Gas Supply Chain Research Articles

Hydrocarbon trade deflection and supply‑chain trade restructuring under sanctions imposed during theRussia–Ukraine conflict

In response to international sanctions, Russia has restructured its hydrocarbon commerce through trade deflection, redirecting exports from sanctioning to non-sanctioning countries. Theresearch aimed to analyze hydrocarbon trade deflection under theRussia–Ukraine conflict within thecontext of theChina–Russia Strategic Partnership and BRICS, and to assess therestructuring of Russia’s crude oil and natural gas supply chains from 2020 to 2023. Two questions were addressed: Whether trade deflection shifted towards non-sanctioning countries, including China and other BRICS countries; whether Russia’s oil and gas supply chains were restructured towards these regions? Design incorporates themethod developed by theauthor which generates and utilizes an integrated database of Bill of Lading and export data to analyze supply-chain trade restructuring, identifying specific shifts in trade flows by product, country, and enterprises. Findings reflected that after sanctions were imposed in early 2022, Russian hydrocarbon exports to sanctioning countries declined sharply, while exports to non-sanctioning countries, particularly China and India, increased significantly. Findings demonstrate theeffectiveness of trade deflection as a strategic response to sanctions. This strategy has mitigated theadverse impacts on Russian oil and gas industry, with significant increases in exports to China and India. TheComprehensive Strategic Partnership with China has helped secure a substantial market for Russian crude oil and increased China’s energy security. This study enhances understanding of trade deflection mechanisms and provides a framework for analyzing theinterplay between international trade, geopolitical strategies, and economic resilience. Geopolitical alliances and trade partnerships have ensured ­resilience and continuity in global trade. This shift indicates strategic diversification towards Asian markets and increased Central Asian involvement. BRICS engagement has provided Russia with a platform to advocate for energy security and challenge Western dominance in global energy governance. Future research should explore other supply-chain components and analyze trade within theBRICS+ group and Russia–China bilateral trade.

Integrated risk management and maintenance planning in Oil and Gas Supply Chain operations under market uncertainty

The Oil and Gas Supply Chain (OGSC) is a multifaceted network comprising diverse activities and echelons. Instability or interruptions can cause economic fluctuations, impacting industries, markets, and consumers. Maintenance activities, which pause production but extend facilities' life, are recommended during non-peak demand periods to avoid production losses and meet customer demand. To mitigate these effects, decisions on operations planning, maintenance scheduling, and maintenance team assignments should be optimized in a risk management framework. The proposed model adopts a mixed-integer linear programming (MILP) framework and is solved via a sequential approach that incorporates the relax-and-fix (RF) heuristic in order to find a solution that is close to optimal. Subsequently, the solution serves as an initial solution for the CPLEX solver, which employs a branch-and-cut algorithm to attain the exact optimal solution. The practicality of this model has been showcased through its application to the supply chain in Saudi Arabia. The model efficiently schedules maintenance activities evenly and consistently across the OGSC plants over the planning period to reduce lost sales by keeping plants operational during high-demand periods. Furthermore, a sensitivity analysis was conducted to investigate the influence of the decision-maker's risk attitude on the outcomes that were obtained.

Constructing a measurement-based spatially explicit inventory of US oil and gas methane emissions (2021)

Abstract. Accurate and comprehensive quantification of oil and gas methane emissions is pivotal in informing effective methane mitigation policies while also supporting the assessment and tracking of progress towards emissions reduction targets set by governments and industry. While national bottom-up source-level inventories are useful for understanding the sources of methane emissions, they are often unrepresentative across spatial scales, and their reliance on generic emission factors produces underestimations when compared with measurement-based inventories. Here, we compile and analyze previously reported ground-based facility-level methane emissions measurements (n=1540) in the major US oil- and gas-producing basins and develop representative methane emission profiles for key facility categories in the US oil and gas supply chain, including well sites, natural-gas compressor stations, processing plants, crude-oil refineries, and pipelines. We then integrate these emissions data with comprehensive spatial data on national oil and gas activity to estimate each facility's mean total methane emissions and uncertainties for the year 2021, from which we develop a mean estimate of annual national methane emissions resolved at 0.1° × 0.1° spatial scales (∼ 10 km × 10 km). From this measurement-based methane emissions inventory (EI-ME), we estimate total US national oil and gas methane emissions of approximately 16 Tg (95 % confidence interval of 14–18 Tg) in 2021, which is ∼ 2 times greater than the EPA Greenhouse Gas Inventory. Our estimate represents a mean gas-production-normalized methane loss rate of 2.6 %, consistent with recent satellite-based estimates. We find significant variability in both the magnitude and spatial distribution of basin-level methane emissions, ranging from production-normalized methane loss rates of < 1 % in the gas-dominant Appalachian and Haynesville regions to > 3 %–6 % in oil-dominant basins, including the Permian, Bakken, and the Uinta. Additionally, we present and compare novel comprehensive wide-area airborne remote-sensing data and results for total area methane emissions and the relative contributions of diffuse and concentrated methane point sources as quantified using MethaneAIR in 2021. The MethaneAIR assessment showed reasonable agreement with independent regional methane quantification results in sub-regions of the Permian and Uinta basins and indicated that diffuse area sources accounted for the majority of the total oil and gas emissions in these two regions. Our assessment offers key insights into plausible underlying drivers of basin-to-basin variabilities in oil and gas methane emissions, emphasizing the importance of integrating measurement-based data when developing high-resolution spatially explicit methane inventories in support of accurate methane assessment, attribution, and mitigation. The high-resolution spatially explicit EI-ME inventory is publicly available at https://doi.org/10.5281/zenodo.10734299 (Omara, 2024).

A MILP-based approach to address the production and distribution planning of large industrial gas supply chains

This paper focuses on addressing the Production Routing Problem (PRP) of industrial gas supply chains (SC). The work introduces a Mixed-Integer Linear Programming (MILP) based approach to effectively tackle this challenging problem. The proposed framework aims to increase company profits by optimizing both production and distribution activities simultaneously. For the distribution part, a route generation algorithm is employed to initially generate a set of feasible routes, ensuring that only routes with practical significance are considered. Subsequently, the mathematical model is developed considering only the set of routes generated. The formulation includes decisions associated with plants production levels, plant selection to supply the different consumers, clients to be visited per trip and day, quantity to be delivered and routes to be used. As part of the problem, it is considered that trucks can make several trips per day, as well as trips of several days. To take into account the last feature, the approach accounts for the explicit effect of the lead time on production and distribution decisions. In this way, the work allows for different delivery times for customers included in the same route, according to their inventories and usage levels. The model considers fleet unavailability until they return to the plants after finishing a trip. Finally, two case studies, one motivating and the other industrial size, are presented and solved. The results obtained demonstrate the effectiveness of the proposed approach to solve the case studies in reasonable CPU times.

Challenges and Countermeasures of Natural Gas Supply Chain Management in China

Challenges and Countermeasures of Natural Gas Supply Chain Management in China

Planning natural gas supply chain pathways for energy system decarbonisation: An Australian case study

The future role of natural gas systems in a deeply decarbonised world is very uncertain. This work seeks to characterise the changes that the clean energy transition is likely to induce in the natural gas chain, across extraction and transmission, distribution networks and gas consumption/use trends, for various scenarios with different demand and supply drivers. First, the results of a least-cost macro-scale energy system planning optimisation are explored to identify future natural gas demand and supply requirements. Second, those findings are used as inputs to a detailed analysis of the full gas supply chain, from extraction to final use, to examine the evolution of i) stored resource levels; ii) transmission and distribution networks operation and financing; and iii) required capacity and siting of gas generation; all, with a realistic account of the related infrastructure. Australia is investigated as a case study that relies on natural gas for both domestic and export purposes. Results project a shift towards a more localised gas consumption to be largely supplied by fewer basins, with associated potential transmission and extraction bottlenecks. They anticipate an overall less utilised, ageing distribution network with potential challenges to asset reliability and financing. Finally, they demonstrate both the scheduled and early retirement of fossil generation assets can allow the siting of considerable amounts of new gas power firming capacity on brownfield sites, thus offering an opportunity to reduce total system costs.

Methane Quantification Performance of the Quantitative Optical Gas Imaging (QOGI) System Using Single-Blind Controlled Release Assessment.

Quantitative optical gas imaging (QOGI) system can rapidly quantify leaks detected by optical gas imaging (OGI) cameras across the oil and gas supply chain. A comprehensive evaluation of the QOGI system's quantification capability is needed for the successful adoption of the technology. This study conducted single-blind experiments to examine the quantification performance of the FLIR QL320 QOGI system under near-field conditions at a pseudo-realistic, outdoor, controlled testing facility that mimics upstream and midstream natural gas operations. The study completed 357 individual measurements across 26 controlled releases and 71 camera positions for release rates between 0.1 kg Ch4/h and 2.9 kg Ch4/h of compressed natural gas (which accounts for more than 90% of typical component-level leaks in several production facilities). The majority (75%) of measurements were within a quantification factor of 3 (quantification error of -67% to 200%) with individual errors between -90% and 831%, which reduced to -79% to +297% when the mean of estimates of the same controlled release from multiple camera positions was considered. Performance improved with increasing release rate, using clear sky as plume background, and at wind speeds ≤1 mph relative to other measurement conditions.

Charting the Course: The National Petroleum Council’s Advice on the Role of Emission Detection and Quantification in Reducing Greenhouse Gas Emissions from the U.S. Natural Gas Supply Chain

Charting the Course: The National Petroleum Council’s Advice on the Role of Emission Detection and Quantification in Reducing Greenhouse Gas Emissions from the U.S. Natural Gas Supply Chain

Information Technology, Dynamic Capabilities, and Strategic Planning in the Oil and Gas Supply Chain

Information Technology, Dynamic Capabilities, and Strategic Planning in the Oil and Gas Supply Chain

On the cost of zero carbon electricity: A techno-economic analysis of combined cycle gas turbines with post-combustion CO2 capture

To achieve a sustainable electricity grid, affordable and dispatchable power capacity that supports grid stability and does not increase atmospheric CO2 levels will be required. Combined cycle gas turbines (CCGTs) with post-combustion CO2 capture (PCC) can meet these requirements by capturing and permanently storing all combustion CO2 emissions and, coupled with negative emissions technologies, any remaining life-cycle emissions. For the first time, we present a comprehensive analysis of the technical and financial challenges of producing zero-carbon electricity from CCGTs on a life-cycle basis. We conclude that when the design is optimised, fossil CO2 capture fractions can be increased from 96% to 100% with minimal process modification, commercially available technology and an additional 0.5% decrease in thermal efficiency. This represents a significant 60–70% reduction in the additional efficiency penalty required to reach zero CO2 emission operation. The Cost of CO2 Avoided of 100% fossil CO2 capture is just 128 £/tCO2, a 3 £/tCO2 increase over the 95% gross CO2 capture fraction required to permit PCC projects in the UK. Indeed, within the bounds of the UK power CCS business model, we show that 100% fossil CO2 capture maximises both variable and capacity payments to the producer, resulting in a 2% decrease in the cost of power produced. For zero-carbon electricity on a life-cycle basis, the recapture and permanent geological storage of all remaining life-cycle CO2e emissions from plant construction & decommissioning, CO2 T&S network operation and the natural gas supply chain (operational CO2e emissions and methane leakage) increases the median Cost of CO2 Avoided to 178 £/tCO2 (130–371 £/tCO2), leading to the novel conclusion that a market mechanism equating to a CO2 price of over 178£/tCO2 is likely sufficient to incentivise the development of truly CO2-neutral CCGTs.

First validation of high-resolution satellite-derived methane emissions from an active gas leak in the UK

Abstract. Atmospheric methane (CH4) is the second-most-important anthropogenic greenhouse gas and has a 20-year global warming potential 82 times greater than carbon dioxide (CO2). Anthropogenic sources account for ∼ 60 % of global CH4 emissions, of which 20 % come from oil and gas exploration, production and distribution. High-resolution satellite-based imaging spectrometers are becoming important tools for detecting and monitoring CH4 point source emissions, aiding mitigation. However, validation of these satellite measurements, such as those from the commercial GHGSat satellite constellation, has so far not been documented for active leaks. Here we present the monitoring and quantification, by GHGSat's satellites, of the CH4 emissions from an active gas leak from a downstream natural gas distribution pipeline near Cheltenham, UK, in the spring and summer of 2023 and provide the first validation of the satellite-derived emission estimates using surface-based mobile greenhouse gas surveys. We also use a Lagrangian transport model, the UK Met Office's Numerical Atmospheric-dispersion Modelling Environment (NAME), to estimate the flux from both satellite- and ground-based observation methods and assess the leak's contribution to observed concentrations at a local tall tower site (30 km away). We find GHGSat's emission estimates to be in broad agreement with those made from the in situ measurements. During the study period (March–June 2023) GHGSat's emission estimates are 236–1357 kg CH4 h−1, whereas the mobile surface measurements are 634–846 kg CH4 h−1. The large variability is likely down to variations in flow through the pipe and engineering works across the 11-week period. Modelled flux estimates in NAME are 181–1243 kg CH4 h−1, which are lower than the satellite- and mobile-survey-derived fluxes but are within the uncertainty. After detecting the leak in March 2023, the local utility company was contacted, and the leak was fixed by mid-June 2023. Our results demonstrate that GHGSat's observations can produce flux estimates that broadly agree with surface-based mobile measurements. Validating the accuracy of the information provided by targeted, high-resolution satellite monitoring shows how it can play an important role in identifying emission sources, including unplanned fugitive releases that are inherently challenging to identify, track, and estimate their impact and duration. Rapid, widespread access to such data to inform local action to address fugitive emission sources across the oil and gas supply chain could play a significant role in reducing anthropogenic contributions to climate change.

Energy markets restructure beyond 2022 and its implications on Qatar LNG sales strategy: Business forecasting and trend analysis

The emergence of new suppliers and energy resources has reshaped the energy market in terms of contractual structures and pricing systems. The market shifts were accelerated in response to the latest Russian-Ukraine crisis, impacting natural gas supply chains from financing projects to contracting volumes. The increased demand for liquified natural gas volumes intensified the need to switch from long-term oil-indexed contracts to short-term gas-indexed contracts. Those shifts were anticipated to influence the selling strategies for the expected added 49 MTPA of Qatari LNG, wherein increasing the share of spot selling would be reflected in higher economic performance. This study used forecasted prices to investigate potential Qatari LNG selling strategies. Initially, projections of the most dominant pricing systems used for pricing Qatari LNG (i.e., brent, Henry Hub, Title Transfer Facility, and Japan Korea Marker) were estimated between 2023 and 2040. While Qatar has been relying on long-term oil-indexed contracts, the second step estimated annual LNG revenues under different combinations of selling strategies (i.e., long-term and spot sales). Finally, the influence of varying brent slopes on the estimated revenues was measured. Due to data limitations and non-stationarity, the double exponential smoothing model was selected among the different tested models. Considering current market dynamics, forecasts of the double exponential smoothing model showed an upward price trend until 2040. An annual average increase of 1.24% for the studied pricing systems was reported. Reducing the share of long-term brent-indexed contracts to 70% and dedicating the remaining 30% of volumes to spot sales yielded the highest premiums for revenue estimates. An average annual revenue of $62 bn was reported for the 70/30 strategy, around 6% higher than the 100% brent-indexed contracts strategy. The findings revealed that diversifying the selling approach and introducing spot sales can enhance revenues. From the buyers’ perspective, the outcomes support policymakers in understanding the implications of escalated prices driven by a lack of liquidity investments.

Multi-objective optimization of straw-based bio-natural gas supply chains considering cost, CO2 emission, and safety

Bio-natural gas (BNG) has received recent interest as a renewable alternative to natural gas (NG). BNG supply chains (BSC), including production, transportation, and utilization, are compatible and can overlap with existing NG infrastructure. The goal is to develop a set of models that achieve the various trade-offs between economic, environmental and safety risks by combining life cycle assessment (LCA), mixed-integer linear programming (MILP) and fuzzy optimization, expanding the utilization of BSC while quantifying the risk of the whole process, so as to improve the safety awareness of the project operation. BNG technologies were considered: anaerobic digestion (AD), gasification, and syngas methanation. This model can analyze the changes in the different objectives of each module and the distribution of biomass mass flow by comparing different straw-based harvesting rates. Results indicate that AD technology possesses the lowest economic cost, and BNG as transportation fuel will generate the most benefits. The unit cost of BNG for different technologies ranges from 0.36 to 0.67 $/m³，the emission reduction is from 5.18 kg/m³ to 10.28 kg/m³，and the maximum safety risk value is 1.96. The proposed model was applied to a case study in China to illustrate the optimization of a regional straw-based BSC. The results illustrate how BNG supply chains can be systematically planned as part of an integrated decarbonization policy while mitigating safety risks that may occur from handling this fuel.

Temporal Variation and Persistence of Methane Emissions from Shallow Water Oil and Gas Production in the Gulf of Mexico.

Methane emissions from the oil and gas supply chain can be intermittent, posing challenges for monitoring and mitigation efforts. This study examines shallow water facilities in the US Gulf of Mexico with repeat atmospheric observations to evaluate temporal variation in site-specific methane emissions. We combine new and previous observations to develop a longitudinal study, spanning from days to months to almost five years, evaluating the emissions behavior of sites over time. We also define and determine the chance of subsequent detection (CSD): the likelihood that an emitting site will be observed emitting again. The average emitting central hub in the Gulf has a 74% CSD at any time interval. Eight facilities contribute 50% of total emissions and are over 80% persistent with a 96% CSD above 100 kg/h and 46% persistent with a 42% CSD above 1000 kg/h, indicating that large emissions are persistent at certain sites. Forward-looking infrared (FLIR) footage shows many of these sites exhibiting cold venting. This suggests that for offshore, a low sampling frequency over large spatial coverage can capture typical site emissions behavior and identify targets for mitigation. We further demonstrate the preliminary use of space-based observations to monitor offshore emissions over time.

Assessing Risks on China’s Natural Gas Supply under Carbon Peaking Policies from Foreign–Domestic Perspectives

China’s natural gas supply has been challenged in the past few years by non-traditional risks such as trading conflicts, the COVID-19 pandemic, and the country’s own emission policy. To ensure energy security and supply, conducting an up-to-date risk analysis of China’s natural gas supply status is crucial. This research utilized the Fuzzy-AHP method to compose a risk index and assessed the key links within China’s natural gas supply chain from the import side to the domestic side. The results indicate that (a) for China’s gas import, the most influential risks are the correlated dependence risk, international relation risk, and supplier internal stability risk. (b) While the dependence risk and transport risk have decreased sharply in the past decade, the import risk is still China’s major concern on natural gas supply. (c) Emissions-peaking and carbon neutrality targets are potential challenges, which the country would possibly face in the near future.

Extended CSF-CoCoSo Method: A Novel Approach for Optimizing Logistics in the Oil and Gas Supply Chain

Extended CSF-CoCoSo Method: A Novel Approach for Optimizing Logistics in the Oil and Gas Supply Chain

Research on Petroleum Industry Supply Chain in China: Performance and Predictive Analysis of Sinopec Group

As a major producer of oil and gas, China has historically adopted a variety of different approaches to managing its overall oil and gas supply chain. It also incorporates decisions and forecasts of trends in the overall petroleum supply chain in the context of existing domestic and international societal trends, such as the impact of national policies and the supply chains of China’s domestic petrochemical companies in the context of Sinopec’s past annual reports and assessments and recommendations for sustainable supply chains. This article uses the case study of Sinopec, a major Chinese chemical company, to provide statistics on the domestic market context and to propose and discuss risk management and sustainable supply chains for the company’s supply chain, as well as quantitative analysis to forecast and analyze China’s domestic oil consumption, with case studies and data on all indicators, and to show the impact of plans and trends on the chemical supply chain over time. The implications and trends of developing trends in the chemical supply chain are presented, and conclusions and final recommendations are drawn.

Evolutionary algorithms for integrated oil and gas supply chain management considering enhanced oil recovery methods

Evolutionary algorithms for integrated oil and gas supply chain management considering enhanced oil recovery methods

Assessment of methane emissions from pressure regulation stations in China

Pressure regulation stations are responsible for transporting natural gas downstream and are an indispensable part of the gas supply chain. In recent years, countries and enterprises have attached increasing importance to methane emission accounting. However, methane emissions from pressure regulation stations are still not comprehensively understood and accounted for. In this study, methane emissions from 21 pressure regulation stations under normal conditions were quantified using the Environmental Protection Agency's (EPA's) “Other Test Method 33 A” (OTM 33 A) in three regions of China: the eastern, northern, and central regions of China. The results showed that the emission rate from pressure regulation stations generally lied in the order of 10−1-10−3 kg/h, whereas the measured methane emission rate (MMER) with 95% confidence interval (95%CI) was 0.671 (0.066, 3.040) (kg/h), which was determined from the bootstrapping measurements from all pressure regulation stations. The MMER (95%CI) values were 0.051 (0.026, 0.102) for East China, 2.263 (0.095, 8.317) for North China, and 0.004 (0.003, 0.005) (kg/h) for Central China, showing a relatively obvious skewed distribution. Overall, MMER had a diminutive correlation with gas throughput and pipeline pressure. In contrast, the degree of correlation of pipeline pressure was higher than that of gas throughput.

Evolutionary algorithms for integrated oil and gas supply chain management considering enhanced oil recovery methods

Evolutionary algorithms for integrated oil and gas supply chain management considering enhanced oil recovery methods