Plugging the Skills Gap

Introduction Although petroleum engineering as a profession is relatively new timewise, it has matured rapidly and become a recognized and essential element in the financing of oil and gas operations. Most oil operators have become accustomed to working with the bank petroleum engineer and know that certain requirements must be met to obtain loans. It is worth noting that petroleum engineers have found bank work to be interesting, varied and rewarding. For the alert, competent and ambitious, there are ample opportunities for advancement and promotion to officer status. The main objectives in this discussion are to comment on financing oil and gas operations by banks and to discuss in some detail the importance, content and usefulness of the engineering report in establishing the value of a property as collateral and in forecasting production for repayment of a loan. It may seem contradictory to the popular idea of conservative bank practice that a bank would accept as collateral for loans oil and gas still in the reservoir rock-commodities that are fluid, mobile, cannot be inspected or insured and must be produced from wells and sold in order to make payments on the loans. However, experience with loans based on properly engineered reserves has been most satisfactory and many oil-minded banks claim they have never had a bad oil loan. Oil loans are not new to banks; they were started in the early thirties, increased noticeably after 1935 and especially since 1945. In the meantime, banks have made hundreds of oil loans and found them not only safe and profitable, but helpful in developing the growth of important relationships in regard to deposits and use of other bank services. The acceptability of the oil loan to commercial banks is due primarily tolegislation that regulates oil production to prevent waste,recognition of correlative rights,increased engineering ability to estimate with reasonable accuracy reserves and forecasts of production andadvanced production technology. These factors have tended to stabilize prices and substantially improve reliance on reserve estimates and forecasts of revenue.

The primary objective of this paper is to investigate the Reflection of risk analysis and risk assessment into HSE management for oil and gas operations in Kirkuk province. The study focuses on the Baghdad Oil Refinery for petrochemical and bitumen production and the Barham Group for refining petroleum products, which has significant implications for health and safety management. A descriptive analytical method was used to examine the data and describe the relationships between the variables. Questionnaire forms were used for data collection; 92 forms were distributed, and the study population consisted of 64 employees from the two oil operations who completed and returned the form. The IBM SPSS 26 statistical program was used for statistical analysis and findings. The results revealed a direct and significant relationship between the Reflection of risk analysis and risk assessment in HSE management. The relationship variables of Reflection these two aspects also had a positive impact on the HSE management system. The study offers practical recommendations to address identified challenges in the two operations and suggests implementing the findings across industrial facilities in Kirkuk province. It is the first time these variables have been combined in a study of the Baghdad Oil Refinery and the Barham Group.

Unconventional and conventional oil and gas (O&G) operations raise public health concerns, such as the potential impacts from trucking activity in communities that host these operations. In this work, we used two approaches to evaluate accidents in relation to O&G activities in the State of Colorado. First, we calculated the rate of truck accidents by computing the ratio of accident count and county population. When comparing counties with increased O&G operations to counties with less activity, we found that counties with more activity have greater rates of truck traffic accidents per capita (Rate Ratio = 1.07, p < 0.05, 95% CI: 1.01–1.13). Second, we laid a grid over the eleven counties of interest and counted, for each cell, the number of truck accidents, the number of multivehicle accidents with injuries, the number of homes, and the number of O&G wells. We then applied hurdle count models, using the accident counts as the outcomes and the number of homes and number of wells as independent variables. We found that both independent variables are significant predictors of truck accidents and multivehicle truck accidents. These accidents are of concern since they can have an impact on the people who live near O&G operations.

A coupled geomechanics and fluid flow model for induced seismicity prediction in oil and gas operations and geothermal applications

Commercial Oil and Gas discoveries have been made in Uganda, mainly in the Albertine Grabben area. The Grabben area is also a natural habitat to hundreds of flora and fauna species, especially in the Murchison Falls National Park, where significant discoveries of Oil and Gas have been made. Oil and Gas operations in this wild life area must coexist in harmony with the permanent ‘inhabitants’; the flora and fauna. This coexistence poses imminent safety hazards ranging from encountering deadly reptiles, stealthy lions, charging buffalos, startled warthogs, gigantic elephants, stinging bees, mosquitoes, tsetse flies, dashing antelopes, whizzing birds, to mention but a few. Statistically, wildlife related incidents present a significant percentage of recorded incident occurrences within TOTAL E&amp;P Uganda. This paper presents an experience of Total E&amp;P Uganda on Managing Safety in regard to wildlife hazard in its Oil and Gas Operations within their Block. It highlights descriptions of the current safety realities, various preventive and reactive measures that Total E&amp;P has implemented to manage the wildlife hazards and the success that has been obtained, despite the prevailing challenges.

Tax compliance and Value-Added Tax (VAT) management are critical components of financial reporting in the oil and gas industry, given its complex regulatory landscape, cross-border transactions, and high-value capital investments. Failure to comply with tax regulations can result in severe financial penalties, legal risks, and operational inefficiencies. This paper presents a structured framework for developing a tax compliance and VAT management system tailored to oil and gas operations, ensuring financial accuracy, regulatory adherence, and enhanced reporting efficiency. The proposed framework integrates automation, data analytics, and artificial intelligence (AI) to optimize tax processes, reduce errors, and improve compliance. AI-driven tax engines process real-time financial data, identify tax liabilities, and generate accurate VAT reports, minimizing manual intervention. Blockchain technology is incorporated to enhance transparency in financial transactions, preventing tax fraud and ensuring secure data management. Additionally, predictive analytics is utilized to assess potential tax risks, enabling proactive financial planning. A key feature of this framework is its ability to harmonize tax compliance across multiple jurisdictions, addressing the complexities of global oil and gas operations. By implementing standardized tax reporting mechanisms and real-time monitoring systems, companies can ensure adherence to evolving tax regulations and mitigate financial risks. The model also emphasizes strategic VAT recovery and optimization, enabling firms to reclaim eligible tax credits and improve cash flow efficiency. Furthermore, regulatory compliance modules are embedded within the system to align with international tax laws, including OECD guidelines, IFRS standards, and country-specific VAT policies. The framework also promotes seamless integration with enterprise resource planning (ERP) systems, allowing efficient data exchange and reducing reporting discrepancies. The study underscores the significance of digital transformation in tax compliance and financial reporting. By adopting a technology-driven approach, oil and gas companies can enhance tax governance, reduce operational costs, and improve audit readiness. Future research will focus on refining AI algorithms for enhanced tax prediction, exploring the role of big data in tax analytics, and expanding the framework’s applicability across different energy sectors.

Surface water and groundwater risks associated with unconventional oil and gas development result from potential spills of the large volumes of chemicals stored on-site during drilling and hydraulic fracturing operations, and the return to the surface of significant quantities of saline water produced during oil or gas well production. To better identify and mitigate risks, watershed models and tools are needed to evaluate the dispersion of pollutants in possible spill scenarios. This information may be used to determine the placement of in-stream water-quality monitoring instruments and to develop early-warning systems and emergency plans. A chemical dispersion model has been used to estimate the contaminant signal for in-stream measurements. Spills associated with oil and gas operations were identified within the Susquehanna River Basin Commission’s Remote Water Quality Monitoring Network. The volume of some contaminants was found to be sufficient to affect the water quality of certain drainage areas. The most commonly spilled compounds and expected peak concentrations at monitoring stations were used in laboratory experiments to determine if a signal could be detected and positively identified using standard water-quality monitoring equipment. The results were compared to historical data and baseline observations of water quality parameters, and showed that the chemicals tested do commonly affect water quality parameters. This work is an effort to demonstrate that hydrologic and water quality models may be applied to improve the placement of in-stream water quality monitoring devices. This information may increase the capability of early-warning systems to alert community health and environmental agencies of surface water spills associated with unconventional oil and gas operations.

Continental Shelf Associates, Inc. (CSA) was contracted to conduct a three-year study of the environmental and health related impacts of produced water and sand discharges from oil and gas operations. Data on naturally occurring radioactive materials (NORM), heavy metals, and hydrocarbons in water, sediment, and biota will be collected and evaluated. Health related impacts will be studied through field collections and analyses of commercially- and recreationally-important fish and shellfish tissues. Additionally, information on seafood catch, consumption, and use patterns for the Gulf of Mexico will be gathered and analyzed. The facilities to be studied will include both offshore and coastal facilities in the Gulf of Mexico. Coastal sites will be additionally studied to determine ecological recovery of impacted wetland and open bay areas. The economic impact of existing and proposed effluent federal and state regulations will also be evaluated. This report represents the thirteenth quarterly technical summary for the study ``Environmental and Economic Assessment of Discharges from Gulf of Mexico Region Oil and Gas Operations.`` Activities associated with Tasks 3 through 8 are discussed in this report.

An oil operator is subject to a vast number of conservation orders in the conduct of his oil and gas operations. This article considers the civil liabilities that an operator may be subject to for breach of a conservation order. It suggests that with respect to liability to a third party for breach of a conservation order, an operator may be liable on the basis of a breach of statutory duty, or alternatively, the breach of the conservation order may be considered as evidence of negligence per se. With respect to contractual liability to his lessor or to other contracting parties, this article advises that a violation of a conservation order might constitute a breach of contract.

In 2014, a satellite-based map of regional anomalies of atmospheric methane (CH4) column retrievals singled out the fossil fuel rich San Juan Basin (SJB) as the biggest CH4 regional anomaly (“hot spot”) in the United States. Over a 3-week period in April 2015, we conducted ground and airborne atmospheric measurements to investigate daily wind regimes and CH4 emissions in this region of SW Colorado and NW New Mexico. The SJB, similar to other topographical basins with local sources, experienced elevated surface air pollution under low wind and surface temperature inversion at night and early morning. Survey drives in the basin identified multiple CH4 and ethane (C2H6) sources with distinct C2H6-to-CH4 emission plume ratios for coal bed methane (CBM), natural gas, oil, and coal production operations. Air samples influenced by gas seepage from the Fruitland coal formation outcrop in La Plata County, CO, had enhanced CH4, with no C2-5 light alkane enhancements. In situ fast-response data from seven basin survey flights, all with westerly winds, were used to map and attribute the detected C2H6 and CH4 emission plumes. C2H6-to-CH4 plume enhancement correlation slopes increased from north to south, reflecting the composition of the natural gas and/or CBM extracted in different parts of the basin. Nearly 75% of the total detected CH4 and 85% of the total detected C2H6 hot spot were located in New Mexico. Emissions from CBM and natural gas operations contributed 66% to 75% of the CH4 hot spot. Emissions from oil operations in New Mexico contributed 5% to 6% of the CH4 hot spot and 8% to 14% of the C2H6 hot spot. Seepage from the Fruitland coal outcrop in Colorado contributed at most 8% of the total detected CH4, while gas venting from the San Juan underground coal mine contributed &amp;lt;2%.

Monitoring of microbial populations in oil and gas operations is routinely conducted in order to evaluate the need for and performance of biocides. Operators utilize a variety of methods designed to determine if bacteria and archaea capable of causing corrosion, fouling, or souring are present in the systems before, during, and after control methods are applied. Each monitoring method has strengths and limitations, and an understanding of the strengths and limitations is crucial to deciding the best method for any given system. The most obvious considerations are the accuracy of the test, cost, ease of use, and time required to obtain the results. How comparable results are from a given location or time to another time, and the value of the data for making higher-level decisions also should be considered. In this study, we will share the results obtained from analyzing samples collected from various phases of natural gas and oil production operations. These locations include microbial populations collected from a range of operating temperatures, pressures and salinities as well as those treated with different types of biocides. Four methods, culture based enumeration using bug bottles with indicator media for sulfate-reducing bacteria (SRB) and acid-producing bacteria (APB), rapid bacterial cell enumeration based on an adenosine triphosphate (ATP) quantification assay, epifluorescence microscopy, and molecular analysis of the microbial populations by DNA isolation and sequencing of 16S amplicons were directly compared. The results are discussed in terms of agreement between the methods, difficulty of the approaches, and the relative value of each data set for future use.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29115, “Application of Remote Sensing Imagery and Ancillary Products to Improve Safety and Logistical Efficiency of Arctic Operations,” by Tiffany Carey and Khalid Soofi, SPE, ConocoPhillips, prepared for the 2018 Arctic Technology Conference, Houston, 5–7. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Many forms of remote sensing imagery can be used, along with datasets and the resultant products, to improve the efficiency and safety of upstream oil and gas operations on the North Slope of Alaska, which is characterized by limited road access, seasonally restrictive operations, and stringent environmental regulations. This paper discusses how optical satellite and aerial imagery, high-resolution light detection and ranging (LiDAR) for digital elevation and digital surface models, and synthetic aperture radar (SAR) have enabled one operator to undertake detailed logistical planning of field operations in the Alaskan Arctic by gaining a better understanding of the landscape, environment, and overall regional investigations. Introduction Significant growth in remote sensing systems and techniques has enabled advanced desktop studies and technical investigations, particularly in remote areas such as the Alaskan Arctic. Arctic regions are, by nature, highly inaccessible and consequently problematic to investigate for the purposes of logistical planning of field operations. The North Slope, covering approximately 100,000 acres of northern Alaska and bounded on the north coast by the Chukchi and Beaufort Seas, exemplifies these qualities. Less than 1% of this region is covered by gravel road systems. North Slope oil fields are concentrated in a very small portion of this area. Extensive regulation governs both ground and air access to protect and preserve the environment and wildlife in the region, and to respect the cultural resources and Inupiat lifestyle of the 10,000 residents spread among eight villages. Meandering and braided fluvial systems and stationary waterbodies vary seasonally in size, volume, and state. The environment has been sculpted by significant fluvial systems that drain from the Brooks Range into the Beaufort Sea. High-energy river drainages with steep-cut banks and expansive gravel bars leave abandoned channels and oxbows across the dynamic landscape. The tundra is marked by numerous waterbodies with a wide range of depths. Small ponds and lakes often have the most significant depth profiles. Light or deep snow levels; thin, thick, or grounded ice conditions on lakes; and overflow conditions on the rivers can plague preparation and execution of North Slope winter operations. Because of the substantial portion of the North Slope that is inaccessible by road, winter tundra access for exploration operations is the only option for most of the region. North Slope winter-season length is established on the ability of the tundra to reach predetermined frost depths and snow thickness, which must be achieved to commence work. The formal annual opening and closing of the tundra is governed by federal and state agencies. All off-road winter operations must adhere to these regulations. The winter season has varied from 97 to 145 total days during the past 15 years. On top of the short winter work season, the Arctic is also known for its winter darkness. More than 50 days of the winter season have no daylight, which dramatically affects health, safety, and environment (HSE) regulations for working in the North. However, given the 24 hours of darkness, International Association of Oil and Gas Producers standards and operator HSE regulations allow for 24-hour operations.

Proceedings of the 1989 Academy of Marketing Science (AMS) Annual Conference

Inspection, repair, and maintenance operations are of crucial importance for the safety and survival of marine renewable energy devices. Current ROV manipulator technology used for subsea operations in offshore oil and gas industry is not adequate for offshore renewables. Target devices for inspection and monitoring operations in oil and gas are close to static, unlike their marine energy counterparts which are in motion due to a highly dynamic environment in which they operate. In this paper we describe motion analysis methods for marine energy devices implemented on the OC3-Hywind floating wind turbine in order to understand the conditions in which inspection and intervention operations are to be performed. Additionally, we present experiments carried out on a laboratory rig which is able to replicate the motion of the OC3-Hywind floating platform, and which will be used in future research on control systems for automated visual inspection and intervention using ROV manipulators.

Who wants North Sea CCS, and why? Assessing differences in opinion between oil and gas industry respondents and wider energy and environmental stakeholders