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1
Sherik, Abdelmounam M., and Arnold L. Lewis. "Corrosion Inhibition of Sales Gas Transmission Pipelines." Materials Performance 52, no. 9 (2013): 52–56. https://doi.org/10.5006/mp2013_52_9-52.
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Weight loss methodology was used to study the corrosion-inhibiting effects of 14 inhibitors on carbon steel in a simulated sales gas environment. Two inhibitors passed these tests, showing a corrosion inhibition effectiveness off 90% and preventing pitting attack.
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Moring, Frederick. "The pipelines' packaging proposal: Making sales gas more competitive." Natural Gas 7, no. 5 (2008): 22–23. http://dx.doi.org/10.1002/gas.3410070509.
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Holmes, Leanne, Sally L. Mander, and Brian S. Fisher. "COMPETITIVE ACCESS TO AUSTRALIAN GAS MARKETS—IMPLICATIONS FOR EXPLORATION AND DEVELOPMENT." APPEA Journal 34, no. 1 (1994): 862. http://dx.doi.org/10.1071/aj93066.
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Access to profitable markets is one of the key factors influencing the incentives to explore for and develop gas reserves. Recent reviews of gas markets in Australia and attempts by gas buyers and sellers to negotiate interstate gas sales have focused attention on the need to remove barriers to competition and trade. Possible barriers include policies pursued by some state governments that restrict interstate sales of gas and limit its use in some markets. Structural features of gas markets in Australia, including monopoly control over pipeline access, are also potential barriers to new gas discoveries competing for markets. A number of recent developments and proposals could influence access to gas markets in Australia. The most significant are moves to establish a framework for open access to interstate pipelines. These developments could encourage further gas exploration and development, by reducing uncertainty about market access and giving gas producers and large consumers the opportunity to directly negotiate sales on their own negotiated terms.
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Priddle, R. "Impact of Canadian Regulatory Changes on Cross-Border Trade." Energy Exploration & Exploitation 5, no. 1 (1987): 65–78. http://dx.doi.org/10.1177/014459878700500106.
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In the year following oil deregulation Canada's crude oil productive capacity grew by 5%, but production was unchanged due to a lack of pipeline capacity, the effects of prorationing and a lack of price flexibility. While Canadian oil demand remained stable, exports of crude oil increased by one-third and imports by one-half. Export prices followed world trends with light crude oil export prices declining from $C 40/bl to $C 15 in July 1986. Natural gas exports were down by 17% in the first nine months of the 1986 contract year. This period coincides with the implementation of the Agreement on Natural Gas Markets and Prices, but was also a period marked by declines in US gas prices, declining US gas demand, and significant changes in US gas industry regulation. Prices for gas exports by licence have been renegotiated and some short-term interruptible sales have been made. Export prices approached those for interprovincial sales, which typically offered a better load factor. Licence holders have been able to average export prices over all sales under a licence to satisfy the minimum export price requirement in relation to the domestic reference price. As a result, since the Agreement of 31 October 1985, all renegotiated prices for exports of gas by licence have been approved. The factors having the most impact on gas exports by licence appear to be the 6% decline in US gas demand, limitations on pipeline access during the period of transition in US pipeline regulation, priority given by US pipelines to managing lower-48 take-or-pay obligations, and the changing role of US pipelines to being transporters rather than merchants of gas to the detriment of some Canadian gas export contracts. Exports by licence were at a level of 42% of authorized volumes for most of 1986. Volume authorizations were therefore, not an impediment to exports by licence. There was no volume restriction for short-term exports by order. Gas exports by short-term interruptible order faced US pipeline access restrictions but were affected by the domestic reference price floor. Short-term interruptible exports grew rapidly after the Agreement, peaking in January 1986 and then declined as US competitive prices fell below comparable Canadian domestic prices. Short-term interruptible exports have accounted for only 3% of total exports in the first nine months of the current contract year. Canada's disappointing 1985–6 gas export performance was attributable to weak US gas markets, changing US market structures, and delayed US regulatory change. Although there has been some impact on short-term interruptible sales, the overall decline in gas exports was not significantly relatable to Canadian gas export regulation.
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Al Wahedi, Faisal Saleh, Mohammed Hameed Saleh, and Zin Eddine Dadach. "Black Powder in Sales Gas Pipelines: Sources and Technical Recommendations." World Journal of Engineering and Technology 08, no. 01 (2020): 60–73. http://dx.doi.org/10.4236/wjet.2020.81007.
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Chernova, O. T., V. Ya Grudz, Ya V. Grudz, and M. M. Yakumiv. "OPTIMIZATION OF CONTROL OF OPERATING MODES OF GAS TRANSPORT SYSTEM USING UGS." METHODS AND DEVICES OF QUALITY CONTROL, no. 2(47) (December 29, 2021): 72–82. http://dx.doi.org/10.31471/1993-9981-2021-2(47)-72-82.
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The Soyuz, Urengoy-Pomary-Uzhhorod and Progress gas pipeline systems form the basis of the trans-Ukrainian trans-Ukrainian pipeline system. The complex gas transmission system contains a number of gas pipelines forming a linear part and several compressor stations. The amount of capacity of pipelines depends on the number and characteristics of compressor stations. Reliability of work, regulation of transit flows and ensuring uninterrupted gas supply is carried out with the help of underground gas storage facilities, which are an integral part of the GTS of Ukraine. The use of underground storage facilities is considered to be one of the most efficient ways of gas supply, improving the quality of gas supplies to consumers and the efficiency of gas sales within the country and abroad. With the use of storage, you can reduce the unevenness of seasonal consumption and ensure security of supply. The use of underground storage facilities is an integral part, as during the year the maximum daily gas extraction exceeds the minimum more than three times, and the supply of gas through the main gas pipelines is almost constant. The maximum storage capacity cannot be represented as the sum of the absolutely free flow rates of all production wells. This is explained by the fact that the productivity of the underground gas storage during the extraction period is affected by the hydraulic resistance of the gas collection system to the underground storage and its technical condition, which is determined by the coefficient of hydraulic efficiency of loops and collectors.
 Studies show that the location of gas storages in the system has an impact on the amount of energy consumption. Therefore, the strategy of rational use of underground gas storage facilities in pipeline transport (in terms of minimizing energy consumption) is based on the study of the impact of their location in the gas transmission system. The principle of energy efficiency of the use of underground gas storage facilities for long-distance transportation (in order to equalize the unevenness of gas consumption) is based on the sequence: the most remote UGS should be used first. These are the objects that are located at the end points of the GTS route and whose location corresponds to the proximity to consumers.
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Johny, Soedarsono, Wijaya Arie, Aditiyawarman Taufik, et al. "Development of risk-based inspection of 28-years-old subsea sales gas pipelines to support the energy demand." Eastern-European Journal of Enterprise Technologies 2, no. 3(122) (2023): 17–27. https://doi.org/10.15587/1729-4061.2023.277256.
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In the oil and gas industry, maintaining the integrity of production equipment is critical to ensuring the industry’s sustainability. Failure to maintain the integrity of production equipment can result in financial losses for the business. The management of production equipment nearing the end of its design life faces an increasing cost of Inspection, Maintenance, and Repair (IMR). As a result, a strategy to improve the efficiency of IMR is essential. Recent IMR management practices include predictive Risk-Based Inspection (RBI), which is more efficient than Time-Based Inspection (TBI). The research intends to evaluate the 28-year-old subsea sales gas pipeline using API 581 standard quantitative methodology by utilizing the Inline Inspection (ILI). Specifically, the study focuses on measuring the Probability and Consequence Failure of inspected pipelines. The inspection interval is determined based on the minimum allowable thickness. The risk calculation indicates that 12 pipeline segments are at a medium risk level (3 segments, 1D and 1E, and 2C). The remaining nine segments remain at lower risk (1C). Based on the result, segment nine is accepted as the highest PoF value of 1.04E-4 failures per year due to high depletion values due to the higher CoF value at the leak location. The calculation of the inspection interval indicates that the forthcoming Inspection will be due 20 years post the previous assessment. Another method using the Estimated Repair Factor (ERF) thickness limit approach produces the same results. However, assessment using ASME B31.8S provides different results of 10 years intervals when using the same ILI inspection method. This work can be used as a standard guideline to assess the risk of pipelines over a decade in service
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Febaide, I. C., and G. O. Uzedhe. "Leveraging on low-cost devices for wireless data acquisition in remote pipeline networks." Nigerian Journal of Technological Development 20, no. 3 (2023): 154–62. http://dx.doi.org/10.4314/njtd.v20i3.1587.
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Pipeline infrastructures are the most used means of transporting oil and gas from extraction point to production and sales point. These pipelines are exposed to various attacks either by natural occurrences, indiscriminate human activities around pipelines or direct criminal sabotage, and therefore require constant monitoring. The use of low-cost wireless devices for pipeline data acquisition as it applies to remote and difficult terrain is presented. Different methods and models have been suggested in literature with several existing systems such as SCADA, DCS, and satellite spectral imaging currently in use for pipeline operations. Among the challenges here is the need for lower operational costs, even at reduced response time demand. The Wireless Data Acquisition System (WDAS) presented simulates a pipeline system in a testbed in which a petroleum product is caused to flow and its parameters read, processed as data and wirelessly transmitted, through a wireless sensor network, to a remote device for monitoring. Results indicate a very short response time of about 3.0sec in the simulation at a percentage accuracy of 0.07% over 1km. It also shows that low-cost wireless sensor networking can provide a cost-effective means for pipeline infrastructure management and should be explored.
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Soedarsono, Johny, Arie Wijaya, Taufik Aditiyawarman, et al. "Development of risk-based inspection of 28-years-old subsea sales gas pipelines to support the energy demand." Eastern-European Journal of Enterprise Technologies 2, no. 3 (122) (2023): 17–27. http://dx.doi.org/10.15587/1729-4061.2023.277256.
Full textAbstract:
In the oil and gas industry, maintaining the integrity of production equipment is critical to ensuring the industry’s sustainability. Failure to maintain the integrity of production equipment can result in financial losses for the business. The management of production equipment nearing the end of its design life faces an increasing cost of Inspection, Maintenance, and Repair (IMR). As a result, a strategy to improve the efficiency of IMR is essential. Recent IMR management practices include predictive Risk-Based Inspection (RBI), which is more efficient than Time-Based Inspection (TBI). The research intends to evaluate the 28-year-old subsea sales gas pipeline using API 581 standard quantitative methodology by utilizing the Inline Inspection (ILI). Specifically, the study focuses on measuring the Probability and Consequence Failure of inspected pipelines. The inspection interval is determined based on the minimum allowable thickness. The risk calculation indicates that 12 pipeline segments are at a medium risk level (3 segments, 1D and 1E, and 2C). The remaining nine segments remain at lower risk (1C). Based on the result, segment nine is accepted as the highest PoF value of 1.04E-4 failures per year due to high depletion values due to the higher CoF value at the leak location. The calculation of the inspection interval indicates that the forthcoming Inspection will be due 20 years post the previous assessment. Another method using the Estimated Repair Factor (ERF) thickness limit approach produces the same results. However, assessment using ASME B31.8S provides different results of 10 years intervals when using the same ILI inspection method. This work can be used as a standard guideline to assess the risk of pipelines over a decade in service
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McDiarmid, A. J., P. T. Bingaman, S. T. Bingham, et al. "JOHN BROOKES GAS FIELD DEVELOPMENT." APPEA Journal 45, no. 1 (2005): 13. http://dx.doi.org/10.1071/aj04001.
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The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.
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Howard, D. "UNDERGROUND GAS STORAGE-LEGAL ANT REGULATORY REQUIREMENTS IN AUSTRALIA." APPEA Journal 39, no. 1 (1999): 663. http://dx.doi.org/10.1071/aj98045.
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The storage of gas in underground naturally occurring reservoirs takes place in a variety of forms and for a variety of reasons. In many jurisdictions within Australia, the regulatory framework to deal properly with underground gas storage requires attention and, in some cases, significant refinement. Underground natural reservoir storage of gas in Australia is an option which is being increasingly investigated as fields close to infrastructure (such as pipelines and processing plants) become depleted and alternative uses are sought for those depleted reservoirs. In addition, gas storage may give flexibility to spot gas sales and other commercial operations, and facilitate greater market sophistication. Accordingly, it is important for the industry in Australia to understand the legal implications and their impact on this type of storage.
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Cowie, MichaelIan, and AM El-Sherik. "Naturally occurring radioactive material and naturally occurring mercury assessment of black powder in sales gas pipelines." Radiation Protection and Environment 42, no. 1 (2019): 34. http://dx.doi.org/10.4103/rpe.rpe_69_18.
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Ashwarya, Sujata. "Post-2003 Iran–Iraq Cooperation in the Oil and Gas Sector: Initiatives, Challenges, and Future Scenarios." Contemporary Review of the Middle East 4, no. 1 (2017): 84–118. http://dx.doi.org/10.1177/2347798916681349.
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Iran–Iraq cooperation in the oil and gas sector took shape after the 2003 war as relations between the two countries improved with the assumption of power by a Shia-led government in Baghdad. The two Persian Gulf neighbors recognize the importance of joint or unitized development of cross-border oil fields and have taken preliminary initiatives to that end. Inter-state pipelines for energy export and import are binding them into a tight economic embrace, and combined backing for high oil prices as well as mutual support for raising production quota in the Organization of the Petroleum Exporting Countries (OPEC) speak of their similar imperatives for high revenue. However, Iran and Iraq continue to face challenges to their collaborative ventures, which stem from their historical rivalry over oil production and sales, persisting Iraqi suspicion of Iranian domination, absence of a hydrocarbon law in Iraq, and Iraq’s energy agreements with Iran that add to regional tensions with Baghdad’s Sunni neighbors. The road ahead is likely to see dynamic cooperation in areas that are less contentious, such as building of oil and gas pipelines, whereas the prickly issue of unitization of shared fields would take a backseat.
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Grivach, A. I. "SITUATION IN THE RUSSIAN GAS INDUSTRY IN 2022–2023." Geoeconomics of Energetics, no. 1 (April 29, 2024): 6–17. http://dx.doi.org/10.48137/26870703_2024_25_1_6.
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The article examines the state of the Russian gas industry in the period from the beginning of sanctions (2022) to the end of 2023. The author assesses the period of adaptation to the new market conditions. It is the author’s opinion that the risks in the gas sector last year turned out to be more extensive than in the oil sector. The reduction in gas production is primarily due to the reduction in natural gas purchases by European consumers. Exports to non-CIS countries have decreased over the past two years. Over the past two years, there has been a decline in gas production levels, with the most noticeable drawdowns being seen at Gazprom. This is not only due to the decrease in exports, but also due to the increase in production by other companies (NOVATEK and Rosneft).Russia currently supplies gas via pipelines to Europe, Turkey and the People’s Republic of China. In the European direction, supplies are made through the Ukrainian GTS and the Turkish Stream pipeline. Gas supplies to China have the greatest potential; during the period under review, they increased one and a half times. There is a planned increase in supplies through the Power of Siberia gas pipeline.The author also describes the complicated dynamics in the domestic gas market. The program of social gasification, which continues to develop, is mentioned separately.According to the author, the government will have to develop measures to support the industry in order to fulfill its social obligations and develop new projects that will ensure diversification of sales markets and substitution of partners from unfriendly jurisdictions in the coming years.
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Pylypiv, L. D., and І. І. Maslanych. "Research of pressure influence in the gas supply system on the energy consuption level of gas devices." JOURNAL OF HYDROCARBON POWER ENGINEERING 6, no. 2 (2019): 56–63. http://dx.doi.org/10.31471/2311-1399-2019-2(12)-56-63.
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There are investigated the influence of operating pressures in the gas supply system on the level of such energy indicators as efficiency, gas flow and gas overrun by gas equipment in residential buildings. There is established a relationship between the values of operating pressures in the gas supply system and the gas consumption level of household appliances. The causes of insufficient pressure in the gas networks of settlements are analyzed in the article. There is also developed an algorithm for calculating the change in the efficiency of gas appliances depending on the operational parameters of the gas network. It has been found that the most efficient operation of gas appliances is observed at an overpressure at the inlet of gas appliances of about 1200 Pa.To ensure the required quality of natural gas combustion among consumers and minimize gas consumption there are justified the following measures in the article: coordinating a domestic regulatory framework for assessing the quality of natural gas with international norms and standards; improving the preparation of gas coming from local wells before supplying it to gas distribution networks; auditing low pressure gas pipelines and reconstructing areas affected by corrosion; ensuring standard gas pressure in the network for the normal operation of domestic gas appliances; stating quality indicators of natural gas combustion by gas sales organizations.
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Chernova, Oksana, Oleg Vytyaz, Rostislav Martyniuk, and Irina Fedorovych. "Rational methods of operation of underground gas storages and mitigation of energy losses." Nafta-Gaz 78, no. 3 (2022): 187–96. http://dx.doi.org/10.18668/ng.2022.03.03.
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The fuel and energy complex of Ukraine, like most developed countries of the world, is a complex system of material production incorporating a set of many subsystems that cover the extraction, conversion, distribution, storage and consumption of energy. Ukraine's gas transportation system has an extremely complex system, which consists of gas pipelines of various purposes and capacities, compressor stations, compressor shops, gas distribution stations and underground gas storage facilities. Compressor stations, allied with underground storage, ensure full pipeline use, reliability of work, modes of regulation of transit flows and maintenance of uninterrupted supply. Their co-employment is considered one of the most effective methods of increasing reserves for reliable gas supply and efficiency of gas sales in the country and abroad. The use of storage reduces the unevenness of seasonal consumption and enables timely delivery. This is justified by the fact that during the year, gas production is uneven, as is consumption. In winter, the amount of gas extracted does not provide the amount of gas consumed. Therefore, underground storage facilities are an integral part of the gas transmission system, which must function efficiently. The Ukrainian gas transportation system is part of the European energy system, despite the fact that the country itself is not yet a member of the EU. To research the issues of improving the efficiency of the system and underground storage facilities, it is necessary to analyse the parameters of their work and study the problems of reducing costs during storage and transportation. In the work on the basis of the analysis of the cyclic operation of the Dashavsky underground storage, the energy approach to an estimation of losses of gas at storage is offered. This will streamline and specify the general ideas and the level of irreversible losses of natural gas as an energy source and will increase the efficiency of operation of the underground gas storage as a whole. At the same time, taking into account the energy characteristics of natural gas when forecasting its losses during storage will significantly affect the organisation and optimisation of maintenance of storage equipment and, in particular, the compressor station.
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Wright, Blake. "Working To Solve the Permian Gas Conundrum." Journal of Petroleum Technology 76, no. 06 (2024): 32–37. http://dx.doi.org/10.2118/0624-0032-jpt.
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Reflecting on oilfield history as a whole, it wasn’t all that long ago that natural gas was treated more like a nuisance than a commodity, either an undesirable byproduct of an oil discovery or a letdown when it was encountered in a well instead of the targeted black gold. It can complicate things when an operator is drilling for oil, especially during periods like now when crude prices are robust, but gas prices aren’t. Additionally, when oil is discovered, it often comes with associated natural gas. When producers turn the taps to get that oil into sales lines, the gas can be problematic if the limited takeaway capacity for transporting it is already stretched. This is the current situation for many operators in the prolific Permian Basin of west Texas and south-east New Mexico. Infrastructure constraints to ship natural gas out of the Permian combined with high storage levels due to a relatively mild winter are wreaking natural gas pricing in the region. Natural gas prices at the WAHA hub located near Fort Stockton, Texas, were below zero—negative $4.60/MMBtu as recently early May. Not only did that mean that produced gas in the region was basically free, but the negative price also meant producers trying to move gas out of the region would have to pay someone extra to do it. That’s not good business. Of course, anyone looking to chase that offer would find no pipeline capacity to move the product. The US Energy Information Administration (EIA) said in December 2023 that production of associated natural gas has nearly tripled since 2018 in the three top-producing tight oil plays in the Permian region. Associated natural gas from the Wolfcamp, Spraberry, and Bone Spring plays averaged a combined 13.7 Bcf/D in the first 7 months of 2023, up from an average of 4.7 Bcf/D in 2018, according to data from Enverus. Associated natural gas production has grown due to increases in both crude oil production and the volume of natural gas per barrel of oil that a well produces, the gas/oil ratio, among the oil wells in these three plays. The cavalry is on the horizon, however. A handful of high-capacity Permian natural gas export projects are moving through various stages of development and aim be operational over the next few years. First up is the giant Matterhorn Express pipeline, which will move gas from west Texas to Katy, Texas (just west of Houston) and connect with other pipelines. The project, led by WhiteWater Midstream, EnLink Midstream, Devon Energy, and MPLX, is roughly 80% complete and should come online in the second half of this year. Energy Transfer’s Warrior pipeline is loading up on transport commitments and will move gas from the Permian to the Gulf Coast. This system is on track for a potential late-2024 final investment decision (FID).
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Winthrop, Robert. "Conflicting Perceptions: Tribal and Regulatory Views of Nature, Risk, and Change." Practicing Anthropology 16, no. 3 (1994): 25–28. http://dx.doi.org/10.17730/praa.16.3.221356051617g2r2.
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As an applied anthropologist, I work on the twin tasks of impact assessment and conflict resolution as these are necessitated by proposals for major construction projects or natural resource development. I run a consulting firm which works with American Indian tribes, federal agencies, and corporations in the Pacific Northwest regarding the design, siting, or permitting of major and often controversial facilities or resource uses: hydroelectric projects, natural gas pipelines, timber sales, nuclear waste storage facilities, and the like. In conjunction with tribal colleagues, I participate in assessing the cultural implications of proposed environmental change. When a conflict exists between tribal cultural practices or values and a proposed project, as is common, we determine whether there are any changes in the design or siting of the project through which both the values of the tribe and the technical/economic requirements of the developer can be accommodated.
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Linares, Elisabetta. "Issues in the calculation of antitrust damages in the energy industry." ECONOMICS AND POLICY OF ENERGY AND THE ENVIRONMENT, no. 3 (December 2012): 155–74. http://dx.doi.org/10.3280/efe2012-003010.
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In recent years, the "private enforcement" of antitrust law, through the attempt by private parties (usually harmed competitors or consumers) to recover damages in court, has been increasingly gaining attention in Europe. This paper focuses on two particular regulated network industries (electricity and gas). The purpose of this essay is, first, to describe the types of antitrust cases that could arise in the energy industry and, second, to outline the issues that a forensic economist would face in calculating damages to competitors or other parties in these cases. The identified anti-competitive practices range from the delay or the outright denial of access to major gas transportation pipelines (or the refusal to expand their capacity), unfair tariffs for the use of gas transportation networks and capacity hoarding at regasification terminals or in other gas import infrastructure, to the delayed provision of reliable information needed for customer switching and/or to allow a new entrant to plan its electricity and gas purchases and thus minimize imbalance charges. These practices might entail actual monetary loss (damnum emergens) due, for instance, to; higher energy costs for final consumers; sunk costs incurred by competitors to start import or sales activities; noncost- reflective tariffs for access to gas import or transportation infrastructure; excessive imbalance charges and transmission fees; high costs sustained by traders to purchase electricity or gas for resale. Moreover, they may entail lost profits and foregone cash flows (lucrum cessans) due, for instance, to: definitive loss of customers; inability to serve or invoice energy consumers in a given period; lack of access to entire segments of the electricity or gas markets.
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Stefanov, Miroslav. "Features of Compressed Natural Gas Physical Distribution: A Bulgarian Case Study." Logistics 2, no. 3 (2018): 17. http://dx.doi.org/10.3390/logistics2030017.
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Building a competitive and resource-efficient transportation system involves the achievement of a number of ambitious goals. Two of the main instruments in the European transportation policy in this field address the significant reduction of GHG emissions and oil dependency in transportation. Alternative fuels and compressed natural gas (CNG) in particular have huge potential for achieving these goals. The main problem that limits its wide utilization is related to the insufficient number of CNG refueling stations, especially along highways and routes from the core TEN-T network where no gas pipelines are available. Therefore, the aim of this research is to study a possible solution to building daughter CNG refueling stations which can be used as basis for formulating some recommendations for their accelerated construction along TEN-T core network as well as providing some initial knowledge to be used later for more comprehensive research. The research is based on the case-study method, which allows the presentation of the described best practice. The process of data collection is based on semi-structured interviews, study of normative documents, observation of daily sales and direct observations which were processed with the help of qualitative and quantitative methods for time series analysis—trend and seasonal component as well as descriptive statistics tools. Scientific literature and research as well as secondary data provided by international institutions are also used.
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Moring, Frederick. "Market-based pricing of pipeline sales to LDCs." Natural Gas 6, no. 7 (2008): 9–10. http://dx.doi.org/10.1002/gas.3410060704.
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VA, R. HARITHA. "A Study of Financial Planning and Forecasting With Reference to Indian Oil Corporation Limited." INTERANTIONAL JOURNAL OF SCIENTIFIC RESEARCH IN ENGINEERING AND MANAGEMENT 08, no. 04 (2024): 1–5. http://dx.doi.org/10.55041/ijsrem31376.
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Financial planning is a ceaseless procedure of guiding and designating financial assets to meet strategic goals and targets. The yield from financial planning appears as budgets. The most generally utilized type of budgets is Pro Forma or Budgeted Financial Statements. The establishment for Budgeted Financial Statements is Detail Budgets. Detail Budgets incorporate sales conjectures, production figures, and different gauges in help of the Financial Plan. On the whole, these budgets are alluded to as the Master Budget. We can likewise separate financial planning into planning for tasks and planning for financing. Working individuals centre around sales and production while financial planners are keen on the best way to back the tasks. In this manner, we can have an Operating Plan and a Financial Plan. Be that as it may, to keep things basic and to ensure we incorporate the procedure completely, we will consider financial planning as one single procedure that includes the two tasks and financing. Financial Planning begins at the highest point of the organization with strategic planning. Since strategic choices have financial ramifications, you should begin your planning procedure inside the strategic planning process. Inability to interface and associate planning with strategic planning can result in budgets that are "dead on landing." Strategic planning is a formal procedure for setting up goals and targets as time goes on. Strategic planning includes building up a statement of purpose that catches why the organization exists and plans for how the organization will flourish later on. Strategic targets and relating goals are created dependent on an exhaustive evaluation of the organization and the outer condition. At last, strategic plans are executed by building up an Operating or Action Plan. Inside this Operating Plan, we will incorporate a total arrangement of financial plans or budgets. Indian Oil Corporation Limited (IOCL), also known as Indian Oil, is an Indian government-owned oil and gas explorer and producer, a significant player in the country's energy sector. Headquartered in New Delhi, it is the largest commercial oil company in the country, with a significant presence across the value chain of the petroleum industry, including refining, pipeline transportation, and marketing of petroleum products. IOCL's Chennai operations are a vital part of its extensive network, contributing significantly to its overall performance. IOCL's operations in Chennai also include a sprawling network of pipelines. These pipelines are crucial for the efficient transportation of crude oil to the refinery and the distribution of refined petroleum products to different parts of the region. This network ensures a consistent and reliable supply of fuel, which is vital for the economic development of the area. The retail network of IOCL in Chennai and the surrounding region is extensive, with numerous petrol and diesel stations. These retail outlets not only provide fuel but also offer a range of services and products to consumers. IOCL's focus on customer satisfaction and service quality has made it a preferred brand among consumers. Moreover, IOCL has been at the forefront of adopting innovative technologies and sustainable practices in its operations. The company has undertaken several initiatives in the areas of energy conservation, emission reduction, and waste management to minimize its environmental footprint. These efforts underscore IOCL's commitment to environmental sustainability and its role in promoting green energy alternatives. Indian Oil Corporation Limited's Chennai operations are integral to its strategic objectives and overall success. Through its refinery, pipeline network, and retail outlets, IOCL not only contributes significantly to India's energy security but also plays a pivotal role in the economic development of the region. With a focus on innovation, sustainability, and customer satisfaction, IOCL is poised to continue its leadership role in the Indian petroleum industry. I have chosen Indian Oil Corporation Limited (IOCL) for a project offers a unique opportunity to engage with one of India's leading public sector enterprises, playing a pivotal role in the country's energy sector. IOCL's diverse operations, spanning across refining, pipeline transportation, and marketing of petroleum products, provide a rich learning ground for interns. The exposure to a vast spectrum of operations allows for an in-depth understanding of the energy industry's complexities, offering invaluable insights into both the technical and business aspects of the field. The mentorship and training provided by industry veterans at IOCL are unparalleled, equipping interns with the skills and knowledge necessary to thrive in their future careers. Additionally, the organization's emphasis on corporate social responsibility and community engagement initiatives offers a broader perspective on the impact of business operations on society and the environment. In IOCL is not just a step in one's career journey but a leap into a world of opportunities for growth, learning, and making a meaningful contribution.
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Williams, Okpebenyo, Chuzzy Onoh Chizoba, Onwubuya Cornell Chijioke, and Igwe Anthony. "Revisiting the resource curse in Nigeria: the case of Niger delta." Kampala International University Interdisciplinary Journal of Humanities and Social Sciences 4, no. 1 (2023): 259–76. http://dx.doi.org/10.59568/kijhus-2023-4-1-16.
Full textAbstract:
Natural resources endowment is a blessing to the endowed states due to their catalytic development-driving potential. The exploitation of the endowment should result in rapid socio-economic development. However, for most developing states, the blessing of these natural resources strangely tends to turn disadvantageous; a phenomenon that has been distinctly identified in the literature as ‘the resource curse. This paper examines that phenomenon, using Nigeria Niger Delta as a case study given the serious environmental, political and socio-economic challenges occasioned by the country’s exploitation of its oil and gas endowment. The paper further explores efforts made to reverse the trend of the phenomenon in Nigeria and also what could be the most effective means of containing the said problems in light of their implications for the future of the country and its people. The study recommended that that there is a well-planned and coordinated program for socio-infrastructural development across the region. Government should provide the grounds for both the oil companies and the host oil communities to cooperate with each other and ensure compliance of the MOUs signed by the oil companies and the host communities. The amnesty program initiated by late President Umaru Musa Yar’Adua should be effectively implemented to avoid the resurgence of militancy and other forms of conflict. Government and the oil companies should guarantee the indigenes that they are a part of the business of crude oil exploration and production in the communities, this will help reduce or possibly stop the issue of regular vandalization of oil pipelines and other facilities of the oil exploration companies. There should be equitable sharing of revenue from the sales of crude oil, particularly by the Federal Government.
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Pitt, G. M., L. E. Kuryiowicz, and IP F. Campbell. "EAST SPAR FIELD—FROM DISCOVERY TO SALES." APPEA Journal 36, no. 1 (1996): 30. http://dx.doi.org/10.1071/aj95002.
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The East Spar field is located 40 km west of Barrow Island on the North West Shelf, offshore WA, and contains 23.6 G.m3 (834 Bscf) of proven and probable wet gas in-place in the Early Cretaceous Barrow Group. The trap is structural, but with negligible time closure.At the time of the discovery and early appraisal of East Spar in late 1993, a rapid deregulation of the gas market was taking place. In combination with the concept of a gas pipeline to the central WA Goldfields region, a marketing 'window of opportunity' was created for the East Spar field, if the development could be crystallised in the available period of 9 months. This required appraisal drilling, geotechnical studies, reservoir engineering and facilities engineering to be advanced on parallel fronts, with close co-ordination and communication be tween all disciplines.The concept of an alliance between the East Spar Joint Venture and the engineering/construction contractors was identified as a way of retaining flexibility to alter the development concept during this period, and provide other benefits during the subsequent construction phase. This alliance was ultimately formed to include representatives from WMC (on behalf of the East Spar Joint Venture (ESJV)), Kvaerner-R J Brown and dough Engineering.The East Spar facilities will comprise a subsea completion and gathering system, with all produced fluids being piped to processing facilities on Varanus Island. The treated gas will then be transported to the mainland via the existing sales gas pipeline to the onshore Dampier to Bunbury pipeline, which connects with the Goldfields Gas pipeline. The condensate will be exported from Varanus Island by tanker. First sales are expected in October 1996
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Rivera, Nestor, Nestor Saul Meza, Jeoung Soo Kim, et al. "Static and Dynamic Uncertainty Management for Probabilistic Production Forecast in Chuchupa Field, Colombia." SPE Reservoir Evaluation & Engineering 10, no. 04 (2007): 433–39. http://dx.doi.org/10.2118/100526-pa.
Full textAbstract:
Summary Structural, stratigraphic, and petrophysical uncertainties result in a wide range of geologic interpretations. For fields with a long production and pressure history, 3D dynamic simulations have been very useful in providing feedback to geologic modelers, which results in improved static models. For this study, we developed an integrated static and dynamic workflow to create a range of probabilistic simulation models to forecast dry-gas production under several production scenarios in the Chuchupa field. We selected eight geologic interpretations, representing the range of original gas in place (OGIP) and reservoir geometries determined in the static modeling, to perform dynamic history matches. The OGIP range of the models with very good history matches corresponds closely to the P10 to P90 OGIP range calculated from static modeling. In addition, we calibrated the various models with historical bottomhole and tubinghead flowing pressures and coupled the reservoir model with a network consisting of surface lines and equipment, pipelines from two platforms to the onshore sale-point station, and multistage compression to 1,215 psia. The set of probabilistic models is currently used to evaluate various production and market scenarios. Introduction Chuchupa field has produced 1.9 Tscf of dry gas, or approximately 40% of the OGIP. At the time of this study, three new horizontal wells were being planned, and new gas-sales agreements were being considered. Recent seismic reinterpretation, a new stratigraphic study, and a revision of the petrophysical model resulted in new probabilistic static models for the field. While these static models were being built, a parallel numerical-simulation study was conducted to determine the range of OGIP values that could be successfully history matched. Nine numerical reservoir models were generated by applying pore-volume multipliers to the prior-generation reservoir model, yielding a range of OGIP from 3.8 to 6.6 Tscf. We attempted to history match each of these nine models by using an optimization routine to adjust aquifer support, vertical transmissibility across a potential seal, and rock compressibility. The optimization routine proved to be a very useful and efficient tool to attain good-quality history matches in short periods of time. Good matches were obtained for models with OGIP ranging from 4.3 to 5.8 Tscf. On the basis of this information, the geologic modelers revised petrophysical parameters and generated 27 static models, encompassing three structural interpretations, three porosity distributions, and three possible positions of the gas/water contact (GWC). From experimental design, we obtained P10, P50, and P90values of 4.1, 4.7, and 5.3 Tscf, respectively. We scaled up and built reservoir-simulation models on eight of these models and performed history matches. The observed parameters to match were static well pressures and the absence of water production. Six of the eight models were satisfactorily history matched, with reasonable adjustments to aquifer strength, vertical transmissibility, and rock compressibility. The successfully history-matched models are within the P10 to P90 OGIP range. We selected three models to forecast future gas production. These models match the P10, P50, and P90 OGIP values determined in the probabilistic static model and combine the low, mid, and high structures, porosity and Swi distributions, and the range of GWC positions.
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Peng, Shan Bi, En Bin Liu, Xiao Chun Du, and Rong Lin Hong. "The Dynamic Simulation of a Long Distance Natural Gas Pipeline." Applied Mechanics and Materials 268-270 (December 2012): 1244–48. http://dx.doi.org/10.4028/www.scientific.net/amm.268-270.1244.
Full textAbstract:
With the growth of the natural gas market, the long distance natural gas pipeline system is getting more and more important in nowadays. As a united and enclosed hydraulic system, the operation conditions of the whole line will be changed by the influence of the condition change in one station. On the one hand, the condition change made people analyze operation scheme more difficult, on the other hand, pipeline system operating conditions directly affect the relationship between the production and the sales of natural gas. Therefore, the operation of the gas pipeline must be optimized, which brings huge economic and social benefits. This paper constructed a simulation model of a long distance natural gas pipeline by TG.net, and then analyzed the change of the operating condition of the pipeline after a compressor station shut down, found out the regularity.
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Cameron, G. W. "Canadian Market Developments." Energy Exploration & Exploitation 6, no. 4-5 (1988): 361–68. http://dx.doi.org/10.1177/014459878800600409.
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Domestic and export sales of gas had risen to 25,800 million cu. metres by 1986. Prices appear to have settled near $Can 1.75 MMbtu after deregulation. The pipeline system now in place allows adequate transmission to most regions of Canada and into the U.S. Deregulation has seen a marked increase in sales, sometimes in circumstances where there is fierce competition from alternative energy sources such as from electricity in Quebec. The number of shippers active in inter-provincial markets has increased. Exports to the U.S. have grown despite shrinking gas consumption. Sales in the future will be even more competitive but the prospects of expanded sales to the U.S. North East and Midwest are excellent. Prices will continue to be influenced by those for crude oil
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Researcher. "STREAMLINING BULK SALES WITH IS OIL TSW: A TECHNICAL OVERVIEW." International Journal of Computer Engineering and Technology (IJCET) 15, no. 5 (2024): 1010–19. https://doi.org/10.5281/zenodo.14003087.
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This article examines the IS OIL Traders and Scheduler's Workbench (TSW), a cutting-edge software solution revolutionizing bulk product logistics in the oil and gas industry. In a $3.3 trillion sector where inefficiencies can lead to significant financial losses, TSW addresses critical needs in nomination management, ticketing, multi-modal transport support, inventory reconciliation, and terminal invoicing integration. The system's implementation aligns with industry trends toward automation and integration, potentially unlocking $2.5 trillion in value by 2030. By streamlining operations across rail, pipeline, and marine transport for various product movements, TSW enhances accuracy, efficiency, visibility, regulatory compliance, and cost reduction. This comprehensive analysis explores TSW's features, its alignment with industry trends, and its substantial impact on operational excellence in the complex landscape of oil and gas logistics.
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Chen, Daisong, Tsz Lap Chan, and Jin Shang. "Estimation of the Annual Greenhouse Gas Emissions from the Town Gas Distribution System in Hong Kong in 2022." Atmosphere 16, no. 6 (2025): 643. https://doi.org/10.3390/atmos16060643.
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Estimating leaks in urban gas distribution systems is crucial for reducing greenhouse gas emissions from fugitive losses and mitigating costly waste. This study aimed to use a simplified methodology to estimate pipeline leakage in gas distribution systems and validate these estimations against established benchmarks or other gases globally. The estimation encompassed sources including third-party damage, long-term permeation, flaring, and purging during pipeline commissioning and decommissioning, as well as fugitive leakage, each requiring respective evaluation. Results showed that the total town gas leakage volume was around 695,044 m3 to 2,009,991 m3, accounting for 0.045% to 0.13% of the total town gas sales in 2022. Among the five leakage sources, fugitive leakage was the major contributor with the leakage volume of 1,938,914 m3. To comprehensively benchmark all emission factors (EFs), those from previously reported studies were adapted to the town gas scenario and combined with the current activity factors (AFs) in Hong Kong to calculate the leakage amounts. Comparing our results with different models, we observed variations in estimated leakage amounts based on years, regions, and sampling methods. Upgrades in pipeline materials led to reduced EFs and subsequently lower total gas leakage. Our findings support efforts to reduce greenhouse gas emissions by providing actionable data for policymakers and utility companies to address gas leakage issues.
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Rassenfoss, Stephen. "It Is Easy To Find Lithium; Turning a Profit Is Hard." Journal of Petroleum Technology 75, no. 11 (2023): 26–31. http://dx.doi.org/10.2118/1123-0026-jpt.
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Finding lithium in the water from oil and gas wells is easy. Finding enough to make money is hard. In the US and Canada there has been growing interest in directly extracting lithium from the water coming out of the oil/water separator, which is competing with more established techniques such as mining and evaporating lithium-rich fluids. The race to find lithium is driven by expectations that fast-rising electric car sales will make the lithium required for batteries in those vehicles a valuable commodity. Those chasing direct extraction are also betting that their innovations can do what they say. Direct extraction from water started looking like a real possibility earlier this year when ExxonMobil paid $100 million to buy a company holding 120,000 gross acres of leases in south Arkansas. The price reflected the location in the heart of the direct lithium extraction industry of the future. The area offers a unique combination of lithium-rich water plus the infrastructure and expertise needed to transport, process, and dispose of the billions of gallons of water needed for industrial-scale mineral extraction. Commercial production of battery-quality lithium carbonate in Arkansas is years off. But the sprawling network of water-producing wells, pipelines, and processing that have made the state one of the world’s leading bromine producers, lowers the risk and cost of commercial lithium production. The source of the lithium-rich water is the Smackover—an oil formation discovered near El Dorado, Arkansas, back in 1921 when a gusher blew in. A year after that discovery, there were 608 producing wells nearby, according to the El Dorado News-Times. Now with lithium looking like battery gold, investors are rushing in. In this emotional market, lithium carbonate prices have swung like cryptocurrency. As of mid-October, a ton of it was selling for about $25,000. Over the past quarter it averaged $32,000/ton. Late last year it stood at $85,000. And in 2021 it was going for $10,000, said Graham Bain, vice president for subsurface opportunities at Enverus. He offered $25,000/ton as a “go forward price.” As with oil and gas, hopes of high prices have a way of rapidly increasing supplies, resulting in price-crashing gluts. So far, most oil companies sound curious but far from committed to lithium. “There’s a big rush. I have received several requests from companies in the Permian Basin to discuss lithium in the water,” said Jean-Philippe Nicot, senior research scientist at the Bureau of Economic Geology (BEG) at The University of Texas at Austin. He is the lead author on recent paper that offered a primer on what’s known about lithium brines from oil wells in states from Texas to Mississippi. It is based on nearly 1,802 water analyses from the US Geological Survey (USGS)—some dating back to the 1960s—plus a recent 576-well survey by the BEG. The geologists, whose work ranged from hard-rock mining to water research, said this is an early effort to begin figuring out how to find the lithium in subsurface water.
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Zhu, Ping, and H. I. H. Saravanamuttoo. "Simulation of an Advanced Twin-Spool Industrial Gas Turbine." Journal of Engineering for Gas Turbines and Power 114, no. 2 (1992): 180–85. http://dx.doi.org/10.1115/1.2906568.
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A full-range mathematical model of the LM-1600 gas turbine has been developed, for future use in EHM studies. No data were available from the manufacturer other than sales brochures giving some design and off-design performance. The model was developed using generalized component characteristics and shows excellent agreement with field data from a pipeline operator. A new method has been developed for doing the matching calculations, starting from the turbine (hot) end rather than from the compressor operating point. This method permits solution on a PC, and can be used for studying the full range of operating conditions and the development of fault matrices.
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Croker, John, Matthew Kidd, Evie Nicola, and James Dean. "Resurrection at AGL Silver Springs and Wallumbilla: case study of bringing field and surface facilities back to life." APPEA Journal 57, no. 1 (2017): 124. http://dx.doi.org/10.1071/aj16218.
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AGL acquired the Silver Springs reserves and operations from Mosaic Oil in 2010, including several depleted yet condensate-rich gas fields. Gas was sent from Silver Springs to the Wallumbilla LPG plant (acquired by AGL in 2011) to be refined into sales gas, LPG and condensate. AGL’s objective was to build a commercial underground gas storage facility by converting the Silver Springs gas field into an underground storage reservoir. The business intent was to run the reservoir in alternating injection and withdrawal mode to take advantage of supply and demand economics. Setting up for injection and withdrawal required the commissioning of 10 petroleum producing wells, bi-directional high-pressure flowlines and associated infrastructure. A high-pressure injection compressor was commissioned. Injection of dry sales gas into wells commenced in 2011. Withdrawal at a higher rate than original was facilitated by new separation and dehydration equipment. The Wallumbilla plant was refitted extensively, including flare and venting upgrades and recertification of the pipeline and every pressure vessel on-site. Withdrawal mode operations commenced in October 2015. The LPG plant operability was demonstrated; however, running at design rate was compromised by excessive chilling in the cryogenic section of the Wallumbilla plant, caused by lower than expected LPG quantities in the withdrawn gas. Process engineering work resulted in design of a regenerative heater to warm the sub-cooled gas. The presentation covers the extent of the improvement work and the process investigations, which have formed the basis to ensure future versatile operation.
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JPT staff, _. "E&P Notes (May 2022)." Journal of Petroleum Technology 74, no. 05 (2022): 14–17. http://dx.doi.org/10.2118/0522-0014-jpt.
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Shell Discovers More Oil Off Namibia Shell announced its oil discovery off Namibia in January and was “very encouraged by the early results” from the Graff-1 exploration well in the country’s Orange Basin, which “established a working petroleum system and the presence of light oil.” Researchers at Wood Mackenzie believe the find could hold upward of 700 million BOE. Shell is currently drilling a second well at La Rona, an aggressive stepout which is likely to be appraising the discovery prior to confirmation of a potential commercial development. Shell operates the Graff find with a 45% interest. Partners in the discovery are QatarEnergy (45%) and NAMCOR (10%). Less than a month after Graff was announced, TotalEnergies reported that it had made a significant discovery of light oil with associated gas on the Venus prospect, in Block 2913B in the Orange Basin. The Venus 1-X well encountered around 84 m of net oil pay in a Lower Cretaceous reservoir. No resource estimates have been officially released. First Oil Achieved at King’s Quay in the GOM Murphy Oil has achieved first oil from the Khaleesi, Mormont, and Samurai field development project in the deepwater Gulf of Mexico (GOM). The field trio is being developed subsea and tied back to the Murphy-operated King’s Quay floating production system (FPS), designed to process 85,000 B/D of oil and 100 MMcf/D of natural gas. The project comprises the Khaleesi/Mormont fields in Green Canyon Blocks 389 and 478, respectively, and the Samurai field, located in Green Canyon Block 432. Completions operations are ongoing for the remaining five wells in the seven-well project. Murphy operates the King’s Quay FPS and associated export lateral pipelines, which are owned 50% by an affiliate of Third Coast Infrastructure and 50% by entities managed by Ridgewood Energy, including ILX Holdings III LLC. Neptune Energy Ramps Up Gas Production From Duva Field Neptune Energy and its partners will be doubling gas production from the Duva field in the Norwegian sector of the North Sea, supporting increased supplies to the UK and Europe. The partnership has worked closely with the Norwegian authorities to identify measures to help meet gas demand in Europe. Gas production from the field was planned to increase by 6,500 BOE/D from the first half of April. Duva is a subsea installation with three oil producers and one gas producer, tied back to the Neptune Energy-operated Gjøa semisubmersible platform. The gas is transported by pipeline to the UK’s St Fergus gas terminal. Duva’s overall production currently stands at 30,000 BOE/D, of which 6,500 BOE/D is natural gas. Under the newly agreed measures, daily gas production will double to 13,000 BOE/D for an initial 4–8 months. Around 70% of Neptune Energy’s Norwegian production is gas, and the company is investigating opportunities to ramp up gas production from other fields within its portfolio. Duva license partners include operator Neptune Energy (30%), INPEX Idemitsu (30%), PGNiG Upstream Norway (30%), and Sval Energi (10%). New Oil Discovery Near Troll and Fram Area of the North Sea Equinor has once again discovered oil and gas close to the Troll and Fram area—this time with its Kveikje well. The find came on the operator’s 293 B production license. The company estimates the size of the discovery is between 25–50 million bbl of recoverable oil equivalent. Temporarily called Kveikje, this is the sixth discovery in this area since 2019. Up to more than 300 million BOE were proven in the five former discoveries. Equinor is considering the development as a tieback to the Troll B or C platform. There were several drilling targets in the exploration well. After Kveikje was discovered, drilling continued to the next target in the upper part of the Cretaceous stratigraphic sequence. Smaller deposits of petroleum were discovered but are considered noncommercial. The well has been permanently plugged and abandoned. The well was drilled by semisubmersible Deepsea Stavanger. Plans call for Equinor to drill another exploration well in this area this year. The 293 B license owners are Equinor (51%), DNO (29%), Idemitsu (10%), and Longboat Energy (10%). W&T Offshore Completes Bolt-On Acquisition in the GOM W&T Offshore has acquired the remaining working interests in the oil- and gas-producing properties at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields for $17.5 million in cash. The initial interest was purchased earlier this year from an undisclosed private seller. The transaction had an effective date and closing date of 1 April and was paid using cash on hand. The deal adds internally estimated proved reserves of 1.4 million BOE (70% oil) and proved and probable, or 2P, reserves of 2 million BOE (75% oil) as of year-end 2021. The properties carry an estimated net sales rate of about 900 BOE/D (~80% oil). The acquisition also adds an average of 20% working interest in more than 50 gross producing wells currently operated by the company across three shallow-water fields and provides additional opportunities for future drilling. ExxonMobil Comes Up Empty on Cutthroat Prospect in Brazil Prospect partner Murphy Oil said it and operator ExxonMobil came away with disappointing results from their Cutthroat-1 exploration well in Block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil. While the presence of hydrocarbons was not found, the partner group said it will continue to integrate the exploration well data into its regional subsurface interpretation efforts to better understand the exploration potential of its deepwater blocks located in the basin. Cutthroat-1 was located nearly 90 km offshore Brazil and was drilled in 3094 m of water by the Seadrill West Saturn drillship. It is one of multiple prospects that the partner group has mapped in the basin. ExxonMobil is the operator and holds 50% working interest in nine offshore SEAL blocks that span more than 6800 km2. Enauta Energia and Murphy Oil each hold a 30% working interest. Eni Upgrades Ndungu Field Resources Off Angola Eni has boosted its reserves base for the Ndungu field in the West Hub of Block 15/06 following the results of an initial well. The Ndungu 2 appraisal well was drilled 5 km away from Ndungu 1 and encountered 40 m of net oil pay in the Lower Oligocene reservoirs with good petrophysical properties confirming the hydraulic communication with the discovery well. The preliminary data collected on Ndungu 2 allows Eni to boost the field resources to between 800 million and 1 billion BOE in place from the initial estimates of 250–300 million BOE following the discovery well. The upgrade makes Ndungu, together with Agogo, the largest accumulation discovered in Block 15/06 since the block award. The early production phase of Ndungu started in February through one producer well, and a second producer well is expected in the fourth quarter of 2022, maximizing the utilization of existing facilities in the West Hub. Ndungu field development will now be upgraded to reflect the increase of the resource base, following a phased approach to uncap the overall potential initially contributing to extend and increase the plateau of the Ngoma—a 100,000 B/D, zero-discharge and zero-process-flaring FPSO. Block 15/06 is operated by Eni Angola with a 36.84% share. Sonangol Pesquisa e Produção holds 36.84% and SSI Fifteen Ltd., 26.32%. ExxonMobil Strikes Gas Off Cyprus The Cyprus energy ministry confirmed a reservoir of high-quality gas was encountered by the ExxonMobil-led Glaucus-2 appraisal well. The drilling of the well was conducted in the area known as Block 10 in the Exclusive Economic Zone (EEZ) that has been challenged by Turkey. The ministry said that operations in the EEZ included production testing. “The consortium will proceed with a detailed analysis and evaluation of the data collected to more accurately determine the qualitative and quantitative characteristics of the reservoir, as well as potential development and commercialization of the discoveries,” the ministry said in a statement. Cyprus previously estimated gas resources in the reservoir of between 5 and 8 Tcf when the discovery from the Glaucus-1 well was announced in 2019. ExxonMobil and Block 10 partner Qatar Petroleum began drilling the Glaucus-2 well using drillship Stena Forth in December 2021. ExxonMobil is the operator and holds a 60% interest in Block 10. Qatar Petroleum International Upstream OPC holds the remaining 40% stake. Eni, Sonatrach Make Oil Hit in Algerian Desert Eni and Sonatrach made a significant oil and gas discovery in the Zemlet el Arbi concession located in the Berkine North Basin in the Algerian desert. The concession is operated by a joint venture between Eni (49%) and Sonatrach (51%). Preliminary estimates of the size of the discovery are around 140 million bbl of oil in place. The exploratory well that led to the discovery has been drilled on the HDLE exploration prospect, about 15 km from the processing facilities of Bir Rebaa North field. HDLE-1 discovered light oil in the Triassic sandstones of the Tagi formation confirming 26 m of net pay. During a production test, the well delivered 7,000 BOPD and 5 MMcf/D of associated gas. The HDLE-1 well is the first well of the new exploration campaign which will include the drilling of five wells in the Berkine North Basin. The discovery will be appraised by the followup HDLE-2 well to confirm the additional potential of the structure extending in the adjacent Sif Fatima 2 concession operated by an Eni-Sonatrach JV (50–50%). In parallel with the appraisal program, Eni and Sonatrach will perform studies and analyses to accelerate the production phase of the new discovery through a fast-tracked development with startup planned for the third quarter of 2022. Eni has been present in Algeria since 1981 where it operates several concessions. The company produces about 95,000 BOE/D from the country. Neptune Energy Confirms Hydrocarbons at Hamlet Neptune Energy struck hydrocarbons at its Hamlet exploration well in the Norwegian sector of the North Sea. The find is located within the Gjøa license (PL153). It has yet to be confirmed if commercial volumes of oil and gas are present. A contingent sidetrack may be drilled to further define the extent of the discovery. Located 58 km west of Florø, Norway, at a water depth of 358 m, Hamlet is within one of Neptune’s core areas and close to existing infrastructure. The Hamlet test was drilled by the Odjfell semisubmersible Deepsea Yantai. Partners in the find include operator Neptune Energy (30%), Petoro (30%), Wintershall Dea (28%), and OKEA (12%).
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Wosu,, C. O., and P. N. Ikenyiri,. "Design of an Industrial Heat Exchanger Unit at the TEG Inlet of a Natural Gas Dehydration Plant." FUOYE Journal of Engineering and Technology 9, no. 4 (2025): 678–85. https://doi.org/10.4314/fuoyejet.v9i4.17.
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Gas processing industries globally grapple with water vapor in natural gas, causing issues like methane hydrate formation, caking, corrosion, and flow problems. Due to natural gas's pivotal role in energy and petrochemical production, the triethylene glycol (TEG) dehydration process proves vital for efficient water removal. Within this process, the heat exchanger at the TEG inlet to the contactor is crucial. It maintains optimal lean TEG absorption temperature and regulates sales gas temperature for pipeline transmission. Employing simulation tools like HYSYS, the analysis determined specific parameters such as an overall heat transfer coefficient of 140.4 kJ/h-m²-C, shell and tube side pressure drops of 34.47 kPa and 68.95 kPa respectively, a 5.027 m² heat exchanger area, shell volumes of 0.1955 m³ and 0.0608 m³ for the shell and tube sides respectively, and a positive heat duty of 1.727 x 10^4 kJ/hr. This positive duty signifies successful gas heating for standard transmission and maintaining lean TEG absorption temperature. Remarkably, the water composition in natural gas reduced from 0.005 mol% to 0.0002 mol% after the process simulation.
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B.O., Evbuomwan, Aimikhe V., and Datong J.Y. "SIMULATION AND EVALUATION OF A FLARE GAS RECOVERY UNIT FOR REFINERIES." European Journal of Advances in Engineering and Technology 5, no. 10 (2018): 775–81. https://doi.org/10.5281/zenodo.10726165.
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<strong>ABSTRACT</strong> Flare gas recovery systems are essential process units necessary for all oil and gas processing facilities, refineries inclusive, to put into good use the gas being wasted at the stacks by combustion causing environmental challenges. This paper focused on the design and simulation of a flare gas recovery unit for a typical conversion refinery, using ASPEN HYSYS process simulator version 8.6 for the process condition of a typical refinery in Nigeria. The design gave a throughput efficiency of 97.95% using a single liquid-ring-compressor to handle any flow upsurge up to 40% of the usual gas rate and saving $35,924.00 on equipment cost over the use of conventional reciprocating compressors. The product gas after amine treatment met the pipeline quality gas specification of 4ppm of H<sub>2</sub>S, 3mol% of CO<sub>2</sub> and was found suitable and capable of generating 8MW of electricity using a gas turbine. With a total capital cost of $26,767,050.89, and an operating cost of $2,139,483.54, the project yielded revenue of $9,419,920.00 from electricity sales at the industrial tariff class rate of ₦48.39 per kWh. The research proved viable with a payout or breakeven period of 4 years and 4 months, a net-present-value (NPV) of $ 35,555,817.46 after a project life of 20 years, and an internal rate of return of 17.10%. However, investment decisions are advised only when interest rates are below 34.6% and inflation rates higher than -6%.
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KHALAFOVA, Sevda, and Nadir ISMAYILOV. "INFORMATION PROVISION OF TOURISM AND ECONOMY IN AZERBAIJAN AND ITS BIBLIOMETRIC ANALYSIS." GeoJournal of Tourism and Geosites 56, no. 4 (2024): 1809–15. https://doi.org/10.30892/gtg.56435-1349.
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Tourism is travel for pleasure, and the commercial activity of providing and supporting such travel. Tourism can be domestic (within the traveller's own country) or international, and international tourism has both incoming and outgoing implications on a country's balance of payments. The economy of Azerbaijan has gone through different stages of rapid growth, stability, and crisis. In general, the economy of Azerbaijan, besides field-wise classification, can be divided into three categories: 1. recession period, covering 1992–1995, right after Azerbaijan restored its independence after the USSR collapsed, 2. recovery, from 1996 to 1997, mainly because of increased oil sales, potential oil contracts, partners, and pipelines, 3. boom, from 1998 till 2008, and finally, an economic fall, starting from 2009. After Azerbaijan became independent following the collapse of the Soviet Union, the country started to pursue its sovereign economic policy. For a newly independent country with an economy mainly based on the oil and gas industry, it was quite demanding to keep its say in the world of economy giants. The key objectives of the new and independent economic policy were the establishment of the economic system built on the principles of several types of property, including private property, unlike the Soviet times, integration into the global economy and transition to the market economy. The study of document flow is the most important condition for evaluating the current situation, trends and development prospects in a certain field. The scientific information obtained with the help of the conducted research is successfully applied in various evaluation processes, which in turn allows to accurately determine the development of a certain scientific direction. Among the types of activities carried out in the direction of building an information society in the Republic of Azerbaijan, the organization and management of library - bibliography and information work, the use of modern technologies along with traditional work methods in providing information to readers has become a priority direction of our state's policy in the field of library work. The main goal of t he article is to conduct a comprehensive study of the document flow in the field of tourism and economy and to sup port the information provision of specialists working in this field in the future. One of the priority directions for modern librarian ship and bibliography is the study of information resources in the field of tourism and economy, the determination of the location of these information resources, the study of the current state of the flow of documents in this field, the bibliometric analy sis of fundamental scientific works created in the field of tourism and economy, library- based on the analysis of the current state of information systems, it consists in determining the directions for improving the information provision of different groups of the population. Research methods: special library science, historical, structural-functional analysis, systematic approach, generalization, sociological, statistical analysis and comparative analysis methods were used in the research process. The main conclusion of the article is to achieve the development of information demand and document flow in the field of tourism and economy as a result of the elimination of existing problems in this field. Mentioning certain proposals referring to the works of local and foreign authors is one of the points that attract the main attention in the article.
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Jenkins, C. C., D. M. Maughan, J. H. Acton, A. Duckett, B. E. Korn, and R. P. Teakle. "THE JANSZ GAS FIELD, CARNARVON BASIN, AUSTRALIA." APPEA Journal 43, no. 1 (2003): 303. http://dx.doi.org/10.1071/aj02016.
Full textAbstract:
The Jansz gas field is located in permit WA-268-P, 70 km northwest of the Gorgon gas field in the Carnarvon Basin. The Jansz–1 discovery well was drilled in April 2000 and intersected 29 m of net gas pay in an Oxfordian age shallow marine sandstone reservoir. The well drilled a stratigraphic trap on the western limb of the Kangaroo Syncline.The Io–1 well was drilled in January 2001 in the adjacent permit WA-267-P (18 km from Jansz–1) and intersected the same Oxfordian sandstone reservoir penetrated by Jansz–1, with a total of 44 m of net gas pay. The Tithonian and the Upper Triassic Brigadier Sandstone gas reservoirs at Geryon–1 (1999) and Callirhoe–1 (2001) in WA-267-P are in pressure communication with the Oxfordian gas reservoir at Jansz–1 and Io–1. Consequently, the three different age reservoirs comprise a single gas pool, with a common gas/water contact.The Jansz gas field has been delineated by four wells and 2D seismic. The gas sandstones have a prominent amplitude versus offset response, which defines the field limits. The Jansz gas field is confirmed by drilling to be an areally extensive (2,000 km2) gas accumulation with a gross column height of 400 m and an estimated 20 TCF (566 G.m3) recoverable sales gas, which represents 40% of the discovered gas resources in the deepwater Carnarvon Basin. The size of the Jansz gas field and its remoteness from existing pipeline gas markets suggests that an export LNG project will be the basis for its development.
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Eletta, O. A. A., D. T. Awotoye, and A. A. Zubairu. "Investigation of Alkanol-Amine Solvents and their Blends for CO2 Removal from Natural Gas using Aspen-Hysys." Nigerian Journal of Technological Development 18, no. 4 (2022): 268–78. http://dx.doi.org/10.4314/njtd.v18i4.2.
Full textAbstract:
The removal of carbon dioxide (CO2) from natural gas is vital towards meeting pipeline sales gas specifications and evading operational complications during the liquefaction of natural gas. Therefore, the removal of CO2 from natural gas is necessary for the efficient utilization of natural gas and for the reduction of global CO2 emission. It is also vital for the effective liquefaction process in the liquefied natural gas project A common and widespread technique used at natural gas plants in Nigeria is the removal of carbon dioxide (CO2) from natural gas through chemical absorption using alkanolamine solutions. In this research, an amine sweetening process is simulated using Aspen HYSYS V10 with a typical Nigerian natural gas composition. The simulation is used to investigate four different kinds of amines and their blends (mixed amines). The investigated amines are Monoethanolamine (MEA), Diethanolamine (DEA), Diglycolamine (DGA) and Methyldiethanolamine (MDEA) while the blends are MDEA + MEA, MDEA + DEA and MDEA + DGA. Results obtained from the simulation show that the mixed amine “MDEA + MEA” with lean amine strength of 11% MEA and 39% MDEA, absorbs 99.97% of CO2 present in the gas and hence, amine blends absorb carbon dioxide from natural gas better than the individual amines. It was also concluded that increasing the composition of the primary or secondary amine while decreasing the composition of the tertiary amine in the lean amine solution (amine blend) led to an increase in the amount of CO2 being absorbed. The study provides useful information on the absorption of CO2 using alkanolamine solvents and their blends in a standard amine sweetening plant.
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Deny, Alimun, and Hariadi Djoko Purwanto Agustinus. "Improving Turn around Performance through Operational Models and Value Stream Mapping on the Natuna Sea AG Platform of PT. X." International Journal of Innovative Science and Research Technology 7, no. 12 (2023): 1518–33. https://doi.org/10.5281/zenodo.7527691.
Full textAbstract:
PT. X is one of the upstream oil and gas industry assets in Indonesia that produces natural gas and petroleum from production wells in Natuna Sea, with natural gas production capacity of 165 MMSCFD and 2000 BPD oil. The natural gas exported through a subsea pipeline to Singapore under a 30 years Gas Sales Agreement (GSA) contract. The issue of managing, planning and execution of facility maintenance activities is important to achieve high efficiency and performance. This study is intended to improve lean manufacturing of Turn Around Maintenance (TAM) with Value Stream Mapping and Operational mode methods. The current state mapping in flare tip inspection activities, can increased its Value Added Time (VAT) from 67% to 81% and increase the effect of Lead Time to 63% in the future state map. Research on operational modes using the PLS- SEM method with SmartPLS software provides results on the relationship between the influence of planning and improving lean manufacturing on operating performance. The result showed that there was a positive and significant influence of the scope of TAM, contractor's competency on TAM performance. It is also resulted in a positive and significant influence of TAM performance and maintenance performance on the operating performance of the AG platform. Meanwhile, the business planning process does not have a significant effect on TAM performance.
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Rassenfoss, Stephen. "A Norwegian Oil Company Could Play a Key Role in Brazil’s Gas Transformation." Journal of Petroleum Technology 73, no. 08 (2021): 18–21. http://dx.doi.org/10.2118/0821-0018-jpt.
Full textAbstract:
Equinor could play a critical role in Brazil’s drive to boost its economy by opening up its gas markets. The Norwegian oil company operates two huge deepwater blocks with enough gas to lower prices in the country where big users pay some of the highest prices in the world. The development plan for one of those blocks, BM-C-33 in the Campos Basin, would deliver an average of 14 million m3/d of gas—about 15% of the country’s gas demand on a high-consumption day, which is about 92 million m3/d, based on data from Rystad. A second project in the heart of the presalt, Bacalhau, could become a model for how an international oil company can market gas successfully in the country’s richest oil play, the Santos Basin presalt. The gas potential in that play is also huge; the gas/oil ratio is high compared with other Brazilian fields but has largely been untapped. So far, Equinor and its partners in the projects have not committed to developing gas on either lease, but Equinor appears to be seriously considering doing so. The big question it needs to answer is what the gas market there will look like in a year or so. Brazil has set out to promote domestic gas supplies by ending Petrobras’ virtual monopoly in the pipeline business in favor of a less-regulated, competitive gas market. Equinor avoided gas sales at Bacalhau with an $8 billion Phase 1 plan that will use the popular practice of reinjecting produced gas. Gas reinjection maintains reservoir pressure and allows the development to comply with Brazil’s ban on routine flaring. Brazil’s energy regulator, ANP, said that when Equinor develops a plan for its second phase of development, the company needs to con-sider gas production. The role of gas market pioneer is the latest technical challenge taken on by Equinor in Brazil. Previously, it became the operator of an offshore heavy-oil field—Perigrino—and an aging giant—Roncador—both in the Campos Basin. While the Norwegian company has not promised to take on that role, it has a huge incentive to do so as the operator of Block BM-C-33, where most of the reserves are in the form of gas. The resource is estimated at 3 Tcf of gas and 700 million bbl of condensate, according to Offshore Technology. Equinor and its partners Repsol and Petrobras have developed a plan that would move the liquids by tanker from the platform, which is in water as deep as 2900 m, and build a pipeline about 200 km from there to shore. When asked about the status of the project, Geir Tungesvik, senior vice president for project development at Equinor, said the company is working to “improve the business case.” A Potential Case Study Tungesvik’s bland description fails to reflect the risks and uncertainties faced by those trying to put together offshore gas marketing plans in Brazil. If Equinor and its partners go forward with their plan to monetize that massive gas reserve, the result is likely to be a case study for those who follow. It could either be a model for successful development or a cautionary tale.
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Ardyrizky, Dhanies Wahyu, Aditya Rio Prabowo, Seung Jun Baek, and Quang Thang Do. "A comprehensive study of infrastructure failures in the energy industry to improve operational safety." Jurnal Inovasi Mesin 7, no. 1 (2025): 1–25. https://doi.org/10.15294/jim.v7i1.22583.
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The demand for crude oil continues to increase in line with expanding needs, but this contrasts with its limited availability in nature. The oil and gas industry is one of the key sectors in the global economy, encompassing exploration, refining, processing, transportation, distribution, and sales. Given the high-risk working environment, safety is a crucial factor that must be considered. In recent decades, numerical methods have been widely used to enhance the effectiveness and efficiency of safety analysis, particularly in risk identification, equipment condition monitoring, and optimizing hazard mitigation strategies. This report discusses the application of numerical methods in improving the quality of planning, maintenance, and failure mitigation of various components and infrastructure at PT Pertamina Patra Niaga Fuel Terminal Boyolali. The study focuses on MOV with the friction coefficient between the stem and stem nut, pipeline systems concerning corrosion in elbows caused by chemical compounds carried by oil, and storage tanks related to temperature control within the tank to maintain the quality and quantity of oil as per demand. A comprehensive study shows that lubrication can limit the friction coefficient in MOV, while viscosity is a significant issue in pipeline systems and storage tanks. Numerical approach methods can improve the energy industry's safety, reliability, and efficiency. Modeling can reduce costs, time, and worker safety risks compared to experimental approaches.
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Nwosi-Anele, Adaobi Stephenie. "Technology Focus: Natural Gas Processing and Handling (April 2025)." Journal of Petroleum Technology 77, no. 04 (2025): 42–43. https://doi.org/10.2118/0425-0042-jpt.
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Natural gas processing includes an array of operations, including natural gas dehydration, sweetening, liquefaction, fractionation, knockout of inert gases, transportation, and transmission to sales point. These processes require interactions of different phases of dry-gas and wet-gas pressure, volume, and temperature. These interactions are demonstrated using equations of state, simulations, and models. Recently, artificial intelligence (AI), deep learning (DL), and machine learning (ML) have taken natural gas processing and handling on a new trajectory, replacing complex simulation runs. Challenges related to natural gas processing and handling such as gas leaks, carbon emission, and gas flaring are being managed using innovative processes developed through the operations of AI, ML, and DL. In reviewing a collection of SPE papers with top-notch innovations in natural gas processing operations, it is clear that technologies have become smart, with researchers and technology experts moving with the trends to make improvements on previous operations. Researchers and technology experts have made novel and innovative contributions to natural gas processing and handling using robotic and smart technologies for leak detection, carbon footprinting, and flare management. Smart technologies have also improved the operation processes around gas dehydration, sweetening, liquefaction, and fractionation. These have replaced complex backend simulations and have made natural gas processing seamlessly automated. Truly, AI, DL, and ML may not be optimally efficient in other climes, but they have shown reasonable efficiency in surface production operations, especially natural gas processing, because many of these operations have been automated. This trend is seen in the papers summarized here. Summarized papers in this April 2025 issue. OTC 34756 - Deep-Learning Image-Processing Model Uses Optical Gas-Imaging Camera To Detect Leaks by Mehdi Korjani, Clean Connect, et al. SPE 222264 - Zero-Flaring Technology Reduces Greenhouse-Gas Emissions by Zeeshan Ahmad, ADNOC, et al. SPE 222818 - Study Explores Carbon-Capture Options for Gas‑Processing Facilities by Srihari Kannan, Shell, et al. Recommended additional reading at OnePetro: www.onepetro.org. SPE 218939 - Advancements in Gasfield Operations: A Path to Achieving Zero Flaring by Zaid Alsuhali, Saudi Aramco, et al. SPE 222919 - A Study on Supply-Chain Management of LNG Using Artificial Intelligence by Nicy Susan Koshy, Trafigura Global Services SPE 218564 - Optimizing Gas-Pipeline Operations With Machine Learning: A Case Study of a North American Energy Company by S. Saboo, Amazon Web Services
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Tulupov, Alexander S., and Ivan A. Titkov. "Sustainable development of PJSC «Gazprom»: practical application of ESG-model in production and export of liquefied gas." Market economy problems, no. 1 (2022): 98–126. http://dx.doi.org/10.33051/2500-2325-2022-1-98-126.
Full textAbstract:
Subject/Topic. The paper is devoted to analysis of ESG-model application in production and export of liquefied gas with due account of current opportunities and threats of the EU and USA green transition policy and implementation of transboundary carbon charge. Methodology. General scientific cognitive methods (analysis, synthesis, deduction, comparison, scientific abstraction, logical reasoning and fact-finding) were applied to prepare the theoretical and methodological part of the scientific publication. Specific scientific cognitive methods (static analysis, expert estimates, graphical method) were used to prepare the analytical and expert sections of the publication, to form scenarios for the development of the ESG model of Gazprom's gas business, taking into account the current challenges and threats of the EU and US green policy, the «4 Worlds» Foresight method was used. Results. The scientific study of the ESG model application by «Gazprom's» gas business showed a deep understanding of the green transition processes within the LNG production and sales business processes, which is confirmed by both substantial investments in environmental protection measures and regular business expenses on compensation of gas production and transportation impact on the environment. A comparative analysis of ESG models applied by the gas business of the key oil and gas holdings has revealed the undisputed leadership of PJSC «Gazprom» and its commitment to creating the infrastructure and market landscape for the formation of an «environmentally friendly oil and gas business». According to external stakeholders (political elite of EU and USA, foreign financial and consulting institutions) among the weaknesses of the ESG model of gas business is its use of the «environmental credit» factor (PJSC «Gasprom» buys unused quotas on carbon emissions from the state in order to improve its own rating of environmentally friendly business); presence of undisguised manipulation with environmental value of pipeline gas deliveries to the EU (creating threat of market monopolization); presence of PJSC «Gazprom» holding's own bank (being the source of potential credit risks in the part of financing «toxic projects»); use of state corporation status by the holding to lobby its commercial interests in the EU and the US. Conclusions/Significance. At the end of the research the four main scenarios of ESG-model development were plotted and the expert judgement on their influence on the further lifecycle of the green policy is given: under the extreme scenario (red world) the company is likely to exit the EU and US markets in favour of the Asian states; under the more positive scenarios a gradual decarbonization of business processes of production, manufacturing and sales of LNG, taking into account international environmental standards, will correspond to the national goals and interests of Russia, and not «blindly» following the interests of Western environmental policy. Application. Results of the scientific research can be used to develop academic competence of students on strategic management and sustainable development in the gas business, and for practitioners to generate and improve ESG-models taking into account the latest requirements of the green policy of EU and USA, and the use of green finance tools for implementation of projects on business processes decarbonization.
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Tulupov, Alexander S., and Ivan A. Titkov. "Sustainable development of PJSC «Gazprom»: practical application of ESG-model in production and export of liquefied gas." Market economy problems, no. 1 (2022): 98–126. http://dx.doi.org/10.33051/2500-2325-2022-1-98-126.
Full textAbstract:
Subject/Topic. The paper is devoted to analysis of ESG-model application in production and export of liquefied gas with due account of current opportunities and threats of the EU and USA green transition policy and implementation of transboundary carbon charge. Methodology. General scientific cognitive methods (analysis, synthesis, deduction, comparison, scientific abstraction, logical reasoning and fact-finding) were applied to prepare the theoretical and methodological part of the scientific publication. Specific scientific cognitive methods (static analysis, expert estimates, graphical method) were used to prepare the analytical and expert sections of the publication, to form scenarios for the development of the ESG model of Gazprom's gas business, taking into account the current challenges and threats of the EU and US green policy, the «4 Worlds» Foresight method was used. Results. The scientific study of the ESG model application by «Gazprom's» gas business showed a deep understanding of the green transition processes within the LNG production and sales business processes, which is confirmed by both substantial investments in environmental protection measures and regular business expenses on compensation of gas production and transportation impact on the environment. A comparative analysis of ESG models applied by the gas business of the key oil and gas holdings has revealed the undisputed leadership of PJSC «Gazprom» and its commitment to creating the infrastructure and market landscape for the formation of an «environmentally friendly oil and gas business». According to external stakeholders (political elite of EU and USA, foreign financial and consulting institutions) among the weaknesses of the ESG model of gas business is its use of the «environmental credit» factor (PJSC «Gasprom» buys unused quotas on carbon emissions from the state in order to improve its own rating of environmentally friendly business); presence of undisguised manipulation with environmental value of pipeline gas deliveries to the EU (creating threat of market monopolization); presence of PJSC «Gazprom» holding's own bank (being the source of potential credit risks in the part of financing «toxic projects»); use of state corporation status by the holding to lobby its commercial interests in the EU and the US. Conclusions/Significance. At the end of the research the four main scenarios of ESG-model development were plotted and the expert judgement on their influence on the further lifecycle of the green policy is given: under the extreme scenario (red world) the company is likely to exit the EU and US markets in favour of the Asian states; under the more positive scenarios a gradual decarbonization of business processes of production, manufacturing and sales of LNG, taking into account international environmental standards, will correspond to the national goals and interests of Russia, and not «blindly» following the interests of Western environmental policy. Application. Results of the scientific research can be used to develop academic competence of students on strategic management and sustainable development in the gas business, and for practitioners to generate and improve ESG-models taking into account the latest requirements of the green policy of EU and USA, and the use of green finance tools for implementation of projects on business processes decarbonization.
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Glamazdin, V. P., O. V. Melnyk, and V. M. Tonkogolosiuk. "Oil & gas sector development, as a component of energy of Ukraine." Science, technologies, innovation, no. 1(13) (2020): 32–41. http://dx.doi.org/10.35668/2520-6524-2020-1-05.
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The article analyzes the current state and perspective directions of development of the energy sector of Ukraine in general and the oil and gas complex in particular, which should meet the Plan of measures for the implementation of the stage “Reform of the energy sector (until 2020)” of the Energy Strategy of Ukraine for the period until 2035 “Security, energy efficiency, competitive”. According to the study, at the time the report was released, 80% of the points foreseen by the Plan were not fulfilled. Some legislative initiatives and changes in the regulation of markets of fuel and energy resources are considered. The article analyzes the dynamics of changes in energy consumption. The main trends in the development of the gas and oil products markets are identified. It is found that, despite progress on diversification of supply sources, the country is heavily dependent on imports of energy from The Russian Federation. Separate consideration is given to the transit of natural gas from the Russian Federation to the EU. It is noted that the signed contract is quite compromise and provides a transit pipeline load of less than 40%. The main reasons for the change in the structure of the use of fuel and energy resources, in particular, the practical termination of the use of fuel oil as a boiler-furnace fuel, are also highlighted. The data of the State Statistics Service of Ukraine on the dynamics of prices for natural gas for all categories of consumers, including tariffs for transportation, distribution and trade margin (for household consumers), were also processed. A steady increase in natural gas prices for household consumers was noted during almost the entire analyzed period. Naftogaz Ukraine’s unbinding process was investigated. It is revealed that all necessary steps have been taken to create an independent gas transmission system operator, which took place on January 1, 2020. The implementation of the Energy Community Directives and Regulations in the energy sector has been analyzed, with overall sales less than 50%. The main results of the Stockholm Arbitration between Naftogaz of Ukraine and Gazprom are considered.
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Penteado, Alberto Teixeira, Giovanna Lovato, Abigail Pérez Ortiz, et al. "Economic Potential of Bio-Ethylene Production via Oxidative Coupling of Methane in Biogas from Anaerobic Digestion of Industrial Effluents." Processes 9, no. 9 (2021): 1613. http://dx.doi.org/10.3390/pr9091613.
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Brazil’s large biofuels industry generates significant amounts of effluents, e.g., vinasse from bioethanol, that can effectively be used as substrate for production of biogas via Anaerobic Digestion (AD). The Oxidative Coupling of Methane (OCM) is the heterogeneous catalytic oxidation of methane into ethylene, which is a main building block for the chemical industry. This work investigates the potential and competitiveness of bio-ethylene production via OCM using biogas produced by biological anaerobiosis of vinasse as a feedstock. The proposed process can add incentive to treat of vinasse via AD and replace fossil ethylene, thus potentially reducing emissions of Greenhouse Gases (GHG). A process model is developed in Aspen Plus v10 software and used to design an economic Biogas-based Oxidative Coupling of Methane (Bio-OCM) process that consumes biogas and oxygen as educts and produces ethylene, ethane, and light off-gases as products. Operating conditions in the reaction section are optimized and a reaction product yield of 16.12% is reached by applying two adiabatic Packed Bed Reactors (PBRs) in series. For the downstream CO2 removal section, a standalone amine-absorption process is simulated and compared to a hybrid membrane-absorption process on an economic basis. For the distillation section, two different configurations with and without Recycle Split Vapor (RSV) are simulated and compared. The bio-ethylene production cost for a Bio-OCM plant to be installed in Brazil is estimated considering a wide range of prices for educts, utility, side products, and equipment within a Monte Carlo simulation. The resulting average production cost of bio-ethylene is 0.53 ±0.73 USD.kgC2H4-1. The production cost is highly sensitive to the sales price assigned to a light off-gas side-product stream containing mostly the un-reacted methane. A sales price close to that of Brazilian pipeline natural gas has been assumed based on the characteristics of this stream. The Monte Carlo simulation shows that a bio-ethylene production cost below or equal to 0.70 USD.kgC2H4-1 is achieved with a 55.2% confidence, whereas market values for fossil ethylene typically lie between 0.70USD.kgC2H4-1–1.50USD.kgC2H4-1. Technical and economic challenges for the industrial implementation of the proposed Bio-OCM process are identified and relevant opportunities for further research and improvement are discussed.
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Emelyanov, Vladislav Vyacheslavovich. "Factors of competitiveness of LNG export projects." Mezhdunarodnaja jekonomika (The World Economics), no. 11 (November 1, 2020): 17–25. http://dx.doi.org/10.33920/vne-04-2011-02.
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As a result of the development of liquefaction, storage, transportation and regasification technologies, the attractiveness of LNG projects is steadily growing — in some cases, such projects are becoming more competitive than traditional pipeline solutions. The range of solutions for natural gas liquefaction projects is very wide, but low-tonnage LNG provides greater mobility and high speed of project implementation, cause of the usage of the simple low-efficiency technologies. Medium-capacity natural gas liquefaction plants can be built in environment where there are not enough resources to create a large-capacity project, and enable the usage of relatively small and remote fields, including off shore areas. For Russia, an important advantage of medium-tonnage technologies is that they can be developed in a relatively short time. The positive experience of government support for LNG exports in Canada is noteworthy. The government of this state strives to create conditions for environmentally responsible energy production and use, while ensuring the growth of the Canadian economy, as well as the availability of reliable and competitive energy sources and the protection of energy infrastructure. As for the portfolio of orders for Russian projects for natural gas liquefaction, for example, at present, in the Yamal-LNG project, Russian orders account for only 30 %, and the goal is at least 70 %. To achieve this goal, government support is required: concessional lending and tax incentives. For LNG production in the Arctic zone of the Russian Federation, with the support of the state Corporation Rosatom, a bench-testing base for import-substituting equipment is being created in the Nizhny Novgorod region. Government support for LNG projects should also include improving the regulatory framework. Russia is taking an important step towards developing its hydrocarbon reserves in the Arctic. Special attention should be paid to the measures of state support that are provided to exporters in the context of the pandemic, including in the field of LNG sales, in particular, ensuring sustainable lending to the real sector of the economy with the provision of state guarantees and subsidies.
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Luzyanin, Sergey G. "Russian-Chinese “borders” of security. What does the Beijing’s message of V.V. Putin and Xi Jinping mean?" Asia and Africa Today, no. 2 (2022): 5. http://dx.doi.org/10.31857/s032150750018790-1.
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The signing on February 4, 2022 in Beijing of a joint Russian-Chinese statement &quot;On international relations entering a new era and global sustainable development&quot; and a block of bilateral trade, economic and energy agreements means a qualitative expansion of the scope of the strategic partnership between the two countries. Russia and China politically position themselves not only as a global and regional center of power and security, but also as powers that offer the world the development of common human values and concepts - democracy, indivisible security, openness and equality, oppose the politicization of sports, for the expansion of anti-pandemic measures to combat the common evil of COVID-19. China supported the proposals put forward by Russia on its security guarantees in Europe, which helps to further form a common strategic space of Eurasian security from the western part of the Pacific Ocean to the Eastern European conditional line &quot;Black Sea - Belarus&quot;. There is no need to reformat the Russian-Chinese strategic partnership into a military alliance in modern conditions. The economic block of cooperation is based on systemic and mutually beneficial energy cooperation, which is implemented in the increase in successful gas contracts, including transactions for the sale of liquefied natural gas (LNG) and pipeline gas, oil projects and sales, the construction of new power units by Russia at Chinese nuclear power plants (NPPs), and the expansion of supplies coal, etc. In the context of a significant increase in the volume of Russian-Chinese trade in 2021 by a third compared to 2020, the expansion of the practice of settlements in national currencies (ruble - yuan), bypassing the dollar, acquires additional importance. In the face of American threats to shut down the SWIFT international payment system, it is relevant to create an independent Russian-Chinese payment system for transactions that provides not only energy transactions, but also the entire range of bilateral trade, economic and interbank transactions. The formation of the Greater Eurasian Partnership involves a wide range of trade, economic, investment, transport and institutional measures to deepen Eurasian cooperation. The key component in this area is to increase the efficiency of the process of interface between the projects of the Eurasian Economic Union (EAEU) and the Chinese initiative &quot;One Belt and One Road&quot;, the implementation of joint mutually beneficial infrastructure projects.
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Johnson, Walter R., Zhen-Gang Ji, and Charles F. Marshall. "STATISTICAL ESTIMATES OF SHORELINE OIL CONTACT IN THE GULF OF MEXICO." International Oil Spill Conference Proceedings 2005, no. 1 (2005): 547–51. http://dx.doi.org/10.7901/2169-3358-2005-1-547.
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ABSTRACT As steward of the Federal offshore lands known as the Outer Continental Shelf (OCS), the U.S. Department of the Interior (DOI), Minerals Management Service (MMS), is responsible for balancing the Nation's search for commercial oil and gas with protection of the human and marine environments. The MMS regulates the development of mineral resources in an environmentally safe manner by analyzing environmental consequences of the OCS program prior to lease sales or approval of industry's plans. The Oil-Spill Risk Analysis (OSRA) model was developed by the DOI for the analysis of possible oil-spill impact from offshore oil and gas operations. The OSRA model produces statistical estimates of hypothetical oil-spill occurrence and contact from projected OCS operations. The model generates an ensemble of sea surface oil-spill trajectories by initiating thousands of oil-spill simulations at hypothetical spill locations to statistically characterize oil-spill risk in areas of prospective drilling and production and along projected pipeline routes. The hypothetical spills are initiated every day and move at the velocity of the vector sum of the surface ocean currents plus an empirical wind-induced drift of speed equal to 3.5% of the local wind speed, with a wind-speed-dependent direction (Samuels et al., 1982). The model generates oil-spill trajectories by integrating interpolated values of the wind and ocean current fields at intervals short enough to use the full spatial resolution of the ocean current and wind fields. The OSRA model, as applied to the Gulf of Mexico, uses 3-hourly ocean current fields over 7 years (1993–1999) generated by the Princeton Regional Ocean Forecast System (PROFS) (Oey et al., 2004). The PROFS is driven by synoptic winds, heat flux, and river flows. The wind field is based on the European Center for Medium-Range Weather Forecasts surface winds enhanced by observations from meteorological buoys and Coastal-Marine Automated Network stations. The same wind field used to force the ocean model is used to move the oil in the spill trajectories. As an example of environmental assessment, the OSRA model was used to estimate the spreading of oil spills by simultaneously modeling fractions of each spill, referred to as spillets. The spillets were used to calculate additional statistics, in particular, the length of coastline contacted by a large spill. The coastline was divided into equal length segments. Assumptions were made regarding what fraction of the spill (i.e., the number of spillets) that contacted a land segment would constitute a contact larger than the “level of concern.” Sensitivity of the analysis to key assumed parameters, such as the number of spillets and the level of concern, were tested.
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JPT staff, _. "E&P Notes (February 2022)." Journal of Petroleum Technology 74, no. 02 (2022): 17–23. http://dx.doi.org/10.2118/0222-0017-jpt.
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Shell Signs Concession for Oman Block 10 Shell, along with its partners OQ and Marsa Liquefied Natural Gas LLC (a joint venture between TotalEnergies and OQ), have signed a concession agreement with the Ministry of Energy and Minerals on behalf of the government of the Sultanate of Oman to develop and produce natural gas from Block 10. The parties also signed a separate gas sales agreement for gas produced from the block. The two agreements follow an interim upstream agreement signed in February 2019. The concession agreement establishes Shell as the operator of Block 10, holding a 53.45% working interest, with OQ and Marsa LNG holding 13.36% and 33.19%, respectively. For the initial phase, Petroleum Development Oman (PDO) is building the infrastructure for the project, including the main pipeline to the Saih Rawl gas processing facility, on behalf of the Block 10 venture partners. The venture will drill and hook up wells to maintain the production beyond the initial phase. The block is expected to reach production of 0.5 Bcf/D. Startup is expected within the next 2 years. In addition, Shell and Energy Development Oman (EDO) signed an agreement to process the natural gas from Block 10 in EDO’s Saih Rawl facility. Shell and the government have agreed that, in parallel to the development of Block 10, Shell will develop options for a separate downstream gas project in which Shell could produce and sell low-carbon products and support the development of hydrogen in Oman. Equinor Encounters Oil at Toppand Equinor has discovered oil in the Troll and Fram area in exploration wells 35/10-7 S and 35/10-7 A in the Toppand prospect. Preliminary calculations indicate between 21 million and 33 million BOE of recoverable reserves. Well 35/10-7 S encountered an oil column of around 75 m in the lower part of the Ness formation and in the Etive formation. There were also traces of hydrocarbons in the shale- and coal-dominated upper part of the Brent Group. A total of around 68 m of effective sandstone reservoir of good to very good reservoir quality was encountered in the Ness and Etive formations combined. Exploration well 35/10-7 A encountered a 60-m oil-filled sandstone-dominated interval in the lower part of the Ness formation and in the Etive formation. A total of around 67 m of effective sandstone reservoir of good to moderate quality were encountered in the Ness and Etive formations combined. Geir Sørtveit, senior vice president for exploration and production west operations for Equinor, said, “We are pleased to see that our success in the Troll- and Fram area continues. We also regard this discovery to be commercially viable and will consider tying it to the Troll B or Troll C platform. Such discoveries close to existing infrastructure are characterized by high profitability, a short payback period, and low CO2 emissions.” These wells are the second and third exploration wells in Production License 630. The license was awarded in the 2011 Award in Predefined Areas. The wells were drilled around 8 km west of the Fram field and 140 km northwest of Bergen. Equinor holds a 50% stake and operates Toppand. Partner Wellesley holds the remaining 50% interest. Petrobras Sells Polo Carmópolis Stake to Carmo Petrobras has signed a deal to sell its stake in the onshore Polo Carmópolis area to Carmo Energy for $1.1 billion. The operator said $275 million would be paid up front, another $550 million when the deal closes, and a further $275 million 1 year after closure of the deal, which still needs regulatory approval. The Polo Carmópolis area comprises 11 onshore concessions in the state of Sergipe. Petrobras said in a statement that it is increasingly concentrating its resources on deep and ultradeepwater assets, where it has shown a competitive edge over the years, producing better-quality oil and with lower greenhouse-gas emissions. The Carmópolis Cluster recorded an average production of 7,600 BOPD and 43,000 m3/D of gas from January to November 2021. Eni, EGPC in $1-Billion Pact To Explore Gulf of Suez, Niger Delta Egyptian General Petroleum Corp. (EGPC) has signed an agreement with Italian energy group Eni for oil exploration in the Gulf of Suez and Nile Delta regions. The deal is valued at no less than $1 billion of investments, the petroleum ministry said in late December. The agreement also included a commitment from Eni to additionally spend “not less than $20 million” to drill four wells, the ministry added in a statement. The deal comes as part of the ministry’s strategy to increase production rates and to attempt to offset the natural decline of wells by using the latest technologies in oil-producing areas. Last October, Eni announced three new discoveries in the Meleiha and South West Meleiha concessions in the Western Desert. Eni has been operating in Egypt since 1954 with a current production of about 360,000 BOED. Chevron Transfers Stake in Suriname Block 5 to Shell Chevron has transferred one-third of its 60% equity interest in an offshore Suriname block for which it has a production-sharing agreement to a unit of Royal Dutch Shell, Suriname’s state oil company confirmed. Paradise Oil Company, a subsidiary of Suriname’s state-run Staatsolie, retains its 40% stake in the Block 5 venture as a nonexecutive partner, according to the farmout contract. Staatsolie and Chevron signed a production-sharing contract last October for Block 5, which covers an area of 2235 km2. The deal marked the first time that Staatsolie will participate as a partner in offshore activities. Equinor Increases Ownership in the Statfjord Field Equinor has entered into an agreement to acquire all of Spirit Energy’s production licenses in the Statfjord area which spreads across the Norwegian and UK continental shelves and are developed by three integrated production platforms (Statfjord A, B, C). All licenses are operated by Equinor. Equinor will pay $50 million, plus a contingent payment linked to commodity prices for the period between October 2021 to December 2022. The transaction has a commercial effective date from 1 January 2021, which is expected to result in a net payment to Equinor at closing. Spirit Energy’s daily production from the Statfjord area in the third quarter of 2021 was around 21,000 BOED. The transaction is part of a larger deal including Spirit Energy’s shareholders, Centrica Plc and Stadtwerke München, who are exiting their portfolio in Norway and selling their assets to Sval Energi. The sale to Sval Energi includes all assets with the exclusion of Statfjord. Statfjord marked its 40th year of production in 2019. One of the earliest oil fields on the Norwegian Continental Shelf, it has produced 5.1 billion BOE. Equinor has recently launched a plan to extend the life of the field toward 2040. The closing of the transaction is subject to certain conditions, including customary government approval, and is expected to be completed by the first half of 2022. Shell Hits Oil at Blacktip North in US GOM Shell has struck oil at the Blacktip North prospect located in the Alaminos Canyon block 336 in the deepwater US Gulf of Mexico. The Blacktip North well encountered about 300 ft net oil pay at multiple levels. The well was drilled to a total depth of 27,770 ft by Transocean drillship Deepwater Poseidon. Blacktip North is about 30 miles northeast of the Whale discovery, 4.5 miles northeast of the 2019 Blacktip discovery, and 42 miles from the Perdido spar hub platform. Shell operates the Blacktip North prospect with an 89.49% interest. Spain’s Repsol holds the remaining 10.51% stake. Petrobras Plans Equatorial Margin Drilling Program Petrobras is preparing to drill the first of 14 planned wells at South America’s new deepwater frontier, the Equatorial Margin at its Northern maritime border, a company executive told the World Petroleum Congress in December. Petrobras plans to invest $2 billion in exploration at the Equatorial Margin through 2026, Reservoir Executive Manager Tiago Homem said. The company estimates an overall investment of $2.5 billion in seismic activities over the same period. CLOV Tieback Goes Onstream Offshore Angola TotalEnergies, operator of Block 17 in Angola, has begun production from the CLOV Phase 2 project, connecting to the existing CLOV FPSO. The tieback project is expected to reach a production of 40,000 BOED in mid-2022. Located about 140 km from the Angolan coast, in water depths from 1100 to 1400 m, the CLOV Phase 2 resources are estimated at around 55 million BOE. Block 17 is operated by TotalEnergies with a 38% stake, Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd. (15.84%), and Sonangol P&P (5%). The contractor group operates four FPSOs in the main production areas of the block: Girassol, Dalia, Pazflor, and CLOV. Canacol Strikes Gas With Siku-1 in Colombia Canacol Energy’s Siku-1 exploration well encountered 33 ft true vertical depth of net gas pay with an average porosity of 20% within the primary Cienaga de Oro sandstone reservoir target. The company has completed casing the well and will return with a workover rig in early 2022 to complete and tie the well into permanent production. The well was drilled to a total depth of 8,825 ft. The rig was mobilized to drill the Clarinete-6 development well, which reached a total depth of 7,478 ft measured depth and encountered 174 ft true vertical depth of net gas pay. The well was tied into the Clarinete production manifold and has been placed on permanent production. Next up for the rig is the Toronja-2 development well, which is targeting gas-bearing sandstones within the Porquero sandstone reservoir. Following the completion of that well, the rig will be mobilized to spud the Carambolo-1 exploration well, expected in the second half of February. The well is expected to take 5 weeks to drill and complete.