Petroleum Wells Research Articles

Produced water geochemistry from hydraulically stimulated Niobrara Formation petroleum wells: Origin of salinity and temporal perspectives on treatment and reuse

Produced water (i.e., a mixture of returned injection fluids and geologic formation brines) represents the largest volumetric waste stream associated with petroleum production in the United States. As such, produced water has been the focus of intense study with emphasis on understanding the geologic origin of the fluids, environmental impacts of unintended or intentional release, disposal concerns, and their commodity (e.g., lithium) potential. However, produced water geochemistry from many active petroleum plays remain poorly constrained leading to knowledge gaps associated with the origin of brine salinity and parameters (e.g., radium levels) that can impact treatment, disposal, and possible reuse. Here we evaluate the major ion geochemistry, radium concentrations, and stable water isotope composition of ~120 produced water samples collected from 17 producing unconventional petroleum wells in Weld County, Colorado from the Late Cretaceous Niobrara Formation. This sample set encompasses eight produced water time series from four new wells across production days 0 to ~365 and from four established wells across production days ~1000 to ~1700. Additionally, produced water from nine other established Niobrara Formation wells were sampled at discrete time points ranging from day 458 to day 2256, as well as hydraulic fracturing input fluids. These results expand the available Niobrara Formation produced water geochemical data, previously limited to few wells sampled within the first year of production, allowing for the heterogeneity of major ions and radium to be evaluated. Furthermore, we explore the geochemical relationships between major ion ratios and stable water isotope composition to understand the origin of salinity in Niobrara Formation brines from the Denver-Julesburg Basin. These findings are discussed with perspective toward potential treatment and reuse of Niobrara produced water prior to disposal.

Multiphase flow modelling of gas migration from a hypothetical integrity-compromised petroleum well in the peace region of North-eastern British Columbia, Canada

Well-integrity failure occurs in a small subset of petroleum wells, resulting in release of fugitive gas into intersected geologic formations. Released fugitive gas from geoenergy systems is a growing environmental concern that can contaminate groundwater aquifers and emit greenhouse gases (GHGs) to atmosphere. Currently, the roles of well-cement quality and properties of intersected geologic formations on the environmental outcomes of well-integrity failure is poorly understood. To advance understanding, we numerically modelled a hypothetical fugitive methane release from a petroleum well intersecting the Sunset Paleovalley aquifer system in Northeast British Columbia, Canada. We simulate a 10-year release and migration of fugitive gas into a two dimensional, two-phase, two-component advective flow field with the subsurface properties informed by field and laboratory data. We evaluate the effects of cement quality, gas release depth, and geologic heterogeneity on fugitive-gas containment or emission by defining and/or evaluating three key numbers: a) emission-retention ratio (ERR), b) well integrity index (WII), and c) fugitive gas mobility ratio (MR) over relevant spatiotemporal scales. We show that ERR and WII capture the bifurcated impacts of fugitive gas from petroleum wells, including groundwater contamination and atmospheric emissions. A WII close to one reduces vertical fugitive-gas migration along the well bore, fosters lateral migration into intersected geologic materials and significantly limits GHG emissions to atmosphere. MR and ERR values show fugitive-gas migration and fate are primarily controlled by the casing annulus cement quality, particularly when fugitive gas is released at shallow depths. We conclude that the quality of petroleum-well cement is among the parameters controlling the migration pathways, impacts, and fate of fugitive-gas release.

Mechanical Performance of Bentonite Plugs in Abandonment Operations of Petroleum Wells

This study aims to evaluate how the operational procedure adopted for pellet placement and the exposure to subsurface conditions influence the mechanical integrity of bentonite plugs used as barrier elements in the abandonment of petroleum wells. To this end, the plugs were formed by hydrating the pellets directly in water, simulating the onshore procedure, while the offshore plugs were obtained from pellets hydrated in deionized water after immersion in diesel or olefin, which are suggested as displacement fluids. The plugs obtained were tested by compression and adhesion tests. These mechanical tests were also carried out for specimens obtained from plugs exposed to four formulations of synthetic formation waters. The results obtained demonstrated that, in the offshore procedure, the previous contact with olefin may adversely affects the mechanical stability of bentonite plugs, while plugs formed from pellets immersed in diesel presented satisfactory mechanical properties. However, the contact with formation water evidenced that the onshore plug presents superior resistance than the offshore plug previously immersed in diesel. The highly successful performance of the onshore plug was attested by the maintenance of the compressive strength, which exhibited a maximum reduction of 13%, even after exposure to the most saline formation waters.

Heat extraction from abandoned petroleum wells utilizing coaxial borehole heat exchanger in Ordos basin, China

To extract geothermal energy from abandoned petroleum wells in Ordos basin, China, a coaxial deep borehole heat exchanger (DBHE) is studied through a 3D numerical model. Factors, such as thermophysical properties, geological characteristics and operational conditions, are considered. Given the geothermal gradients and rock/soil properties, numerical results suggest that a sustainable heat extraction rate can be achieved for building heating purpose in long term; after 20 years’ operation, with an injection rate of 30 m3/h at 20 °C and wellbore length being 2350 m, the outlet temperature is around 24 °C, the heat load per unit depth ranges from 89.2 W/m to 67.7 W/m. Through comparison between on-site tests and numerical modeling, it is suggested that factors like well integrity, operational conditions and insulation between the inflow and outflow pipe should be taken into account. Numerical modeling on variation of well depth is performed; results show that both the wellbore length of 1800 m and 2350 m could satisfy a heat extraction load of 80 W/m, and the greater the wellbore length, the larger the outlet temperature. According to results from a DBHE array model, the general 200 m–300 m wellbore interval would not cause thermal interaction.

The Paleocene - Eocene mangroves of southeastern Australia: spatial and temporal occurrences across four geological basins

The advent of the Paleocene-Eocene Thermal Maximum (PETM), a ∼ 200 kyr period of global warming ca. 56 Ma, caused sea-levels to rise, transgressing near-coastal environments in southeastern (SE) Australia over >55,000 km2. During the PETM, warming tropical climates may have extended south to ≥60°S paleolatitude. The PETM in SE Australia is corroborated primarily by stable carbon isotope chemostratigraphy and detailed palynology records in four geological basins. Previous work showed that, in addition to the globally recognised carbon isotope excursion, the PETM interval in coastal SE Australia can be identified using the dual occurrence of the tropical mangrove Nypa palm pollen (Spinizonocolpites prominatus) accompanied by thermophilic marine dinoflagellate cysts (mainly Apectodinium hyperacanthum). We here document a total of twenty-six Gippsland Basin wells that record this Nypa-A.hyperacanthum association in the earliest Eocene Kingfish Formation (Lower Malvacipollis diversus Zone). In the Bass Basin, eight wells record Nypa-A.hyperacanthum association within the Eastern View Group basal Koorkah Formation, or lower part of the Lower M. diversus Zone (earliest Eocene). In the Bass Basin a further thirteen wells with Nypa occurrences near the top of the Cormorant Formation are found, which might be associated with the longer-term warmth of the Early Eocene Climatic Optimum (EECO, ∼53–49 Ma). Government bores and petroleum wells across the Otway Basin record the Nypa-A. hyperacanthum PETM association within the Pember Mudstone Lower M. diversus Zone in twenty-one bores. Nine horizons with Nypa occurrences occur within the Burrungule Member (EECO) at the top of the Dilwyn Formation. In western Tasmania, Nypa occurs in the Sorell Basin and Macquarie Harbour area within the Lower M. diversus Zone. Together, these observations show the remarkable extent of the mangrove-coasts that were established across the mid-high paleolatitudes in SE Australia during the warmest intervals of the Cenozoic, the PETM and EECO.

Transforming abandoned petroleum wells in the Nigerian sector of the Chad basin into triplet borehole heat exchangers for sustainable power generation

This study pioneers a transformative approach to sustainable energy recovery, repurposing abandoned petroleum wells in the Nigerian Chad Basin as a triplet-deep closed-loop heat exchanger. We employed a computational numerical approach to designed two deep closed loop systems, which share a common production well, and to evaluate the thermal performance as well as its sustainability over a period of 25 years. The geometrical configuration consists of two injection wells, which converge to the common production one doubling the flow rate at surface and minimising the heat loss during the ascent of the fluid. The availability of detailed abandoned well specifications enabled us to constrain three-dimensional geological and thermal models of the undisturbed underground and, subsequently, to simulate numerically the production temperature and the thermal disturbance in the surrounding rocks. A comprehensive sensitivity analysis optimized the best operational design for total recovered thermal energy and uninterrupted heat recovery. When the deep close loop heat system operates with a fluid circulation rate of 0.03 m³s⁻1 and an injection temperature of 20 °C, it sustains a production temperature of over 100 °C, which generates total recovered thermal energy of 9730 TWth and 817 TWe over 25 years (9000 days). The average annual thermal and electricity productions of 389 TWth and 33 TWe, respectively, are more than the demand of the entire population of Magumeri district. The study's findings offer practical implications for policymakers, industry stakeholders, and local communities, emphasising the potential for socio-economic development while fostering environmental stewardship in the Nigerian Chad Basin.

Review of Triassic Sherwood Sandstone Group reservoirs of Ireland and Great Britain and their future role in geoenergy applications

As the world progressively shifts to a low/neutral carbon economy over the course of the twenty-first century, geoscience will continue to play a vital role in the energy sector and beyond. Static and dynamic characterization of the subsurface, a key component of the petroleum industry for decades, will be required to evaluate and unlock a variety of different initiatives including carbon, capture and storage (CCS), hydrogen (or any other gas) storage, thermal energy storage and geothermal energy development. Onshore and offshore Ireland and Great Britain, Lower Triassic sandstones are likely to represent one of the primary geological targets for future geoenergy applications. This paper provides a review of the Triassic Sherwood Sandstone Group depositional system across the British and Irish region of NW Europe including its overall stratigraphic context, palaeogeography, sediment provenance and transport directions, and present-day distribution. In addition to geological outcrop data, there is a wealth of subsurface data available from historical petroleum wells. Looking forward, one important focus of geoscience research will be to extrapolate away from these well-defined control points to predict sandstone facies distribution, diagenetic history and hence overall reservoir quality in new undrilled areas that will be of interest to the geothermal, CCS and gas storage sectors.

Analysis and Prediction of Equivalent Diameter of Air Bubbles Rising in Water

The equivalent diameter of rising bubbles in liquids is an important parameter that has been investigated for decades by researchers for different purposes. Bubble diameter plays important role in quantifying oil and gas leaks in subsea leak analysis, since it allows the prediction of the magnitude of leaks in seabed petroleum wells and other structures through images obtained by underwater vehicles at great depths. Most studies available in the literature on the subject focus on investigating air bubbles in water; therefore, they were used as the main guide of the experimental apparatus described in this article. Several tests were conducted with air bubble chain in tap water, whose flow rate ranged from 21.1 mL/min to 234.4 mL/min, whereas the bubble equivalent diameter ranged from 4.1 mm to 8.2 mm. In addition, computational fluid dynamics simulations were carried out for comparison purposes; they were validated as potential tools to help designing an automated subsea gas leakage monitoring system based on image analysis algorithms. The herein proposed model could be both analytically and experimentally validated, based on comparisons to findings reported by other authors. This procedure enabled gathering evidence about the most efficient analytical predictions available in the literature for the herein addressed scenario. The results in the present study are consistent to those recorded in the main related articles.

Innovative drilling fluid containing sand grafted with a cationic surfactant capable of drilling high pressure and high temperature geothermal and petroleum wells

Maintaining the rheology and filtration properties of a drilling fluid plays a vital role during a drilling operation. With the current challenges of high pressure and high temperature environments, there is an urgent need to design thermally stable water-based mud systems (WBM) which are environmentally clean and economically cheap.High pressure and high temperature (HPHT) environments affect drilling fluid systems leading to degradation of additives hence reducing the efficiency of the drilling fluid. Nanotechnology has been widely used to answer questions about additive degradation, and many studies are currently being conducted on how to use nanotechnology to design smart drilling fluids. However, nanotechnology comes at a high cost, resulting in an increase in the overall drilling operation costs and the project as a all. Therefore, the effectiveness of sand particles as a replacement of commercial nanoparticles is investigated in this study as an additive for designing effective-performance water-based drilling fluids. Effective-performance drilling fluids are environmentally friendly, stable at high temperatures, and help to avoid well damage during drilling operations.The research compared sand particles, which are widely available and inexpensive to silica nanoparticles at 0.5 wt% concentration. The samples were tested at different aging temperatures. Rheological properties were measured at room temperature up to 232 °C. The performance of sand and silica nanoparticles was studied by comparing each of the nanoparticle muds with the reference mud sample, taking filtration and rheological properties as the benchmark parameters. Experimental data showed that sand particles enhanced almost all the rheological and filtration properties of the WBM compared to the reference mud. When compared to silica nanoparticles, the results showed neither statistically significant variance in plastic viscosity and yield point among the samples, with muds containing sand particles performing similarly or better. Formulation S2 (35–70 μm) demonstrated the ability to improve the rheology of WBM. At 204 °C and 232 °C, Formulation S2 (35–70 μm) filtrate loss decreased by 16.35% and 29.52%, respectively, compared to 5.66% and 11.32% by mud containing nano silica. The same mud sample decreased the mud cake thickness at the same temperatures conditions by 54.74% and 45.45%, respectively, as opposed to 36.84% and 11.81%. The new innovative mud system can be used to drill in HPHT conditions.

Study Explores Retrofitting Abandoned Petroleum Wells for Geothermal Production

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210861, “An Overview of Retrofitting Abandoned Petroleum Wells for Geothermal Energy Production,” by Rahman Ashena, SPE, Asia Pacific University of Technology and Innovation. The paper has not been peer reviewed. _ The complete paper presents a comprehensive overview and analysis of 20 global case studies in which abandoned petroleum wells were retrofit for geothermal applications, followed by important downhole and surface parameters. Good potential exists for producing geothermal energy from abandoned and nonactivated petroleum wells. Introduction In retrofitted geothermal projects, the bottomhole temperatures are usually much lower than conventional geothermal wells. Given the low temperatures of these projects, optimization should be achieved in all respects. While the complete paper details the effect of the concepts investigated by the authors in the 20 case studies, this synopsis mainly offers a higher-level summary of these concepts rather than a discussion of the case studies themselves. Overview All case studies mentioned in the complete paper are simulation works except for one. Table 1 of the complete paper lists general information including the regional locations and investigators of these case studies, while Table 2 of the complete paper provides comprehensive design and production information about the cases provided.

How Quickly Do Oil and Gas Wells “Water Out”? Quantifying and Contrasting Water Production Trends

Water production from petroleum (oil and natural gas) wells is a topic of increasing environmental and economic importance, yet quantification efforts have been limited to date, and patterns between and within petroleum plays are largely unscrutinized. Additionally, classification of reservoirs as “unconventional” (also known as “continuous”) carries scientific and regulatory importance, but in some cases the distinction from "conventional" wells is unclear. Using water, oil, and gas production data, we calculated a set of quantitative metrics that elucidate trends in the water-to-petroleum ratio over the life of each producing well. The percent growth of the water-to-petroleum ratio quantifies the degree to which a well “waters out” over time; values calculated for 153,900 wells in 18 oil and gas plays show generally much higher values for conventional wells than for continuous/unconventional wells. Analysis of the percent growth along with the slope and median metrics reveals greater variation between conventional plays and between continuous (unconventional) plays than previously recognized. Further, an example from the Bakken Formation in the Williston Basin, USA, illustrates that, within a single play, the metrics provide insight into spatial variation of water production trends, as influenced by geology and reservoir characteristics. By quantifying the variability of water production trends within individual plays and between plays, including differences between conventional and continuous (unconventional) plays, these results provide a more nuanced view of water production from oil and gas wells than has previously been possible and they illustrate the degree to which water management considerations vary spatially and temporally.

Malmquist–Luenberger Productivity Index for a Two-Stage Structure in the Presence of Undesirable Outputs and Uncertainty

Network Data Envelopment Analysis (NDEA) models assess the processes of the underlying system at a certain moment and disregard the dynamic effects in the production process. Hence, distorted efficiency evaluation is gained that might give misleading information to decision-making units (DMUs). Malmquist–Luenberger Productivity Index (MPI) assesses efficiency changes over time, which are measured as the product of recovery and frontier-shift terms, both coming from the DEA framework. In this study, a form of MPI involving network structure for evaluating DMUs in the presence of uncertainty and undesirable outputs in two periods of time is presented. To cope with uncertainty, we use the stochastic p-robust approach and the weak disposability of Kuosmanen (American Journal Agricultural Economics 87 (4):1077–1082, 2005) proposed to take care of undesirable outputs. The proposed fractional models for stages and overall system are linearized by applying the Charnes and Cooper transformation. Finally, the proposed models are applied to evaluate the efficiency of 11 petroleum wells to identify the main factors determining their productivity, utilizing the data from the 2020 to 2021 period. The results show that the management of resource consumption, especially equipment and capital, is not appropriate and investment is inadequate. Although the depreciation rate of capital facilities in this industry is high, the purpose of the investment is not to upgrade the level of technology.

Natural fractures at depth in shale reservoirs: new insights from the southern Sichuan Basin marine shales

Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a useful opportunity to try to understand subsurface fracture networks in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in the southern Sichuan Basin, four types of natural fractures were identified in terms of orientation, size, filling properties and spatial distribution. Uncemented bed-parallel shear fractures develop at or in the vicinity of mechanical interfaces and are inclined to present in shale layers with a dip angle greater than 12°. Cemented bed-parallel fractures are characterized by a crack-seal texture marked by multiple bands of fibrous cement, and their intensity decreases upwards and shows a positive relationship with total organic carbon (TOC) values. Uncemented bed-oblique fractures are a type of fracture that rarely develops, and accommodate limited open space. Cemented bed-oblique/perpendicular fractures are the most developed fracture type and are distributed on a regional scale and are subdivided into two types. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability, yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.

Curie point depth from airborne magnetic data analysis for geothermal exploration in southern Thailand

Southern Thailand is a high heat flow region, which implies to high-potential area of geothermal resources. Direct heat flow measurements are only available from petroleum wells in Gulf of Thailand. Therefore, indirect method of Curie Point Depth (CPD) calculation has been used to evaluate the heat flow on land of southern Thailand. CPD is the theoretical depth at which subsurface temperature reaches the value of the Curie point of magnetite, which is 578 °C. CPD can be calculated by deriving the depth of the bottom of the magnetic body to the surface using spectral analysis from airborne magnetic data, and the calculated values can produce the CPD map of southern Thailand. The results show that CPD ranges from 7.88 to 19.75 km with an average of 13.74 km, and heat flow ranges from 61.54 to 154.25 mW/m2 with an average of 90.36 mW/m2. This study suggests that the high heat flow in southern Thailand, which is higher than the regular continental crust heat flow of 65 mW/m2, is possibly caused by a high heat anomaly from mantle upwelling and expressed through weak zones of faults and sutures in extensional tectonic regimes. The high heat from mantle has elevated by five zones: (1) Ranong faults zone, (2) Khlong Marui faults zone, (3) Coastline of Surat Thani and Nakhon Si Thammarat, (4) Trang and Satun zone, and (5) Bentong-Roab suture. These five zones are considered to be high-potential areas for future geothermal resources exploration.

Influence of gas density on void fraction and pressure drop in upward vapor–liquid flow

The influence of gas density on the void fraction, flow map, and pressure drop was examined for an upward vapor–liquid flow. The knowledge of the flow map is necessary to ensure a safe operational condition in a nuclear zone at high pressure. Moreover, the pressure gradient and its volumetric flow rate are related to the profitability of petroleum wells. Considering these scenarios, a modified cascade refrigeration cycle was constructed to generate and measure single-phase streams with different liquid and vapor density ratios. These single-phase liquid and vapor streams were mixed and injected into an upward vertical test section with an inner diameter of 26.64 mm and length of 5.8 m. The pressure ranged from 1.7 to 2.3 MPa, liquid–vapor density ratio ranged from 10.2 to 15.2, and total mass flux ranged from 733.1 to 882.9 kg.s−1.m−2. The void fraction, pressure gradient, and frictional pressure component were measured using quick-closing valves, temperature probes, and absolute and differential pressure sensors. The experimental data and transition line behavior of the flow map at high pressures in an upward two-phase flow as well as the proposed correction factors for the pressure gradient and its frictional component reflect the novelty of this study. Most existing studies have focused only on the influence of the gas density on the horizontal flow. A key observation of our study is that the liquid–vapor density ratio significantly changes the churn and annular transition lines. According to a vertical flow map found in the literature, the disappearance of the churn region can be foreseen and an annular transition occurs at lower gas velocities. The liquid–vapor density ratio does not influence the void fraction or slip velocity ratio; both increase with the superficial vapor velocity. Correction factors for the pressure gradient and its frictional component were proposed. The mean deviation for the pressure gradient was reduced from 27 % to 16 % after application of the correction factor. Half of the experimental points presented absolute relative errors lower than 30 % for the frictional pressure gradient. A cross-validation between the experimental data reported by other authors and the proposed correction factors was conducted to assess their response. In this cross-validation, 126 additional experimental points were used for the pressure gradient whereas 1270 points were used for its frictional component. Overall, the mean deviation of the pressure gradient was reduced from 92.7 % to 31.9 % after the application of the correction factor. Similarly, the mean deviation of the frictional gradient was reduced from 70.7 % to 31.3 % after the application of the correction factor. There was no evident influence of the liquid–vapor density ratio on the total pressure gradient and drift relationships for Froude numbers spanning from 2.6 to 7.4.

A coupled model of wellbore-formation thermal phenomena and salt creep in offshore wells

The present work proposes a mathematical framework for calculating heat transport and annular pressure buildup (APB) in petroleum wells, taking into account salt creep in uncemented annular segments. To achieve this, we propose a Laplace Transform-based semi-analytic method to calculate transient heat flow in the wellbore. To estimate wellbore closure due to creep, we developed a Finite Element Method (FEM) formulation to handle the three deformation components that affect salt displacement. In addition to the time-dependent creep deformation of the rock, the model initially considers the elastic deformation of the rock due to geomechanical loads and pressure changes in the exposed annulus. The model was compared against field data from a well that contained an 800-m long uncemented second annulus exposed to halite. Regarding APB, considering creep in the salt layer resulted in a 2.55-MPa increase (approximately 15%) in annulus pressure. The thermal expansion of the salt rock did not significantly affect APB but significantly increased the computational cost of the simulations.

Lithospheric and asthenospheric properties of the saharan platform inferred from potential field, geoid and heat flow data

In this paper, we construct a geophysical-based model of the crust and uppermost mantle to provide an understanding of the architecture of the intricate deep structures, and determine the origin of geothermal reservoirs within the Saharan platform. These structures influence the distribution of the geothermal resources in the eastern Algerian Sahara. This study illustrate the deep structures of the lithosphere and asthenosphere, extending to depths of ∼350 km. Heat flow values were measured from petroleum wells and calculated from the magnetic data. The estimation of lithospheric mantle density was at standard pressure-temperature (P-T) conditions. However, the layer thickness estimate was, based on coupled analysis of elevation-geoid anomaly information. Hence, thermal models were generated with respect to crustal, crystalline basement and lithospheric-asthenospheric boundaries. Analyses of gravity, geoid and topographic dataset, shows that the Moho depth is deeper towards the southeastern limits, and shallower across the M'zab dorsal and the Hassi R'mel basin. The Moho temperature estimates were between 415 and 498 °C, typical of a cold stable cratonic crust. Results of lithospheric thickness were between 177 and 222 km, with maximum depth occurring within the northwestern limits of the Saharan platform. Hence, this paper provides an initial comprehensive geodynamic model, and gives insight to the origin of the geothermal potential of the Eastern Sahara.

Bedrock Geologic Database of the Vincennes 30- x 60-Minute Quadrangle, Indiana

Located in the eastern Illinois Basin, the Vincennes 1:100,000-scale quadrangle comprises portions of Daviess, Knox, Sullivan, and Greene Counties in Indiana. It is situated in the rolling topography of the Wabash Lowland and dominated by Pennsylvanian-age coal-bearing strata. Pennsylvanian siliciclastics in the Vincennes quadrangle host economically significant coal seams. The most widespread coal beds occur in the Carbondale Group, but the Raccoon Creek Group hosts superior coal quality (low sulfur, low ash) in Indiana. Both surface and underground mining of these coals have been extensive, with expansive impacts on the landscape and subsequent reclamation. Bedrock outcrop is largely obscured by multiple cycles of glacial sediments, and extensive fluvial activity of the Wabash River has formed deep channels (paleo and active) filled with outwash and alluvium. The geological map of Gray and others (1970) is the fundamental compilation of previous geological knowledge from this area. Additional geological information for the Vincennes quadrangle comes from previous 1:24k-scale mapping through the STATEMAP program. Specifically, Fraser and others (1998) conducted bedrock mapping in the 7.5-minute Wheatland and Washington quadrangles, and Fraser and Zlotin (1997) did some mapping in the 7.5-minute Montgomery quadrangle. Conolly and others (1996) performed a coal availability study in the 7.5-minute Wheatland quadrangle. However, the most information for the 1:100k Vincennes quadrangle and, more broadly, the western corridor, comes from the Indiana-scale coal seam mapping conducted between 2011 and 2017 based on the Indiana Coal Stratigraphic Database (NCRDS) and Indiana Coal Quality Database (ICQD), and geophysical logs from petroleum wells archived in the Petroleum Database Management System (PDMS). These data were previously presented in Esri-based Indiana Coal Atlas StoryMaps for the entire western corridor (Drobniak and others, 2017a, 2017b, 2017c, 2017d). This geologic map was funded in part through the STATEMAP Program supported by the U.S. Geological Survey under Cooperative Agreement No. G21AC10646. The Bedrock Geologic Database of the Vincennes 30- x 60- Minute Quadrangle is a composite geodata set that conforms to "GeMS (Geologic Map Schema)--a standard format for the digital publication of geologic maps," available at http://ngmdb.usgs.gov/Info/standards/GeMS/. Metadata records associated with each element within the geodata set contain more detailed descriptions of their purposes, constituent entities, and attributes. An OPEN shapefile version of the data set is also available. It consists of shapefiles, DBF files, and delimited text files and retains all information in the native geodatabase, but some programming will likely be necessary to assemble these components into usable formats.

The Potash Identification (PID) Plot: A Rapid Screening Crossplot for Discrimination of Commercial Potash

Potash minerals are the primary source of potassium (K), which is used for the manufacture of gunpowder, fertilizer, and as a sodium-seasoning substitute. Commercial potash minerals are all evaporites. Because potassium-40 (40K) is radioactive (decaying to argon-40 (40Ar) and releasing a gamma ray (GR) in the process), commercial potash mineralization is often discovered when GR (γ ray) logs in petroleum wells drilled through evaporite sequences “go off scale.” However, not all potash minerals may be commercial sources of potassium via underground mining techniques, and potassium is not the only radioactive element. For example, the mineralogy of the McNutt “potash” Member of the Salado Formation in southeast (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 for underground mining. There are also four nonradioactive evaporite minerals, one of which may interfere with potash milling chemistry and numerous claystones and marker beds (shales and/or volcanics), with GR count rates comparable to the low-grade potash mineralization in this sequence. Because of this complexity, traditional borehole wireline (WL) and logging-while-drilling (LWD) potash assay techniques, such as GR log-to-core assay transforms, may not be sufficient to identify potentially commercial potash mineralization for underground mining (Teufel, 2008) in SE New Mexico. Crain and Anderson (1966) and Hill (2019) developed linear programming and multimineral analyses, respectively, to estimate potash mineralogy and grades from multiple borehole geophysical measurements. However, both of these approaches require large sets of multiple log measurements. In SE New Mexico, petroleum wells are drilled through the Salado Formation evaporite (including the McNutt “potash” Member) with air, then cased and cemented in place without running WL measurements. Then, the wells are drilled out to total depth (TD) in the underlying sediments with water-based mud. Complete log suites are 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, essentially all recent oil and gas wells in SE New Mexico have casedhole gamma ray and neutron logs through the Salado evaporite. Hill and Crain (2020) developed a simple crossplot involving only GR and neutron log data, which could discriminate between anhydrous and hydrated potassium evaporite minerals. Logs from these wells could provide a rapid potash screening database if used properly. This technique can be used with both openhole and casedhole petroleum well logs, as well as corehole WL logs, and provides discrimination of commercial potash mineralization from noncommercial (potash and non-potash) radioactive mineralization. Case histories of the use of PID crossplots in evaporite basins of Michigan, Nova Scotia, Saskatchewan, and SE New Mexico are described. This technique may also be useful in screening potential potash deposits elsewhere in the world.

Hydrocarbon reservoir depth identification in the eastern black sea basin: Implications from euler deconvolution and gravity tensor invariants

The Black Sea Basin (BSB) consisting of Eastern Black Sea (EBS) and Western Black Sea (WBS) basins which separated by the Mid Black Sea High (MBSH) is formed by the collision of Eurasia and Arabian-African Plates. Petroleum and gas hydrate contents of the BSB have been discussed by using different geological and geophysical research. In this study, the gravity gradient tensor and invariant data based on the Bouguer gravity anomaly of the EBS basin were evaluated to define the hydrocarbon reservoirs. Afterwards, Euler deconvolution technique is applied to the invariant to reveal the depth of subsurface bodies. Furthermore, the significant invariant anomalies are compared with known oil seepage and petroleum wells. The depth values of oil trace closest to the known Sürmene and Hopa drill holes were computed as 4809 m, and 4455 m according to the structural index values of SI = 2.