Enabling a Digital Earth for methane emissions management with equal-area discrete global grids

Direct measurement of methane emissions from the upstream oil and gas sector: Review of measurement results and technology advances (2018–2022)

The aim of this study is to analyze the role of the upstream oil and gas sector within Indonesia's economy in terms of its linkage to other sectors and the multiplier effect it produces. The input-output (IO) analysis method is applied by calculating the total, backward, and forward linkage index and multiplier effect index values of the upstream oil and gas sector. Building upon a previous study using the 2005 BPS IO Database updated in 2010 (2005 IO), this study used the 2010 IO Database released by BPS in 2015 (2010 IO) and the 2016 IO Database released in 2021 (2016 IO), processing the data using Python-based software. Based on the calculation using 2010 IO Database, there were 93 sectors with linkage to the upstream oil sector and 104 with linkage to the upstream gas sector, whereas the 2016 IO Database identified 96 sectors with linkage to the upstream oil sector and 113 with linkage to the upstream gas sector. Simulated calculation and analysis results revealed that there was an increase in total (backward and forward) linkage index values of the upstream oil and gas sector, from 3.8801 to 4.0826 for the upstream oil sector and from 3.1256 to 3.3940 for the upstream gas sector. In regard with multiplier effect, simulated calculation results also pointed towards an increase in total multiplier index values, from 6.1855 to 7.8943 for the upstream oil sector and from 4.9828 to 6.5630 for the upstream gas sector. The increase in total multiplier index in the national upstream oil and gas sector correlates with an increase in linkage between the upstream oil and gas sector and other sectors in Indonesia's economy as a whole, both backward and forward. Analysis results showed that the greater the multiplier index reported by a sector with linkage to the upstream oil and gas sector, the greater the total multiplier index produced in the upstream oil and gas sector.

Canada was an early adopter of methane regulation in the oil and gas sector, and recently announced a more ambitious goal to reduce 75% of methane emissions by 2030. New stricter methane regulations should also help reduce loading of air pollutants typically associated with methane emissions (H2S, VOCs, ozone). To examine regional emission trends and to derive an inventory estimate for Canada’s upstream oil and gas sector, we measured methane emissions at 6650 sites across six major oil and gas producing regions in Canada. Our research suggests that methane emissions from the oil and gas industry are underestimated in Canada by ~1.5. For Canada’s largest producing province, Alberta, we found a greater than 1000-fold variation in methane intensity per unit of fossil energy production within the cohort of oil and gas producers. Producer self-published methane emission intensities in ESG materials showed a low bias and tended to mirror regulatory submissions that require reporting only on specific source types. Our measurements suggest that methane-associated pollutants produced by oil and gas activities are also underestimated and communities near these activities may face higher loading of methane-accessory contaminants than might be predicted by Canada’s National Pollutant Release Inventory (NPRI). Using accepted pollutant emission factors, reported flaring and other combustion activity, the federal methane inventory, and our methane measurements, we generated air quality exposure maps reflecting air pollutant loads on Canadian communities. Stricter methane regulation has the potential to significantly decrease methane, but also pollutant loads in several heavy oil communities including the Lloydminster - Bonnyville area.

Airborne measurements of methane emissions from oil and gas infrastructure were completed over two regions of Alberta, Canada. These top-down measurements were directly compared with region-specific bottom-up inventories that utilized current industry-reported flaring and venting volumes (reported data) and quantitative estimates of unreported venting and fugitive sources. For the 50 × 50 km measurement region near Red Deer, characterized by natural gas and light oil production, measured methane fluxes were more than 17 times greater than that derived from directly reported data but consistent with our region-specific bottom-up inventory-based estimate. For the 60 × 60 km measurement region near Lloydminster, characterized by significant cold heavy oil production with sand (CHOPS), airborne measured methane fluxes were five times greater than directly reported emissions from venting and flaring and four times greater than our region-specific bottom up inventory-based estimate. Extended across Alberta, our results suggest that reported venting emissions in Alberta should be 2.5 ± 0.5 times higher, and total methane emissions from the upstream oil and gas sector (excluding mined oil sands) are likely at least 25-50% greater than current government estimates. Successful mitigation efforts in the Red Deer region will need to focus on the >90% of methane emissions currently unmeasured or unreported.

Background: Adversity Quotient (AQ) is an essential concept for understanding an individual’s capacity to cope with adversity, including prolonged workplace stress that may lead to Emotional Mental Disorders (EMD), particularly among Onshore workers in the upstream oil and gas sector. Harsh physical work environments and psychosocial pressures place these workers at increased risk of developing EMD. Although AQ has been shown to correlate negatively with stress, no specific research has investigated the relationship between AQ and EMD in this population. Objective: This study aims to examine the relationship between AQ and EMD among Onshore workers in the upstream oil and gas.Methods: This was an observational analytic study with a cross-sectional design involving 155 high-risk Onshore workers in the upstream oil and gas sector. Data were collected using total sampling and measured through the Self-Reported Questionnaire-20 (SRQ-20) and the Adversity Response Profile (ARP). Data analysis was conducted using the Chi-square test and Fisher’s exact test.Results: Fisher’s test results, Adversity Quotient and emotional mental disorders were not significantly related (p = 0.47).Conclusion: There is no significant correlation between Adversity quotient (AQ) and emotional mental disorders onshore workers in the upstream sector oil and gas.

This research examines legal vacuums in the management of state assets derived from Cooperation Contracts (KKKS) in the upstream oil and gas sector in Indonesia. Despite a legal framework established by Law No. 22 of 2001 and Government Regulation No. 35 of 2004, field practices reveal discrepancies between regulations and implementation, leading to difficulties in the recording and reporting of assets, as well as the determination of depreciation values and operational costs. The impact of this legal vacuum not only affects state revenue and transparency but also has significant social and economic implications. Through case study analysis, this research suggests improvements to existing regulations, capacity building for KKKS, and strengthening oversight mechanisms to optimize the management of state assets in the upstream oil and gas sector.

Completing the Bridge to Nowhere: Prioritizing Oil and Gas Emissions Regulations in Western States

Achieving the Paris Agreement 1.5 C target requires a reversal of the growing atmospheric concentrations of methane, which is about 80 times more potent than CO 2 on a 20-year timescale. The Intergovernmental Panel on Climate Change (IPCC) Sixth Assessment Report stated that methane is underregulated, but little is known about the effectiveness of existing methane policies. In this review, we systematically examine existing methane policies across the energy, waste, and agriculture sectors. We find that currently only about 13% of methane emissions are covered by methane mitigation policies. Moreover, the effectiveness of these policies is far from clear, mainly because methane emissions are largely calculated using potentially unrepresentative estimates instead of direct measurements. Coverage and stringency are two major blind spots in global methane policies. These findings suggest that significant and underexplored mitigation opportunities exist, but unlocking them requires policymakers to identify a consistent approach for accurate quantification of methane emission sources alongside greater policy stringency. ll

Worldwide methane emission by various industrial sources is one of the important human concerns due to its serious climate and air-quality implications. This study investigates less-considered diffusive natural methane emissions from the world's largest oil sand deposits. An analytical model, considering the first-order methane degradation, in combination with Monte Carlo simulations, is used to quantitatively characterize diffusive methane emissions from Alberta's oil sands formations. The results show that the average diffusive methane emissions from Alberta's oil sands formations is 1.56 × 10−4 kg/m2/year at the 90th percentile of cumulative probability. The results also indicate an annual diffusive methane emissions rate of 0.857 ± 0.013 Million tons of CO2e/year (MtCO2e/year) from Alberta's oil sands formations. This finding suggests that natural diffusive leakages from the oil sands contribute an additional 1.659 ± 0.025 and 5.194 ± 0.079% to recent Canada's 2019 and Alberta's 2020 methane emission estimates from the upstream oil and gas sector, respectively. The developed model combined with Monte Carlo simulations can be used as a tool for assessing methane emissions and current inventories.

Methane emissions were measured at 6650 sites across six major oil and gas producing regions in Canada to examine regional emission trends, and to derive an inventory estimate for Canada’s upstream oil and gas sector. Emissions varied by fluid type and geographic region, with the heavy oil region of Lloydminster ranking highest on both absolute and intensity-based scales. Emission intensities varied widely for natural gas production, where older, low-producing developments such as Medicine Hat, Alberta showed high emission intensities, and newer developments in Montney, British Columbia showed emission intensities that are amongst the lowest in North America. Overall, we estimate that the Canadian upstream oil and gas methane inventory is underestimated by a factor of 1.5, which is consistent with previous studies of individual regions.

<div>Methane emissions were measured at ~7000 sites across major oil and gas producing regions in Canada to examine regional emission trends, and to derive an inventory estimate for Canada’s upstream oil and gas sector. Emissions varied by fluid type and geographic region, with the heavy oil region of Lloydminster ranking highest on both absolute and intensity-based scales. Emission intensities varied widely for natural gas production, where older, low-producing developments showed high emission intensities, and where emissions intensity in newer developments was amongst the lowest in North America. Emissions from offshore production were in-line with reported estimates. When allocated to individual producers, we found that methane emissions intensity varied more than 1000-fold as determined by geographical factors and infrastructure portfolio. Reporting and disclosure frameworks in Canada are improving but we found that producers could easily under-report emissions and emissions intensity if relying only on regulatory requirements. Overall, we estimate that the Canadian upstream oil and gas methane inventory is underestimated by a factor of 1.5, which is consistent with previous studies of individual regions. </div>

Iron oxide is the most important electron acceptor in paddy fields. We aimed to suppress the methane emission from paddy fields over the long term by single application of iron materials. A revolving furnace slag (RFS; 245 g Fe kg-1) and a spent disposable portable body warmer (PBW; 550 g Fe kg-1) were used as iron materials. Samples of a soil with a low iron level (18.5 g Fe kg-1), hearafter referred to as “a low-iron soil” and of a soil with a high iron level (28.5 g Fe kg-1), hearafter referred to as “an iron-rich soil,” were put into 3 L pots. At the beginning of the experiment, RFS was applied to the pots at the rate of 20 and 40 t ha-1, while PBW was applied at the rate of 10 t ha-1 only, and in the control both were not applied. Methane and nitrous oxide emissions from the potted soils with rice plants were measured by the closed chamber method in 2001 and 2002. When RFS was applied at the rates of 20 and 40 t ha-1 to the low-iron soil, the total methane emission during the cultivation period significantly decreased by 25–50% without a loss of grain yield. Applied iron materials clearly acted as electron acceptors, based on the increase in the amount of ferrous iron in soil. However, the suppressive effect was not evident in the iron-rich soil treated with RFS or PBW. On the other hand, nitrous oxide emission increased by 30–95%. As a whole, when the total methane and nitrous oxide emissions in the low-iron soil were converted to total greenhouse gas emissions expressed as CO2- C equivalents in line with the global warming potential, the total greenhouse gas emissions decreased by about 50% due to the application of RFS.

Abstract. Reducing methane emissions from the oil and gas (oil–gas) sector has been identified as a critically important global strategy for reducing near-term climate warming. Recent measurements, especially by satellite and aerial remote sensing, underscore the importance of targeting the small number of facilities emitting methane at high rates (i.e., “super-emitters”) for measurement and mitigation. However, the contributions from individual oil–gas facilities emitting at low emission rates that are often undetected are poorly understood, especially in the context of total national- and regional-level estimates. In this work, we compile empirical measurements gathered using methods with low limits of detection to develop facility-level estimates of total methane emissions from the continental United States (CONUS) midstream and upstream oil–gas sector for 2021. We find that of the total 14.6 (12.7–16.8) Tg yr−1 oil–gas methane emissions in the CONUS for the year 2021, 70 % (95 % confidence intervals: 61 %–81 %) originate from facilities emitting <100kgh-1 and 30 % (26 %–34 %) and ∼80 % (68 %–90 %) originate from facilities emitting <10 and <200kgh-1, respectively. While there is variability among the emission distribution curves for different oil–gas production basins, facilities with low emissions are consistently found to account for the majority of total basin emissions (i.e., range of 60 %–86 % of total basin emissions from facilities emitting <100kgh-1). We estimate that production well sites were responsible for 70 % of regional oil–gas methane emissions, from which we find that the well sites that accounted for only 10 % of national oil and gas production in 2021 disproportionately accounted for 67 %–90 % of the total well site emissions. Our results are also in broad agreement with data obtained from several independent aerial remote sensing campaigns (e.g., MethaneAIR, Bridger Gas Mapping LiDAR, AVIRIS-NG (Airborne Visible/Infrared Imaging System – Next Generation), and Global Airborne Observatory) across five to eight major oil–gas basins. Our findings highlight the importance of accounting for the significant contribution of small emission sources to total oil–gas methane emissions. While reducing emissions from high-emitting facilities is important, it is not sufficient for the overall mitigation of methane emissions from the oil and gas sector which according to this study is dominated by small emission sources across the US. Tracking changes in emissions over time and designing effective mitigation policies should consider the large contribution of small methane sources to total emissions.

Local Content in the Upstream Petroleum Sector of Ghana. How Well Is Ghana Doing So Far?

The Indonesian government continues to set oil and gas lifting targets every year. This is done to encourage the upstream oil and gas industry to increase lifting to meet national energy needs and optimize state revenue. However, these targets are often not achieved due to the low level of oil and gas exploration activities in Indonesia. Efforts to improve the business climate for upstream oil and gas activities are always carried out in various sectors, one of which is the management of goods and equipment for upstream oil and gas business activities. These goods and equipment are designated as State-Owned Assets (BMN) managed by the Indonesian government c.q. Ministry of Finance. In this regard, in order to encourage investment interest among investors in the upstream oil and gas sector and to pay attention to the mandate of Law 22 of 2001, it is necessary to carry out good management of upstream oil and gas assets so that it can assist Production Sharing Contractors (KKKS) in managing and providing assets needed in upstream oil and gas business activities. Good management of upstream oil and gas BMN can be carried out through adaptive policies so that it can meet every need and problem faced by KKKS, SKK Migas, and the Indonesian government. This adaptive policy will support the resolution of problems that have not been accommodated in normative regulations so that each legal subject can ensure the completion of its responsibilities in accordance with the provisions of laws and regulations.