Permian Basin Research Articles

New approaches to distinguish shale-sourced and coal-sourced gases in petroleum systems

Current approaches relating thermogenic gases to either shale source rocks (predominantly type II kerogen) or coal source rocks (predominantly type III kerogen) are not reliable and not globally applicable. This is because these mostly empirical approaches were developed using small poorly-constrained datasets from limited locations. The evaluation of a large global dataset of molecular and isotopic properties of gases from unconventional shale and coal reservoirs suggests that two genetic diagrams based on stable carbon isotopes of methane and ethane, δ13C-C2H6versus δ13C-CH4 and δ13C-CH4versus Δ(δ13C-C2H6 – δ13C-CH4), provide the best separation of shale-sourced and coal-sourced gases. Newly designated genetic fields and shale/coal separation lines on these diagrams were tested and validated using data from five petroleum systems with, likely, only shale (class B and A organofacies) source rocks (the Maracaibo Basin in Venezuela, the Guajira Basin in Colombia and the Rub Al Khali Basin in Iran) and only coal (class F organofacies) source rocks (the Southern Permian Basin in Germany and the Sichuan Basin in China). The practical usefulness of this new approach to gas-source correlations was demonstrated in two case studies from petroleum systems with debated source rock organofacies (the Mozambique Basin in Mozambique and the Indus Basin in Pakistan). These better constrained and more reliable diagrams with genetic fields and shale/coal separation lines represent a new tool for the evaluation of petroleum systems.

Satellite-based survey of extreme methane emissions in the Permian basin.

Industrial emissions play a major role in the global methane budget. The Permian basin is thought to be responsible for almost half of the methane emissions from all U.S. oil- and gas-producing regions, but little is known about individual contributors, a prerequisite for mitigation. We use a new class of satellite measurements acquired during several days in 2019 and 2020 to perform the first regional-scale and high-resolution survey of methane sources in the Permian. We find an unexpectedly large number of extreme point sources (37 plumes with emission rates >500 kg hour-1), which account for a range between 31 and 53% of the estimated emissions in the sampled area. Our analysis reveals that new facilities are major emitters in the area, often due to inefficient flaring operations (20% of detections). These results put current practices into question and are relevant to guide emission reduction efforts.

Progradational slope architecture and sediment distribution in outcrops of the mixed carbonate-siliciclastic Bone Spring Formation, Permian Basin, west Texas

AbstractSediment transport and distribution are the keys to understanding slope-building processes in mixed carbonate-siliciclastic sediment routing systems. The Permian Bone Spring Formation, Delaware Basin, west Texas, is such a mixed system and has been extensively studied in its distal (basinal) extent but is poorly constrained in its proximal upper-slope segment. Here, we define the stratigraphic architecture of proximal outcrops in Guadalupe Mountains National Park in order to delineate the shelf-slope dynamics of carbonate and siliciclastic sediment distribution and delivery to the basin. Upper-slope deposits are predominantly fine-grained carbonate lithologies, interbedded at various scales with terrigenous (i.e., siliciclastic and clay) hemipelagic and gravity-flow deposits. We identify ten slope-building clinothems varying from terrigenous-rich to carbonate-rich and truncated by slope detachment surfaces that record large-scale mass wasting of the shelf margin. X-ray fluorescence (XRF) data indicate that slope detachment surfaces contain elevated proportions of terrigenous sediment, suggesting that failure is triggered by changes in accommodation or sediment supply at the shelf margin. A well-exposed terrigenous-rich clinothem, identified here as the 1st Bone Spring Sand, provides evidence that carbonate and terrigenous sediments were deposited contemporaneously, suggesting that both autogenic and allogenic processes influenced sediment accumulation. The mixing of lithologies at multiple scales and the prevalence of mass wasting acted as primary controls on the stacking patterns of terrigenous and carbonate lithologies of the Bone Spring Formation, not only on the shelf margin and upper slope, but also in the distal, basinal deposits of the Delaware Basin.

Intermittency of Large Methane Emitters in the Permian Basin

The Permian Basin is the largest and fastest growing oil and gas (O&G) producing region in the United States. We conducted an extensive airborne campaign across the majority of the Permian in September–November, 2019 with imaging spectrometers to quantify strong methane (CH4) point source emissions at facility-scales, including high frequency sampling to evaluate intermittency. We identified 1100 unique and heavy-tailed distributed sources that were sampled at least 3 times (average 8 times), showing 26% average persistence. Sources that were routinely persistent (50–100%) make up only 11% of high emitting infrastructure but 29% of quantified emissions from this population, potentially indicative of leaking equipment that merits repair. Sector attribution of plumes shows that 50% of detected emissions result from O&G production, 38% from gathering and boosting, and 12% from processing. This suggests a 20% relative shift from upstream to midstream compared to other US O&G basins for large emitters. Simultaneous spectroscopic identification of flares found that 12% of detected Permian CH4 plume emissions were associated with either active or inactive flares. Frequent, high-resolution monitoring is necessary to accurately understand intermittent methane superemitters across large, heterogeneous O&G basins and efficiently pinpoint persistent leaks for mitigation.

The Proliferation of Induced Seismicity in the Permian Basin, Texas

AbstractThe Permian Basin has a long history of induced earthquakes, but the seismicity rates have increased dramatically over the past two decades and included a MW 5.0 likely induced by wastewater disposal (WD) in March 2020. A detailed characterization of the proliferation of seismicity in the Permian Basin throughout this time period is needed for improving the scientific understanding of the mechanisms responsible and for mitigating future seismic hazard. Due to a sparse regional seismic network before the advent of Texas Seismological Network in 2017, we characterize seismicity using the 10‐station TXAR array that is 100s of km away from most of the seismicity, with the objective of improving upon the substantial contributions from previous work. By exploiting the nature of waveform similarity, we detect events with template matching, performing a quantitative analysis of spatially varying detection capabilities throughout the study area. From an initial catalog of 10,753 events, we identify 45,009 earthquakes and 10,208 quarry blasts. Using our catalog of earthquakes, we improve epicentral locations, compare relative magnitude techniques, and associate earthquakes to WD or hydraulic stimulations. We further use our earthquake catalog to investigate the relationship between seismicity and human activities near the city of Pecos, Texas. Through a comparison of our earthquake catalog with industrial records, we determine that the vast majority seismicity near Pecos, Texas, since 2000 is likely induced by an increase of WD at wells injecting at depths greater than 1.5 km.

West Texas (Permian) Super Basin, United States: Tectonics, structural development, sedimentation, petroleum systems, and hydrocarbon reserves

The West Texas (Permian) Super Basin is the prototype super basin. The basin has produced 28.9 billion bbl of oil and 203 TCF of gas (63 billion BOE, 1920–2019). The US Geological Survey and Bureau of Economic Geology estimate this super basin has remaining reserves of 120–137 billion BOE, twice the volume produced during the first 100 yr of hydrocarbon production. During the past decade, the West Texas Super Basin has been the driver of production growth in the United States and has decades of remaining economic production and reserve growth. The West Texas Super Basin is a complex Paleozoic basin built on a varied Proterozoic crust. After Cambrian rifting, regional subsidence began in the Middle Ordovician and continued into the Devonian, forming the Tobosa Basin. The early Paleozoic Tobosa Basin subsidence terminated during Mississippian epeirogenic uplift. A later stage of subsidence began in the Late Mississippian accompanied by large-scale faulting and moderate folding. This tectonic and structural development was controlled by basement terrains, earlier tectonic, and structure reactivated by compression of the Ancestral Rocky Mountains and Marathon-Ouachita orogenic events. These formed the Permian Basin. The Marathon-Ouachita tectonic event ended in the Wolfcampian (early Permian). Subsidence continued to the end of the Permian (Ochoan). Periodic subsidence during the Mesozoic was likely caused by Rocky Mountain (Laramide) deformation. Cenozoic (late Paleogene–Neogene) western uplift tilted the basin to the east. Each of these events has a significant influence on the basin petroleum systems. The basin has multiple source rocks and petroleum systems formed during various stages of basin development. During the formation of the early Paleozoic Tobosa Basin, Simpson Group and Woodford Shale source rocks were deposited. During the transitional basin development phase, the Barnett Shale source rocks were deposited, and during Permian Basin subsidence, the Wolfcamp and middle Permian (Leonardian and Guadalupian) source rocks were deposited. Continued subsidence into the Mesozoic resulted in the deposition of additional strata. These Mesozoic intervals are now mostly eroded but provided sufficient burial depths for thermal development and increased the extent of thermal effect for maturation and migration of hydrocarbons within these Paleozoic petroleum systems. Leonardian and Guadalupian conventional reservoirs have produced 71% of the resources from all conventional West Texas Super Basin reservoirs. These reservoirs are typically most abundant on the shelf crest (shelf to edge), where reservoir development is maximized and becomes a focus of hydrocarbon migration from the deeper Delaware and Midland Basins source rocks and shallower, more-proximal shelf and platform source rock systems. Unconventional resource reservoir oil production in the West Texas Super Basin accounted for just under 90% of total basin daily production at the close of the last decade (2010–2019). Total West Texas Super Basin production peaked in March 2020 at 4.7 million BOPD. Since that time, production has declined because of lower rates of investment driven by lower product prices. The West Texas Super Basin economic oil and gas production has benefited from an extensive infrastructure, a large geologic and engineering community, regulatory and public support, open access, sufficient capital availability, and a scalable service industry. The paradigm toward new drilling, completion, and production technology has been driven by unconventional resource reservoir development in the basin. These West Texas Super Basin technological developments have lead industry technology for unconventional resource development worldwide. Maintaining talented human resources and capital are challenges that time will tell if individual firms and the industry will meet to develop the hydrocarbon resources within the basin.

Pilot-Scale Evaluation of Natural-Gas-Based Foam at High Pressures, Temperatures

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201611, “A Pilot-Scale Evaluation of Natural-Gas-Based Foam at Elevated Pressure and Temperature Conditions,” by Griffin Beck, Swanand Bhagwat, and Carolyn Day, Southwest Research Institute, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. The complete paper presents recent results from a rigorous pilot-scale demonstration of natural-gas (NG) foam over a range of operating scenarios relevant to surface and bottomhole conditions with a variety of base-fluid mixtures. The NG foams explored in these investigations exhibited typical shear-thinning behavior observed in rheological studies of nitrogen- (N2) and carbon-dioxide- (CO2) based foams. The measured viscosity and observed stability indicate that NG foams are well-suited for fracturing applications. Test Facilities Two test facilities were used to explore properties of NG foams at a variety of relevant operating conditions to determine whether NG foam is a suitable alternative to typical water-based fracturing fluids. Pilot-Scale Foam-Test Facility. The pilot-scale foam-test facility (PFTF) is a single-pass pilot plant used to generate and characterize foams at conditions relevant to surface and reservoir conditions. The facility is capable of generating aqueous and oil-based foams using a variety of gases for the internal phase [e.g., methane (CH4), N2, and CO2]. Foams can be characterized at pressures up to 7,500 psi and temperatures up to 300°F. A key benefit of the PFTF is that it can be used to demonstrate new or challenging foaming processes before large-scale or field demonstrations. Further, these processes can be evaluated at conditions relevant to the final application. The test facility consists of three subsystems: a base-fluid system to pressurize and heat the liquid/viscosifier/surfactant mixture, a gas system to pressurize and heat the liquefied gas stream, and the foam test sections to measure various fluid properties of the NG foam. Laboratory Foam-Test Facility. Tests performed on the PFTF were limited to foams generated with pure CH4 and tap water. Additional laboratory tests were conducted to investigate the effects of multiconstituent natural gas mixtures and produced water on foam stability. For these tests, the aqueous base fluid for the foam half-life and foam rheology experiments was prepared from either de-ionized water, tap water, or a synthetic produced water based on a water sample from the Permian Basin. Foam fracturing fluids also typically contain a gelling agent and a foaming agent. The gel was prepared by slow addition of guar to a stirred water sample followed by 30 minutes of mixing to ensure complete hydration. The foaming agent was added and stirred in gently. Three foaming agents were used in this study: anionic Foamer A, nonionic Foamer B, and zwitterionic Foamer C.

Automated Mud Skid Holds Promise of Safety, Efficiency Improvements With Real-Time Fluid Monitoring

As industry buzzwords go, “automation” has spent its time in oilfield vernacular climbing the ranks of widely used terms. It now resides as one of the go-to designations for signs of advancement in any number of disciplines. Its use has been tied most frequently with drilling operations as contractors look to keep employees out of harm’s way via a robotic take-over of most motion-intensive jobs on the rig’s drill floor—basically anything that grips, clamps, or spins. More recently, the term has moved away from the drill floor and into other well construction operations allowing for things such as remote, real-time measurements without the need for boots on the ground. For areas like west Texas and the Permian Basin shales, having the option for remote readouts and a component of automation that can allow for corrective actions should the need arise can go a long way in terms of safety and efficiency gains as well as better manpower application. Unsurprisingly, the area has become a solid testing ground for new, expanding efforts in automation. With dreams of new drilling-fluid-monitoring automation, Eric van Oort, a professor at The University of Texas at Austin and former Shell research scientist, and select students came up with a new way to automatically measure mud parameters such as viscosity without the use of a traditional viscometer. “The fact that we still use manual measurements, some of them now 90 years old, is quite puzzling in this day and age,” van Oort said. “The Marsh funnel, for instance, was introduced in the 1930s, and other mud tests go back to the 1950s and 1960s. These API measurements have served us well, but the question is, can you do something more now with modern measurement techniques and sensors? So, I started working on new ways of measuring the viscosity and density, and then later fluid loss and even solids and salinity in muds. That proved to be all very successful and promising.” Construction of a mud skid to house the equipment and sensors needed to conduct these tests in real time was the next step in the evolution of van Oort’s concept. That initial skid was a cannibalized and reworked version of a unit that was employed on Shell’s Rig 1, which the supermajor built for its in-house rig-automation research based in Pennsylvania. This early mud skid, considered the prototype of van Oort’s design, was abandoned before it was properly tested. “We generated quite a bit of IP [intellectual property], my students and I at UT,” he said. “The Shell skid hadn’t seen a significant amount of service, and it had some nice components that we could reuse. We took that skid apart and reconfigured it and put it out in the field with Pioneer Natural Resources for a set of field trials in the Permian. Those went well.” The field trial results were shared in a paper presented at the 2019 Unconventional Resources Technology Conference (URTEC 2019-964). The paper concluded that the pipe viscometer employed by the skid allows for the characterization of additional rheology parameters, which cannot be obtained with Couette-type viscometers, such as the critical Reynolds number, characterizing the transition from laminar into turbulent flow, and the friction factor in the turbulent flow regime.

Machine learning assisted detection of excess water-producing wells in unconventional shale plays

Excess water production from oil/gas wells drilled in unconventional shale formations of Permian Basin leads to environmental concerns related to the disposal of produced water and also leads to significant expenses in water management programs. In the Delaware Basin, water-to-oil ratios are as high as 10:1 for an oil-producing well. This paper analyzes subsurface data from 20 wells targeting the Bone Springs sands and the Wolfcamp shale formation, which are the primary unconventional-resource targets in the Delaware Basin. The dataset was expanded by adding 53 wells from both the Fort Worth Basin and Gulf Coast Region. For purposes of this study, a data-driven workflow was developed to use 5 well logs from the 300-feet depth interval above or below the kick-off point for each well to detect high water-producing well. The 300 ft of logged data above or below the KOP are divided into six 50-ft intervals. From these banded intervals, 7 statistical parameters were computed for each of the 5 logs. In doing so, 210 features were generated for each well, which were then reduced to most informative 21 features by first thresholding based on p-value and F value, followed by the use of Pearson Correlation. The dimensionally reduced 21 features were used to train classification methods to predict whether a well is a high-water producer (HWPs) and low-water producer (LWPs). Logistic regression performs the best. In Delaware Basin, the prediction performance has a median F1 score of 0.96 and a median Matthew's Correlation Coefficient of 0.92. Median scores for both the Fort Worth and Gulf Coast datasets are above 0.80. For the Delaware Basin, the statistical parameters computed using deep resistivity and porosity logs from the nearest 50-ft band just below the KOP are the most informative features for detecting excess water-producing well.

An Improved Multicomponent Diffusion Model for Compositional Simulation of Fractured Unconventional Reservoirs

Summary Most simulators currently use the advection/diffusion model (ADM), where the total flux comprises Darcian advection and Fickian diffusion. However, significant errors can arise, especially for modeling diffusion processes in fractured unconventional reservoirs, if diffusion is modeled by the conventional Fick’s law using molar concentration. Hence, we propose an improved multicomponent diffusion model for fractured reservoirs to better quantify the multiphase multicomponent transport across the fracture/matrix interface. We first give a modified formulation of the Maxwell-Stefan (MS) equation to model the multicomponent diffusion driven by the chemical potential gradients. A physics-based modification is proposed for the ADM in fractured reservoirs, where fracture, matrix, and their interface are represented by three different yet interconnected flow domains to honor the flux continuity at the fracture/matrix interface. The added interface using a more representative fluid saturation and composition of the interface can hence better capture the transient mass fluxes between fracture and matrix. The proposed approach is also implemented in an in-house compositional simulator. The multicomponent diffusion model is validated with both intraphase and interphase diffusion experiments. Then, the improved model for fracture/matrix interaction is compared with a fine-grid model. The proposed multiple interacting continua (MINC) model with three continua (MINC3) can better match the fine-grid model’s result than the double-porosity (DP) model, which only obtains a fair match at an early time. Then, we simulate a gas huff ‘n’ puff (HnP) well in the Permian Basin to investigate the effect of diffusion within the fractured tight oil reservoir. The simulation reveals that diffusion has a minor effect on the performance of depletion when oil is the dominant phase. For gas HnP, the simulation neglecting diffusion will underestimate the oil recovery factor (RF) but overestimate the gas rate. The DP approach tends to overestimate the RF of heavy components but leads to a similar cumulative oil RF compared with MINC3. With the diffusion included in the simulation, gas HnP performance becomes more sensitive to the soaking time than the model without diffusion. Although increasing the soaking time will lead to a higher RF after considering diffusion, the incremental oil is not sufficiently large to justify a prolonged soaking time.

Mechanical zonation of rock properties and the development of fluid migration pathways: implications for enhanced geothermal systems in sedimentary-hosted geothermal reservoirs

Oil and gas operations in sedimentary basins have revealed the occurrence of significant temperature anomalies at depth, raising the possibility of major geothermal resource potential in the sedimentary sequences. The efficient development of such a resource may require enhancement by hydraulic stimulation. However, effective stimulation relies on an initial assessment of in situ mechanical properties and a model of the rock response. Here, we examine the distribution of mechanical properties (unconfined compressive strength, UCS; ultrasonic velocity-derived Poisson ratio, ν; and, scratch toughness, Ks) along the cored interval of a sedimentary formation with a known low-to-medium temperature geothermal anomaly in the Permian Basin, U.S. Our results reveal the presence of mechanical stratigraphy along the core, demonstrated by the alternation of distinct soft–hard (i.e.,less stiff-to-stiff) mechanical zone couplets composed of: (1) mechanically softer 0.17-m-thick Zone-A and 0.18-m-thick Zone-C with mean values of UCS = 110 MPa, ν = 0.25, Ks = 1.89 MPa·√m; and (2) mechanically harder 0.41-m-thick Zone-B and 0.15-m-thick Zone-D which show mean values of UCS = 166 MPa, ν = 0.22, and Ks = 2.87 MPa·√m. Although X-ray diffraction analyses of the samples suggest that the entire rock matrix is dominated by dolomite, the harder zones show an abundance of quartz cement (> 30%) and relatively lower phyllosilicate mineral content (< 2%) than the softer zones. Further, we observe that the mechanically harder zones have the greatest occurrences and thicknesses of hydrothermal alterations (anhydrite veins and nodules), indicating that the rock had experienced hydrothermal fluid circulation (basinal brines) in the past. We infer that the mechanical stratigraphy most likely influenced the spatial clustering of fractures that facilitated hydrothermal fluid migration in the past, and provides insight that is relevant for the exploitation of geothermal energy resources in sedimentary basins. We suggest that the harder zones or formation intervals with higher ratios of the hard zones relative to soft zones represent viable targets for hydraulic stimulation of a sedimentary-hosted geothermal reservoir, both for the emplacement of new fractures and the linkage of pre-existing fractures to allow efficient fluid circulation. Our findings in this study provide insight that is relevant for understanding the complexity of pre-existing mechanical heterogeneity in sedimentary-hosted geothermal reservoir targets in other places.

Deviations from transient linear flow behavior: A systematic investigation of possible controls on abnormal reservoir signatures

Observed deviations from classical diffusion (specifically transient linear flow, TLF) for Permian Basin Wolfcamp shale oil wells have been historically attributed to reservoir geometric heterogeneity and consequent anomalous diffusion (AD). Recently, we have suggested that the combination of multiphase flow and variable operating conditions could create similar reservoir signatures (as quantified using classic flow-regime identification techniques). However, there are additional factors, not previously investigated, that could be affecting flow-regime identification (ID). This work aims to systematically investigate all possible causes of deviations from classical diffusion behavior. A general, new semi-analytical oil flow solution is proposed that explicitly accounts for multi-phase flow, stress-sensitive reservoir properties, and variable operational conditions. This is achieved through using the combination of modified oil-phase pseudo-pressure and material balance pseudo-time. Additionally, reservoir geometric heterogeneity and AD are incorporated into the exponent of the power-law relationship between rate-normalized oil-phase pseudo-pressure and material balance pseudo-time. A new workflow is also developed to improve flow regime ID while various reservoir complex behaviors are occurring simultaneously. Using the new workflow, a comprehensive investigation into which parameters are primarily causing deviations from TLF is performed in use of simulated cases with inputs that are similar to those used to history-match a Wolfcamp shale well. Further, errors in the determination of reservoir and fracture properties caused by misdiagnosis of the flow regime are analyzed. Our extensive investigations demonstrate that: 1) multi-phase flow, and in particular the appearance of gas flow (producing gas-oil-ratio ramps up) as flowing bottomhole pressure (FBHP) drops below the bubble point pressure, has the biggest impact on the deviation from TLF; 2) even for cases with high producing water-oil-ratio, water production has relatively minor effects; 3) pressure-dependent permeability has relatively small effects, even for cases when well FBHP changes strongly; 4) deviations from TLF in a Wolfcamp shale oil example may be primarily caused by the combination of multiphase flow and variable FBHP, while the AD effect is likely secondary. Importantly, if log-log flow-regime identification plots are not corrected for complex reservoir behaviors, the reservoir flow regime may become distorted, leading to the selection of incorrect models for production analysis and errors in reservoir/fracture properties estimates.

Concurrent variation in oil and gas methane emissions and oil price during the COVID-19 pandemic

Abstract. Methane emissions associated with the production, transport, and use of oil and natural gas increase the climatic impacts of energy use; however, little is known about how emissions vary temporally and with commodity prices. We present airborne and ground-based data, supported by satellite observations, to measure weekly to monthly changes in total methane emissions in the United States' Permian Basin during a period of volatile oil prices associated with the COVID-19 pandemic. As oil prices declined from ∼ USD 60 to USD 20 per barrel, emissions changed concurrently from 3.3 % to 1.9 % of natural gas production; as prices partially recovered, emissions increased back to near initial values. Concurrently, total oil and natural gas production only declined by ∼ 10 % from the peak values seen in the months prior to the crash. Activity data indicate that a rapid decline in well development and subsequent effects on associated gas flaring and midstream infrastructure throughput are the likely drivers of temporary emission reductions. Our results, along with past satellite observations, suggest that under more typical price conditions, the Permian Basin is in a state of overcapacity in which rapidly growing associated gas production exceeds midstream capacity and leads to high methane emissions.

Direct measurements from shut-in and other abandoned wells in the Permian Basin of Texas indicate some wells are a major source of methane emissions and produced water

Oil and gas production wells are a major anthropogenic source of the greenhouse gas methane (CH4) in the United States. Oil and gas production rates from these wells fluctuate due to changes in demand, and is expected to decline over the coming decades to centuries due to the transition to renewable energy. The CH4 emissions profile from wells that are ‘shut-in’ to accommodate changes in demand has not been previously measured, and thus it is unclear whether reduced demand will actually result in reduced CH4 emissions from oil and gas production. Here we present the results of a measurement campaign of CH4 emissions from shut-in and other non-producing oil wells in the Permian Basin, Texas, the largest oil production basin on Earth. All the wells we measured were conventionally drilled oil wells, and we did not measure CH4 emissions from any shut-in unconventional wells. We found that, of 37 wells measured, two-thirds had an emission rate of less than 1 g CH4 hr−1, with the remaining seven wells ranging from 1.3 to 132.0 g CH4 hr−1. The average CH4 emission rate from all wells was 6.2 g CH4 hr−1, lower than previous measurements of CH4 emissions from active conventional wells in the Permian Basin (∼400 g CH4 hr−1) (Robertson et al (2020 Environ. Sci. Technol. 54 13926–34)). Some shut-in wells could be a substantial source of CH4 emissions if this category is not subject to leak detection and repair regulations. We also found five orphaned wells that were a source of produced water to the surface, sometimes in very large quantities (1000s of liters per minute), with evidence for emissions of CH4, hydrogen sulfide, brine, and possibly other hazardous chemicals such as oil residue. Future work should further characterize the impacts of shut-in and orphaned wells on greenhouse gas emissions, water quality and human health.

Shale oil production and groundwater: What can we learn from produced water data?

As oil production in the Permian Basin surges, the impact of shale production on groundwater resources has become a growing concern. Most existing studies focus on the impact of shale production on shallow freshwater aquifers. There is little understanding of the shale development's impact on other groundwater resources (e.g., deep carbonate aquifers and deep basin meteoric aquifers). The possible natural hydraulic connections between shallow aquifers and formation water suggest such an impact can be consequential. This study explores the relationship between shale production and groundwater using produced water (PW) samples from active unconventional oil wells. Focusing on the most productive portion of the Permian Basin-the four-county region in Southeast New Mexico between 2007 and 2016, a large produced water dataset allows us to analyze the conditional correlations between shale oil production and PW constituents. The results suggest that (1) expanding from primarily conventional wells to unconventional wells during the recent shale boom has led to dramatic increases of the TDS, chloride, sodium, and calcium levels in groundwater (i.e., producing formation). (2) Nearby oil well density positively correlates with the TDS, chloride, and sodium levels in the PW samples.

Dolomitization geometry and reservoir quality from supervised Bayesian classification and probabilistic neural networks: Midland Basin Leonardian Wichita and Clear Fork Formations

Extensive dolomitization is prevalent in the platform and periplatform carbonates in the Lower-Middle Permian strata in the Midland and greater Permian Basin. Early workers have found that the platform and shelf-top carbonates were dolomitized, whereas slope and basinal carbonates remained calcitic, proposing a reflux dolomitization model as the possible diagenetic mechanism. More importantly, they underline that this dolomitization pattern controls the porosity and forms an updip seal. These studies are predominately conducted using well logs, cores, and outcrop analogs, and although exhibiting high resolution vertically, such determinations are laterally sparse. We have used supervised Bayesian classification and probabilistic neural networks (PNN) on a 3D seismic volume to create an estimation of the most probable distribution of dolomite and limestone within a subsurface 3D volume petrophysically constrained. Combining this lithologic information with porosity, we then illuminate the diagenetic effects on a seismic scale. We started our workflow by deriving lithology classifications from well-log crossplots of neutron porosity and acoustic impedance to determine the a priori proportions of the lithology and the probability density functions calculation for each lithology type. Then, we applied these probability distributions and a priori proportions to 3D seismic volumes of the acoustic impedance and predicted neutron porosity volume to create a lithology volume and probability volumes for each lithology type. The acoustic impedance volume was obtained by model-based poststack inversion, and the neutron porosity volume was obtained by the PNN. Our results best supported a regional reflux dolomitization model, in which the porosity is increasing from shelf to slope while the dolomitization is decreasing, but with sea-level forcing. With this study, we determined that diagenesis and the corresponding reservoir quality in these platforms and periplatform strata can be directly imaged and mapped on a seismic scale by quantitative seismic interpretation and supervised classification methods.

Late Paleozoic (Late Mississippian–Middle Permian) sediment provenance and dispersal in western equatorial Pangea

Late Mississippian to middle Permian sediment-dispersal networks of regional to continental scale in western equatorial Pangea, depicted here in a series of paleogeographic maps, developed in response to temporally and spatially changing influences of climate, eustasy, and a continent-wide late Paleozoic orogenic system. The orogenic system included linked Alleghanian, Ouachita-Marathon-Sonora collisional belts and associated foreland basin systems on Laurentia and magmatic arcs on Gondwana, intracratonic basement uplifts and basins of the Ancestral Rocky Mountains, flexural arches and intracratonic basins of the US midcontinent region, and basins and uplifts of the southwestern Laurentian transcurrent continental margin. Consideration of new and published U-Pb detrital-zircon datasets permits delineation of Laurentian sediment-dispersal networks of the developing supercontinent. The Transcontinental Arch deflected Late Mississippian transcontinental rivers with Alleghanian headwaters toward the southern midcontinent and nascent, deep-marine foreland basins along the Ouachita collision orogen. Pennsylvanian rivers likewise headed in the Alleghanian Orogen, transporting sediment southwest across the midcontinent and along the Alleghanian foreland basin to empty into the Arkoma Basin and Fort Worth Basin, which also received voluminous sediment from Gondwana and the Ouachita Orogen. Concomitantly, major growth of Ancestral Rocky Mountains uplifts yielded basement-derived sediment, much of which was retained in local flexural basins. Increased aridity drove ascendant eolian transport in early Permian (Artinskian) time, just as lowstand desiccation of a midcontinent seaway exposed unconsolidated silt and sand derived from eastern, western, and southern sources in an extensive interior desert sink. Eolian transport within the interior desert further mixed and deflated the already-cosmopolitan sediment, pushing it southwest toward the Permian Basin and westward beyond the Ancestral Rocky Mountains. Intercepted by newly developed monsoonal circulation, the deflated sediment came to reside in erg systems along the western marine margin of Pangea. Subtropical Pennsylvanian transcontinental fluvial networks were similar to those of modern big river systems of the eastern and midcontinent United States that drain toward the Gulf of Mexico. In contrast, Permian drainage networks yielding sediment to a continental desert more resembled Pleistocene sediment routes of the Arabian Plate; there, intermittent wadis draining western rift highlands and big rivers of the Mesopotamian foreland contribute sediment to Arabian eolian sands via zonal and monsoonal surface winds to create widespread sand seas of mixed Eurasian and Arabian provenance.

Geodynamic modeling on the formation mechanism of Linxi Basin: New constraints on the closure time of the Paleo-Asian Ocean

The Linxi Basin is situated at the eastern portion of the Tianshan-Solonker suture where the Paleo-Asian Ocean closed and represents the key region to understand the tectonic evolution of the Solonker suture. The Linxi Basin has the best preserved Permian sediments and its formation mechanism is much debated. Two controversial Permian tectonic backgrounds are proposed for this basin, i.e., oceanic-continental convergence (hence an arc basin related to subduction) versus post-orogenic extension (hence a crustal/lithospheric subsidence basin). Oceanic-continental convergence indicates subduction of oceanic lithosphere beneath the continental boundary of the North China Craton, whereas post-orogenic extension implies a thickened continental lithosphere experienced a drip-like gravitational instability. To address this controversy, we conduct subduction and drip (lithospheric instability) numerical experiments to calculate model predictions of surface topography for the Linxi Basin across the Solonker suture. Comparisons between the model predictions and the Permian sedimentary records in the Linxi Basin are made to determine which model can better explain the sedimentation. The persistent accumulation of Permian sediments indicates continuous crustal subsidence, which fits better the predicted subsidence from our drip model. By contrast, our modelled subduction-induced surface evolution in the Linxi Basin generally shows a switch from subsidence to uplift. The better fitting of the drip tectonics indicates that the post-orogenic extension rather than subduction tectonic setting would be more suitable to explain the Linxi Basin development during the Permian. In addition, the spatial and temporal distribution of magmatic activities is consistent with drip process. Our preferred Permian basin formation induced by drip model favors an early closure of the Paleo-Asian Ocean before the Permian.

The Influence of Development Target Depletion on Stress Evolution and Infill Drilling of Upside Target in the Permian Basin

SummaryThe extensive depletion of the development target triggers the demand for infill drilling in the upside target of multilayer unconventional reservoirs. However, such an infill scheme in the field practice still heavily relies on empirical knowledge or pressure responses, and the geomechanics consequences have not been fully understood. Backed by the data set from the Permian Basin, in this work we present a novel integrated reservoir-geomechanics-fracture model to simulate the spatiotemporal stress evolution and locate the optimal development strategy in the upside target of the Bone Spring Formation. An embedded discrete fracture model (EDFM) is deployed in our fluid-flow simulation to characterize complex fractures, and the stress-dependent matrix permeability and fracture conductivity are included through the compaction/dilation option. After calibrating reservoir and fracture properties by history matching of an actual well in the development target (i.e., third Bone Spring), we run the finite element method (FEM)-based geomechanics simulation to model the 3D stress state evolution. Then a displacement discontinuity method (DDM) hydraulic fracture model is applied to simulate the multicluster fracture propagation under an updated heterogeneous stress field in the upside target (i.e., second Bone Spring). Numerical results indicate that stress field redistribution associated with parent-well production indeed vertically propagates to the upside target. The extent of stress reorientation at the infill location mainly depends on the parent-child horizontal offset, whereas the stress depletion is under the combined impact of horizontal offset, vertical offset, and infill time. A smaller parent-child horizontal offset aggravates the overlap of the stimulated reservoir volume (SRV), resulting in more substantial interwell interference and less desirable oil and gas production. The same trend is observed by varying the parent-child vertical offset. Moreover, the efficacy of an infill operation at an earlier time is less affected by parent-well depletion because of the less-disturbed stress state. The candidate infill-well locations at various infill timings are suggested based on the parent-well and child-well production cosimulation. Being able to incorporate both pressure and stress responses, the reservoir-geomechanics-fracture model delivers a more comprehensive understanding and a more integral solution of infill-well design in multilayer unconventional reservoirs. The conclusions provide practical guidelines for the subsequent development in the Permian Basin.

Completion Design Evaluated by Use of Field Offset Well-Pressure Measurements

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201346, “Are We Overstimulating Our Laterals? Evaluating Completion Design Practices Based on Field Offset Well-Pressure Measurements,” by Puneet Seth, SPE, The University of Texas at Austin, and Brendan Elliott, SPE, and Trevor Ingle, SPE, Devon Energy, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Increased injection volumes coupled with a suboptimal completion design can lead to overstimulation at current well-spacing densities. In the complete paper, the authors analyze offset well-pressure measurements in the Permian Basin to evaluate if a fracturing job is overstimulated. Additionally, numerical modeling studies are performed to evaluate the extent of overstimulation in different scenarios and provide recommendations to maximize the capital efficiency of a fracturing job. In their analysis, the authors focus on the scenario in which fracturing hits occur when child-well fractures intersect with the parent well. Field Data Analysis Pumping for the full designed volume and time (typically 90 minutes) according to well-stimulation procedures is currently common in the industry. Often, the observation of hydraulic interactions is not coupled with a decision to alter or change the stimulation. The authors analyzed the offset well-pressure response monitored with a surface pressure gauge in multiple parent wells in the Permian Basin during stimulation in nearby child wells. The child wells were stimulated after roughly 1 year of production from the parent wells. The focus of this study was to identify fracture-driven interactions—specifically the timing of intersection of the child-well fractures with the offset parent wells, which are recorded as massive hydraulic pressure responses. The results of this analysis for different well pairs are presented in the complete paper. To better understand the factors that affect fracture propagation from the child wells toward the parent wells, fracture arrival times, and capital efficiency of a fracturing job, a series of numerical simulations was performed with a fully coupled hydraulic fracturing simulator. Simulation Results Numerical simulations were performed using an integrated hydraulic fracturing and reservoir simulator developed at The University of Texas at Austin. This simulator solves for flow and geomechanics in the reservoir, fracture, and wellbore domains in a tightly coupled manner. Hydraulic fractures are modeled as compliant discontinuities in the reservoir rather than high-permeability gridblocks. This is important in order to capture the stress alterations around a propagating fracture accurately. Effect of Parent-Well Production (Depleted Region). For this study, two scenarios were analyzed. In the first case, fracture propagation from a child well stimulated near a recently fractured unproduced parent well (no depletion) was considered. In this case, the fracture from the child well propagates away from the parent well because of elevated stresses near the parent well. In the second case, a child well is stimulated near a parent well that has been producing for 300 days before child-well stimulation. In this scenario, the child-well fracture propagates toward the parent well because of a depleted region that develops near the parent well (because of production) and relaxes the reservoir stresses around the parent well. This causes the child-well fracture to grow preferentially toward the parent well (toward the low-stress region). In fact, in this scenario, as the fracture reaches the depleted reservoir region, its growth accelerates toward the parent well and intersects with the parent well. Even minor depletion can induce asymmetric growth of infill child-well fractures toward the parent well.