complementing this, we are conducting a series of CO2 core-flooding experiments combined with reservoir modelling to investigate the techno-economic feasibility of producing oil and storing CO2 in these formations. We aim to establish and test a workflow for characterising and evaluating ROZs in Australia. ROZs could prove to be good targets for CO2-EOR+, potentially even producing carbon-neutral or carbon-negative oil by using CO2 from anthropogenic sources, such as from blue hydrogen production. To access the poster click the link on the right. To read the full paper click here

Enhanced monitoring of atmospheric methane from space over the Permian basin with hierarchical Bayesian inference

Methane is a strong greenhouse gas, with a higher radiative forcing per unit mass and shorter atmospheric lifetime than carbon dioxide. The remote sensing of methane in regions of industrial activity is a key step toward the accurate monitoring of emissions that drive climate change. Whilst the TROPOspheric Monitoring Instrument (TROPOMI) on board the Sentinal-5P satellite is capable of providing daily global measurement of methane columns, data are often compromised by cloud cover. Here, we develop a statistical model which uses nitrogen dioxide concentration data from TROPOMI to efficiently predict values of methane columns, expanding the average daily spatial coverage of observations of the Permian basin from 16% to 88% in the year 2019. The addition of predicted methane abundances at locations where direct observations are not available will support inversion methods for estimating methane emission rates at shorter timescales than is currently possible.

Dissolved organic matter within oil and gas associated wastewaters from U.S. unconventional petroleum plays: Comparisons and consequences for disposal and reuse

Wastewater generated during petroleum extraction (produced water) may contain high concentrations of dissolved organics due to their intimate association with organic-rich source rocks, expelled petroleum, and organic additives to fluids used for hydraulic fracturing of unconventional (e.g., shale) reservoirs. Dissolved organic matter (DOM) within produced water represents a challenge for treatment prior to beneficial reuse. High salinities characteristic of produced water, often 10× greater than seawater, coupled to the complex DOM ensemble create analytical obstacles with typical methods. Excitation-emission matrix spectroscopy (EEMS) can rapidly characterize the fluorescent component of DOM with little impact from matrix effects. We applied EEMS to evaluate DOM composition in 18 produced water samples from six North American unconventional petroleum plays. Represented reservoirs include the Eagle Ford Shale (Gulf Coast Basin), Wolfcamp/Cline Shales (Permian Basin), Marcellus Shale and Utica/Point Pleasant (Appalachian Basin), Niobrara Chalk (Denver-Julesburg Basin), and the Bakken Formation (Williston Basin). Results indicate that the relative chromophoric DOM composition in unconventional produced water may distinguish different lithologies, thermal maturity of resource types (e.g., heavy oil vs. dry gas), and fracturing fluid compositions, but is generally insensitive to salinity and DOM concentration. These results are discussed with perspective toward DOM influence on geochemical processes and the potential for targeted organic compound treatment for the reuse of produced water.

Spatiotemporal Analysis of Produced Water Demand for Fit-For-Purpose Reuse—A Permian Basin, New Mexico Case Study

This study created a framework for assessing the spatial and temporal distribution of the supply and demand of four potential produced water (PW) reuse options: agriculture, dust suppression, power generation, and river flow augmentation using Eddy and Lea counties in the southeastern New Mexico Permian Basin as a case study. Improving the PW management in the oil and gas industry is important in areas with limited water resources and increasing restrictions on PW disposal. One option in the PW management portfolio is fit-for-purpose reuse, but a lack of adequate information on PW quality, volumes, and the spatiotemporal distribution of PW supply and demand precludes its reuse. Using the framework, we determined that a 1.1-mile grid cell for data aggregation is a sufficient spatial scale for capturing the granular data needed for PW management decisions. The annual available PW supply for the two counties was estimated to be 45,460,875 m3 (36,870 acre-feet). The annual cumulative estimated demand was 647,656,261 m3 (525,064 acre-feet) for the four potential use cases—far exceeding PW supply. The maps generated using the framework illustrated that much of the supply and demand are spatially dispersed. The spatiotemporal analysis framework provides a generic methodology that can be used for PW management in other basins or for assessing alternative waters at the local and regional scales where management occurs.

Laboratory and pilot-scale studies of membrane distillation for desalination of produced water from Permian Basin

Substantial quantities of produced water generated during the extraction of oil and gas from unconventional reservoirs present significant environmental concern and increase the operating cost for this industry. Membrane Distillation (MD) can serve as a potential solution for beneficial reuse of produced water by generating high-quality permeate and reducing the volume of produced water requiring disposal. This study investigated treatment of produced water from Permian Basin in both laboratory and pilot-scale studies. Laboratory tests revealed the potential to successfully recover 50% of produced water although some increase in permeate conductivity was observed due to the passage of ammonia from the feed side. Initial pilot-scale test with filtration of raw produced water as the only pre-treatment step led to precipitation of SrSO4, NaCl, and Fe in the system once the solubility limits for these salts were exceeded. However, chemical pretreatment that included pH adjustment, aeration, and barite precipitation, allowed successful steady-state operation of the AGMD pilot system for 5 days where the produced water was concentrated from 127 g/L to 255 g/L (~50% water recovery) while recovering high quality permeate. Overall, greater than 99.7 % salt rejection was achieved with the average permeate flux of 1.86 LMH. Mass balance analysis suggested potential Ba and Ca precipitation in the system but there was no impact on AGMD performance and permeate quality during 5 days of continuous operation in the field.

PM2.5 in Carlsbad Caverns National Park: Composition, sources, and visibility impacts

ABSTRACT Carlsbad Caverns National Park in southeastern New Mexico is adjacent to the Permian Basin, one of the most productive oil and gas regions in the country. The 2019 Carlsbad Caverns Air Quality Study (CarCavAQS) was designed to examine the influence of regional sources, including urban emissions, oil and gas development, wildfires, and soil dust on air quality in the park. Field measurements of aerosols, trace gases, and deposition were conducted from 25 July through 5 September 2019. Here, we focus on observations of fine particles and key trace gas precursors to understand the important contributing species and their sources and associated impacts on haze. Key gases measured included aerosol precursors, nitric acid and ammonia, and oil and gas tracer, methane. High-time resolution (6-min) PM2.5 mass ranged up to 31.8 µg m−3, with an average of 7.67 µg m−3. The main inorganic ion contributors were sulfate (avg 1.3 µg m−3), ammonium (0.30 µg m−3), calcium (Ca2+) (0.22 µg m−3), nitrate (0.16 µg m−3), and sodium (0.057 µg m−3). The WSOC concentration averaged 1.2 µg C m−3. Sharp spikes were observed in Ca2+, consistent with local dust generation and transport. Ion balance analysis and abundant nitric acid suggest PM2.5 nitrate often reflected reaction between nitric acid and sea salt, forming sodium nitrate, and between nitric acid and soil dust containing calcium carbonate, forming calcium nitrate. Sulfate and soil dust are the major contributors to modeled light extinction in the 24-hr average daily IMPROVE observations. Higher time resolution data revealed a maximum 1-hr extinction value of 90 Mm−1 (excluding coarse aerosol) and included periods of significant light extinction from BC as well as sulfate and soil dust. Residence time analysis indicated enrichment of sulfate, BC, and methane during periods of transport from the southeast, the direction of greatest abundance of oil and gas development. Implications: Rapid development of U.S. oil and gas resources raises concerns about potential impacts on air quality in National Parks. Measurements in Carlsbad Caverns National Park provide new insight into impacts of unconventional oil and gas development and other sources on visual air quality in the park. Major contributors to visibility impairment include sulfate, soil dust (often reacted with nitric acid), and black carbon. The worst periods of visibility and highest concentrations of many aerosol components were observed during transport from the southeast, a region of dense Permian Basin oil and gas development.

Federalism and the politics of oil and gas pipelines in Canada (Alberta) and the United States (Texas)

AbstractIn recent years, pipeline policy has been a significant and controversial issue in Canadian politics. In the United States, pipeline projects to increase transportation capacity for Texas oil have also been high on the energy agenda, but they have not permeated national politics like in Canada. In fact, new pipelines to transport oil and gas out of Texas' Permian Basin have multiplied without generating serious national controversy or intergovernmental conflicts. This article develops an explanation for these distinct political outcomes in Canada and the United States. The article identifies three factors that have contributed to pipeline projects triggering serious intergovernmental conflicts in Canada around Alberta oil but not in the United States in relation to the transportation of Texas oil: (1) pipeline structures and the regulatory framework for oil and gas; (2) the ideological and political support for, or opposition to, oil and gas development; and (3) the level of Indigenous opposition to pipeline projects.Related ArticlesAsh, John S. 2011. “Radiation or Riots: Risk Perception in Nuclear Power Decision Making and Deliberative Approaches to Resolving Stakeholder Conflict.” Politics & Policy 39(2): 317–44. https://doi.org/10.1111/j.1747‐1346.2010.00237.x.Mahafza, Zachary, Jonathan M. Fisk, and David P. Adams. 2021. “Crude Contempt: Examining Local Pushback to Oil and Gas Development in California.” Politics & Policy 49(2): 479–501. https://doi.org/10.1111/polp.12401.Neill, Katharine A., and John C. Morris. 2012. “A Tangled Web of Principals and Agents: Examining the Deepwater Horizon Oil Spill through a Principal‐Agent Lens.” Politics & Policy 40(4): 629–56. https://doi.org/10.1111/j.1747‐1346.2012.00371.x.

Zircon U-Pb-Hf Isotopes, Biotite 40Ar/39Ar Geochronology, and Whole-Rock Geochemistry of the Baogeqi Gabbro in the Northern Alxa, Southernmost Central Asian Orogenic Belt

The final closure time of the Paleo-Asian Ocean and the Permo-Carboniferous tectonic settings in the northern Alxa are very important but controversial tectonic issues. The geochronology and petrogenesis of mafic igneous rocks are superior in clarifying regional tectonic settings. Here, we report on zircon U-Pb-Hf isotopes, biotite 40Ar/39Ar geochronology and whole-rock geochemical data of the hornblende gabbro from the Baogeqi gabbro pluton in the northern Alxa. The LA-ICP MS U-Pb analysis of zircon grains from the hornblende gabbro yield a weighted mean age of 262.7 ± 2.3 Ma (2σ, MSWD = 0.74), manifesting that the Baogeqi gabbro pluton emplacement was during the late Middle Permian (Capitanian). The 40Ar/39Ar dating of biotite grains from the hornblende gabbro yields a plateau age of 231.3 ± 1.6 Ma (2σ, MSWD = 0.55), indicating that the Baogeqi gabbro pluton cooled to below 300 ℃ in the Triassic. The hornblende gabbro samples are calc-alkaline with metaluminous character, and show enrichment in large ion lithophile elements (e.g., Rb, Ba, Sr, and K) but depletion in Nb, Ta, P, Th, and Ti relative to primitive mantle. Combined with the positive zircon εHf(t) values (+4.9–+9.4), we suggest that the magmas formed from the partial melting of depleted mantle were metasomatized by slab-derived fluids. Together with regional geology, these geochemical data suggest that the Baogeqi gabbro pluton was formed in an intracontinental extension setting, further indicating that the Paleo-Asian Ocean in the northern Alxa was closed prior to the late Middle Permian (Capitanian), and this region was in a post-collision extensional setting during the Capitanian-Late Permian. In addition, the Triassic cooling of the gabbro pluton may be a record of the decline of the Capitanian-Late Permian post-collisional extension basin due to the far-field effect of subduction-collision during the closure of the Paleo-Tethys Ocean.

Methane, carbon dioxide, hydrogen sulfide, and isotopic ratios of methane observations from the Permian Basin tower network

Abstract. We describe the instrumentation, calibration, and uncertainty of the network of ground-based, in situ, cavity ring down spectroscopy (CRDS) greenhouse gas (GHG) measurements deployed in the Permian Basin. The primary goal of the network is to be used in conjunction with atmospheric transport modeling to determine methane emissions of the Delaware sub-basin of the Permian Basin oil and natural gas extraction area in Texas and New Mexico. Four of the measurements are based on tall communications towers, while one is on a building on a mountain ridge, with the recent addition of a small tower at that site. Although methane (CH4) is the primary species of interest, carbon dioxide (CO2), hydrogen sulfide (H2S), and the isotopic ratio of methane (δ13CH4) are also reported for a subset of the sites. Measurements were reported following the WMO X2004A scale for CH4 and the WMO X2019 scale for CO2. CRDS instruments were calibrated for CH4 and CO2 in the laboratory prior to deployment. For H2S, data were offset-corrected using the minimum 40 min running mean value of the day, and for δ13CH4, calibrations were based on laboratory data. We describe the characteristics of the dataset with a set of illustrative analyses. Methane and carbon dioxide showed strong seasonality, with a well-defined diurnal cycle during the summer, which was opposed to the winter, when a diurnal cycle was absent. CH4 enhancements to the background, during the winter, are up to twice the summer values, which is attributed to the changes in boundary layer depth and wind speed. The largest CH4 enhancements occurred when winds blow from the center of the Delaware sub-basin, where most of the methane emissions come from. The magnitude of enhancements of CO2 did not present seasonality. H2S enhancements indicated a potential source northeast of the tower (Hobbs, New Mexico) where the inlet is installed. Isotopic ratios of methane indicated that oil and natural gas extraction is the source of local methane in the region. The hourly-averaged data, starting on 1 March 2020 and described in this paper, are archived at The Pennsylvania State University Data Commons at https://doi.org/10.26208/98y5-t941 (Monteiro et al., 2021).

The search for new oil and CO

Residual oil zones (ROZs) could present a new, potentially large and commercially viable oil resource for Australia and provide an avenue for geological storage of carbon dioxide (CO2) through CO2 enhanced oil recovery (CO2-EOR). These reservoirs, which can contain a moderate amount of residual oil and resemble water-flooded oil fields, can be associated with conventional fields (brownfields) or occur with no associated main pay zone (greenfields). Both types of ROZ are currently produced commercially through CO2-EOR in the Permian Basin, USA, and are of growing interest internationally, but our understanding of the occurrence and economic viability of oil production from ROZs in Australia is limited. We are employing geological and petrophysical methods to identify, map and quantify the potential oil resources of ROZs, initially in central Australian basins. Complementing this, we are conducting a series of CO2 core-flooding experiments combined with reservoir modelling to investigate the techno-economic feasibility of producing oil and storing CO2 in these formations. We aim to establish and test a workflow for characterising and evaluating ROZs in Australia. ROZs could prove to be good targets for CO2-EOR+, potentially even producing carbon-neutral or carbon-negative oil by using CO2 from anthropogenic sources, such as from blue hydrogen production.

Identification of fossil contourite drifts in the Delaware Basin, U.S.A.

ABSTRACT Carbonate contourite drifts formed by bottom currents are common on modern sea floors but are rarely defined in the rock record. Regional subsurface well-log mapping in the northern Delaware Basin in southeast New Mexico, USA, reveals early Permian carbonate-dominated elongate, mounded accumulations along the slope of the western margin of the basin. Thickness maps also show possible moats oriented oblique to depositional dip. The thickness variations and moat geometries are hard to explain by deposition from gravity flows but are consistent with deposition from bottom currents with a counterclockwise deflection in the basin. The contourite drift system consists of three large elongate carbonate drifts that form in relation to significant bathymetric irregularities which may alter currents, resulting in localized drift accumulations along the slopes. These findings highlight the significant role bottom currents play in shaping carbonate margin and slope architecture, rivaling the impact of gravity flows. Furthermore, full-scale assessment of the basin geometry and deposits provide insight into paleo-oceanographic circulation that is inherently difficult to assess. Identification of these large sedimentary bodies requires extensive basin-wide data sets, which were acquired by decades of work in the Permian Basin, as well as comparison with drifts in modern carbonate settings. These new interpretations in one of the most data-rich geologic regions in the world indicate that drift systems may be easily overlooked and are likely more common in the ancient rock record than currently recognized.

Comments: Costs of Technology to Reduce Emissions

Seven years, and we’re on track to exceed the 1.5°C target established by the Paris Agreement in 2015 to limit global warming by 2030. Instead, we may be turning up the heat to 3.0°C, according to a report released last month by the United Nations Intergovernmental Panel on Climate Change (IPCC). And in this case, doubling the wager does not hold potential for greater rewards. It’s clear that current climate policies will not accomplish the mitigation of emissions needed to achieve the target. Equally clear is the challenge for policymakers to decide how much to spend on measures to reduce greenhouse gases (GHG) and for people to understand the costs and reasons for the outlay from governments (the people’s money) or higher prices for products and services (again, the people’s money). To make informed and as-realistic-as-possible decisions, all stakeholders need to be able to compare and understand the costs of various options. Those costs are not easily calculated. Mitigative measures are nascent when viewed in the context of “how things have always been done.” In this third IPCC report released since August 2021, the focus was on the technologies to mitigate emissions. Science-based measurements of the types and amounts of emissions and their validly measured reductions are critical to making the most beneficial and cost-effective decisions about the technologies to be implemented. The IPCC tackled the task of quantifying various technologies’ effectiveness as estimated in GtCO2-eq yr–1 by 2030, their likelihood of doing so this decade, and the economics of their deployment. The chart shows the current accounting. Note the lines indicating the “uncertainty range” for each option. Blue shading represents cost competitiveness today; light orange to dark red means investment is needed. Mitigation options costing $100 GtCO2-eq–1 or less are estimated to potentially reduce global GHG emissions by at least half the 2019 level by 2030. Options costing less than $20 GtCO2-eq–1 are estimated to make up more than half of this potential. Large contributions that cost less than $20 come from solar and wind energy, energy efficiency improvements, reduced conversion of natural ecosystems, and CH4 emissions reductions (coal mining, oil and gas, waste). Carbon capture and storage, not surprisingly, needs investment today and in the longer term. Its potential by 2030 is small and it is expensive. For example, Oxy updated investors on 23 March on its plans to invest up to $1 billion in its direct-air-capture facility, expected to remove up to 1 mtpa of CO2 annually from its location in the Permian Basin to be sequestered in enhanced-oil-recovery reservoirs. Larry W. Lake presents a pragmatic view of using what has been learned in CO2-EOR to upscale CCS in this month’s Guest Editorial. The report dedicates a chapter to innovation, technology development, and transfer. Slowdowns result from an inadequate supply of trained scientists and engineers and the willingness of consumers to accept new technology. Another barrier referenced in the report is the concept of the “four valleys of death” for climate-tech entrepreneurs. The complete report can be found here and warrants at least a skim of the executive summaries of the chapters of interest to you.

Pressure Measurements for Monitoring CO2 Foam Pilots

This study focuses on the use of pressure measurements to monitor the effectiveness of foam as a CO2 mobility control agent in oil-producing reservoirs. When it is applied optimally, foam has excellent potential to improve reservoir sweep efficiency, as well as CO2 utilization and storage, during CO2 Enhanced Oil Recovery (EOR) processes. In this study, we present part of an integrated and novel workflow involving laboratory measurements, reservoir modeling and monitoring. Using the recorded bottom-hole pressure data from a CO2 foam pilot study, we demonstrate how transient pressures could be used to monitor CO2 foam development inside the reservoir. Results from a recent CO2 foam pilot study in a heterogeneous carbonate field in Permian Basin, USA, are presented. The injection pressure was used to evaluate the development of foam during various foam injection cycles. A high-resolution radial simulator was utilized to study the effect of foam on well injectivity, as well as on CO2 mobility in the reservoir during the surfactant-alternating gas (SAG) process. Transient analysis indicated constant temperature behavior during all SAG cycles. On the other hand, differential pressures consistently increased during the surfactant injection and decreased during the subsequent CO2 injection periods. Pressure buildup during the periods of surfactant injection indicated the development of a reduced mobility zone in the reservoir. The radial model proved to be useful to assess the reservoir foam strength during this pilot study. Transient analysis revealed that the differential pressures during the SAG cycles were higher than the pressures observed during the water-alternating gas (WAG) cycle which, in turn, showed foam generation and reduced CO2 mobility in the reservoir. Although pressure data are a powerful indicator of foam strength, additional measurements may be required to describe the complex physics of in situ foam generation. In this pilot study, it appeared that the reservoir foam strength was weaker than that expected in the laboratory.

Methane emissions from US low production oil and natural gas well sites

Eighty percent of US oil and natural gas (O&G) production sites are low production well sites, with average site-level production ≤15 barrels of oil equivalent per day and producing only 6% of the nation’s O&G output in 2019. Here, we integrate national site-level O&G production data and previously reported site-level CH4 measurement data (n = 240) and find that low production well sites are a disproportionately large source of US O&G well site CH4 emissions, emitting more than 4 (95% confidence interval: 3—6) teragrams, 50% more than the total CH4 emissions from the Permian Basin, one of the world’s largest O&G producing regions. We estimate low production well sites represent roughly half (37—75%) of all O&G well site CH4 emissions, and a production-normalized CH4 loss rate of more than 10%—a factor of 6—12 times higher than the mean CH4 loss rate of 1.5% for all O&G well sites in the US. Our work suggests that achieving significant reductions in O&G CH4 emissions will require mitigation of emissions from low production well sites.

Shale Gas Decarbonization in the Permian Basin: Is It Possible?

The United States is unique in the energy reserves held in shale gas fields, which coproduce natural gas and natural gas liquids. Use of this resource, however, contributes to greenhouse gas emissions and, correspondingly, climate change. We explore how natural gas and natural gas liquids might build bridges toward low-carbon transportation fuels. For example, as petroleum refineries produce less gasoline in response to widespread electrification, natural gas liquids can be converted to fuel. We consider whether the greenhouse gas emissions from production and use of these fuels might be offset through three potential outcomes of converting coproduced natural gas to CO2 through steam methane reforming. First, the CO2 could be injected into conventional oil formations for enhanced oil recovery. Second, it could be sequestered into saline aquifers to avoid CO2 emissions from the produced oil combustion. Third, it could be injected into unconventional gas formations in the form of CO2-based fracturing fluids. Simultaneously, the coproduced hydrogen from steam methane reforming could be used to support the expansion of the hydrogen economy. The region of study is the Permian Basin. The results show sizeable emission benefits by decreasing net emissions of natural gas production and use to 28 from 88 g-CO2e/MJ. For revenue generating pathways, a partial decarbonization of 3.4 TCF/year is possible. All of the natural gas can be partially decarbonized if the CO2 is sequestered in saline aquifers. Overall, the results show that while greenhouse gas emissions can be reduced through decarbonization approaches relying on subsurface sequestration, full natural gas decarbonization is not achieved but must be pursued through other approaches.

Source rock evaluation and fluid inclusion reconnaissance study of Carboniferous and Zechstein rocks in the northern margin of the Southern Permian Basin, onshore Denmark

Hydrocarbon exploration onshore Denmark has been unsuccessful with no commercial discoveries. Several potential plays have been identified of which the Zechstein carbonate play relying on organic-rich Zechstein (Z2) carbonates as source rock is considered the most promising. Additional source rocks might be lower Carboniferous calcareous and carbonaceous units. This study aims at documenting Palaeozoic source rock(s) in the Upper Mississippian/Lower Pennsylvanian and Zechstein Z2 cored sections in wells drilled in the northern margin of the Southern Permian Basin in the Danish Baltic Sea area. The source rock potential, organic matter composition, and thermal maturity was examined using Rock-Eval pyrolysis, vitrinite reflectance measurements, and organic petrography of cuttings and core samples from two wells. In addition, a fluid inclusion reconnaissance study was conducted on samples from four wells. The examined Upper Mississippian/Lower Pennsylvanian marine calcareous mudstones are thermally immature to marginally mature with a generally low TOC content consisting of minor amounts of dispersed vitrinite and inertinite and scattered yellowish fluorescing mainly terrigenous liptinite macerals. The source rock potential is nil to poor. The analysed Zechstein Z2 section is also thermally immature and consists of resedimented carbonate mudstones deposited in a marine environment on a slope. The mudstones are organic-lean with identifiable tiny vitrinite particles and some telalginite. The source rock quality is poor with a potential for some gas generation. Thus, identification of rich source rocks failed, but the occurrence of solid bitumen in the Zechstein Z2 suggests the presence of restricted source rock levels in the mudstones or migration from deeper richer source rock sections. Further, hydrocarbon fluid inclusions are direct evidence for petroleum generation and migration. The dark appearance, high vapour/liquid ratio at room temperature and their homogenisation behaviour clearly indicate a mixed hydrocarbon composition with methane and higher hydrocarbons, like gas condensate. This demonstrates the presence of a working petroleum system in the northern margin of the Southern Permian Basin in southern Denmark.

Mechanisms for the Generation of Complex Fracture Networks: Observations From Slant Core, Analog Models, and Outcrop

We use observations of hydraulic fractures in core, outcrop attributes of natural hydraulic fractures, and analogue models, to address how hydraulic fracture networks evolve. A slant core from the Wolfcamp Formation—an unconventional shale hydrocarbon reservoir in the Permian Basin of West Texas—collected within 18 m and 30 m of two hydraulically stimulated horizontal wells, provided an opportunity to examine hydraulic fractures directly. In approximately 183 m of core, 309 calcite-sealed natural opening-mode fractures and 375 hydraulic fractures were identified. Many hydraulic fractures in the core show complex morphology, including twist-hackle segmentation, diversion, and bifurcation; these structures most commonly develop at lithological bed boundaries and mechanical heterogeneities such as natural fractures and concretions. An outcrop of bed-parallel pavements in the Cretaceous Boquillas Formation in West Texas contains opening-mode fractures that likely formed by natural hydraulic fracturing. Fracture traces provide evidence of twist-hackle segmentation, and are typically associated with bed boundaries and preexisting bed-parallel stylolites. A laboratory study of hydraulic fracturing of 33 synthetic blocks of gypsum and hydrostone revealed fracture steps, diversions, twist hackles, and multiple overlapping fractures together with information on fracture growth directions. These complexities in the fracture network were dominantly nucleated at inclusions used to simulate pre-existing fractures, and as a result of mechanical heterogeneity introduced by the wellbore and perforations. Collectively, our results show that complex fracture networks are produced in hydraulic fracturing of self-sourced reservoir strata. Mechanical stratigraphic boundaries and other heterogeneities are likely to enhance fracture network complexity through the processes of segmentation, diversion, and bifurcation. These processes create multiple fracture strands, resulting in an increased number of hydraulic fractures over those initiated, thereby increasing total fracture surface area. Our study provides insight into hydraulic fracture network propagation, and has applications for evaluation, completion, production, and fracture modeling of unconventional reservoirs.

Novel Proppant Logging Technique for Infill Drilling of Unconventional Shale Wells

Summary During the development of an unconventional play, wells are drilled and completed in batches, and depending on the development plans, current and expected energy market trends, as well as other developmental considerations, new wells are drilled and hydraulically fractured later near existing producing laterals. This creates challenges in terms of optimizing resource recovery and reducing interwell communication. A novel approach is proposed that utilizes systematic composite sampling and analysis of drilling mud returns to look for and quantitatively identify sand particles. The workflow involves cleaning, drying, and segregation of samples into sizes of interest to us (size distribution of pumped proppant in offset parent wells). These samples are imaged at a very high resolution and analyzed for grains using characteristic optical imaging properties to classify proppant sand particles using computer vision algorithms. Further analysis, such as elemental compositional analysis, is used to validate the results from the imaging workflow. We present a case study from the Permian Basin, where a new child well was used as a test case to prove this technology at the Hydraulic Fracturing Test Site (HFTS-2) in Delaware Basin. We introduce new proppant parameters that help identify sustained proppant zones vs. localized propped fractures. We have used additional diagnostics and data collected at the test site to validate observations from the proppant log and have successfully interpreted significantly propped vs. unpropped zones. A key finding from this test has been the significant proppant transport distances observed away from parent wells. Observable proppant was found at a lateral distance of approximately 425 m for one set of parent wells and more than 915 m for another set of parent wells. While a major limitation of this technique is the sampling rate, given adequate sampling, the proposed technology represents a systematic and one-of-a-kind interpretation of spatial proppant distribution while drilling infill wells. It provides us with unique opportunities to better understand the current state of the reservoir being targeted, including zones that are likely highly drained relative to others, and how the planned hydraulic fracturing of child wells can be improved.

A Numerical Simulation Approach for Shale Fracture Network Characterization Using Hybrid EDFM Method

Abstract Efficient and economical production in shale reservoirs requires specific knowledge and techniques to characterize the fracture network, which consists of both the large hydraulic fractures and the natural fractures. Current research mainly focuses on the hydraulic fracture part, while research on characterizing the natural fractures is relatively rare due to the complexity and uncertainties of the natural fracture distribution in reservoirs. This paper proposed a numerical method for characterizing this complex fracture network in shale reservoirs which handles both the hydraulic fracture and the natural fractures at full dimensions using a combination of microseismic data, geostatistical information, fracking plan, and reservoir simulation. We use microseismic clouds to generate mappings of hydraulic fractures and choose the most appropriate set using the fracking schedule and flowback simulation. The natural fractures are treated using a fractal probabilistic model calibrated with geostatistical information including fracture length, density, and intensity. Both the hydraulic and fractal natural fractures mentioned above are then modeled using embedded discrete fracture model (EDFM) and are coupled to create the hybrid fracture network and applied with reservoir simulation grids. Numerical simulation is performed to investigate further into the fracture network, and history matching is applied to reduce the uncertainty by select the most appropriate fracture network from multiple realizations. Sensitivity analysis is also performed to analyze the controlled natural fracture parameters on total production. We further used our approach to study a horizontal well performance in the Permian Basin and compared our simulation results with traditional fracture characterization and model methods. Our established work has shown the best agreement with history production data compared with randomized fracture model and the multimedium method. This provides a novel method to characterize fracture networks in shale and may be used to guide production optimizations and plan management.

Simulated Methane Emission Detection Capabilities of Continuous Monitoring Networks in an Oil and Gas Production Region

Simulations of the atmospheric dispersion of methane emissions were created for a region containing 26 oil and gas production sites in the Permian Basin in Texas. Virtual methane sensors were placed at 24 of the 26 sites, with at most 1 sensor per site. Continuous and intermittent emissions from each of the 26 oil and gas production sites, over 4 week-long meteorological episodes, representative of winter, spring, summer, and fall meteorology, were simulated. The trade-offs between numbers of sensors and precision of sensors required to reliably detect methane emissions of 1 to 10 kg/h were characterized. A total of 15 sensors, able to detect concentration enhancements of 1 ppm, were capable of identifying emissions at all 26 sites in all 4 week-long meteorological episodes, if emissions were continuous at a rate of 10 kg/h. More sensors or sensors with lower detection thresholds were required if emissions were intermittent or if emission rates were lower. The sensitivity of the required number of sensors to site densities in the region, emission dispersion calculation approaches, meteorological conditions, intermittency of the emissions, and emission rates, were examined. The results consistently indicated that, for the conditions in the Permian Basin, a fixed monitoring network with approximately one continuous monitor per site is likely to be capable of consistently detecting site-level methane emissions in the range of 5–10 kg/h.