Search

Hydrogen, primarily produced from steam methane reforming, plays a crucial role in oil refining, and provides a solution for the oil and gas industry's long-term energy transition by reducing CO2 emissions. This paper examines hydrogen’s role in this transition. Firstly, experiences from oil and gas exploration, including in-situ gasification, can be leveraged for hydrogen production from subsurface natural hydrogen reservoirs. The produced hydrogen can serve as fuel for generating steam and heat for thermal oil recovery. Secondly, hydrogen can be blended into gas for pipeline transportation and used as an alternative fuel for oil and gas hauling trucks. Additionally, hydrogen can be stored underground in depleted gas fields. Lastly, oilfield water can be utilized for hydrogen production using geothermal energy from subsurface oil and gas fields. Scaling up hydrogen production faces challenges, such as shared use of oil and gas infrastructures, increased carbon tax for promoting blue hydrogen, and the introduction of financial incentives for hydrogen production and consumption, hydrogen leakage prevention and detection.

Coal and natural gas have dominated ASEAN’s power sector in the past and contributed to 77% of power generation in 2019. To achieve net-zero by 2050, ASEAN countries need to decarbonize their power sector in the next three decades. This paper performs a technology screening exercise for ten decarbonization technologies for the power sector based on a holistic approach of sustainability, security, affordability, reliability, technology readiness and technology impact. This exercise has resulted in country-specific ranking of technologies which can inform policymakers of ASEAN countries. Overall speaking, simultaneous utilization of both fossil and non-fossil technologies is needed rather than waiting for certain technologies to mature. On the fossil side, switching from coal to gas for power generation and implementing carbon capture and storage (CCS) in coal- and gas-fired power plants have the highest decarbonization potential. Therefore, eleven first-mover CCS projects are proposed with the potential to mitigate up to 22% of energy-related CO2 emission in ASEAN in 2019. On the renewable side, hydropower has the highest potential but sustainability issues due to overdamming of the Mekong River needs to be addressed. Further addition of capacity will likely come from run-of-the-river hydropower plants. Within ASEAN, there is medium to high potential for further usage of agricultural resides as biomass for power generation, especially in Indonesia,​ Thailand, Malaysia and the Philippines. Solar photovoltaic (PV) has medium potential in ASEAN countries with high land mass but more research and development (R&D) is needed in grid improvement and energy storage technologies. Within ASEAN, wind energy suffers from a low average wind speed but there are exceptions. More R&D is needed in the deign of low wind speed wind turbines. Geothermal resources are found only in Indonesia and the Philippines and are under-utilized. Further implementation will require favorable government polices to incentivize private investment and streamlining permitting, among others. Energy policies that promote rapid decarbonization of ASEAN’s power sector based on our findings are also discussed.

The objective of this paper is to derive, for the first time, decarbonization roadmaps for the ten nations of ASEAN. This study first presents a regional view of ASEAN’s fossil and renewable energy usage and energy-related CO2 emission. Results show that renewable energies have been losing ground to fossil energies in the last two decades and fossil fuels will likely continue to be an important part of ASEAN’s energy mix for the next few decades. Therefore, decarbonizing efforts should focus not only on increasing the share of renewable energies in electricity generation, but also on technologies to reduce CO2 emission from fossil power and industrial plants. This study next performs a technology mapping exercise for all ten ASEAN countries to determine decarbonization technologies that have high impact and high readiness for individual countries. Besides installing more sustainable renewable energies, common themes coming from these roadmaps include switching from coal to gas for power generation, using carbon capture and storage (CCS) technologies to decarbonize fossil and industrial plants, replacing internal combustion vehicles by electric vehicles, and for countries that have coal and natural gas resources, upgrading them to blue hydrogen by chemical processes and using CCS to mitigate the emitted CO2. Blue hydrogen can be used to decarbonize hard-to-decarbonize industries. Policy implications of these roadmaps include imposing a credible carbon tax, establishing a national hydrogen strategy, intergovernmental coordination to establish regional CCS corridors, funding research and development to improve carbon capture efficiency on a plant level and resolving sustainability issues of hydropower and bioenergy in ASEAN.

In this paper, opportunities for carbon capture and storage (CCS) in India’s west coast is investigated. Specifically, CO2 emissions from the power and industry sectors in the states of Maharashtra and Gujarat and subsurface sinks to store them in oil fields, gas fields or saline aquifers in the closest sedimentary basins are quantified on a plant-by-plant and field-by-field basis.Results indicate that CO2 emission from these two states is 221 Mtpa and 115 Mtpa from the power and industry sectors, respectively. The mid CO2 storage capacity in nearby sedimentary basins is 141 Gt, enough to store 420 years of CO2 emission. Of this, 137 Gt (97.4%) come from saline aquifers, 2.23 Gt (1.6%) from gas fields, and only 1.4 Gt (1.0%) from oil fields. Furthermore, CO2 injection has the potential of recovering 2,620 MMbbl from oil fields and 118 MMbbl from gas fields through enhanced oil recovery (EOR) and enhanced gas recovery (EGR), respectively. The most significant CO2-EOR potential (1,453 MMbbl) is in the offshore Mumbai High oil field. Currently, most gas fields are under primary production and, therefore, will only be ready for CO2 storage when they are near depletion.Results of a CO2 source–sink mapping exercise suggest using four CCS hubs to connect regional CO2 sources and sinks. They are Mumbai, Nagpur and Chandrapur in the state of Maharashtra and Hazira in the state of Gujarat. These hubs can be used to temporarily store CO2 before it is transported to nearby oil fields or saline aquifers for permanent storage. Implementation of CCS projects based on these hubs can remove up to 168 Mtpa CO2 or 50% of stationary emission of these two states with a CO2 source–sink distance of 150 km or less, thus making a significant contribution to India’s decarbonization.

A review of global CO2 emissions over the last century shows that emissions from 80 economies contributed to 95% of global emissions. Among them, 55 economies were decarbonizers, where CO2 emissions had either plateaued or were declining, while 25 economies were polluters, where CO2 emissions were still increasing. In 2021, the global CO2 emissions were 37.1 Gtpa, with 56% coming from polluters and 39% from decarbonizers. If current trends continue, global CO2 emissions will reach 49.6 Gtpa by 2050, with 81% coming from polluters and 14% from decarbonizers. Only 14 economies will reach net zero. The decarbonization target, over and above current efforts, to achieve net zero is calculated for each economy. Decarbonizers need to mitigate 230 Mtpa CO2 and polluters 1365 Mtpa CO2 beginning in 2021 to reach the net-zero target by 2050. This target will increase each year decarbonization is delayed. Analyses show that renewable energies’ share in the total final energy consumption in most economies increased by an average of only 4 percentage points in the last decade, which is inadequate for achieving net zero by 2050. Other means of decarbonization, including low-carbon fossil solutions through carbon capture and storage, will be needed. Pathways to accelerate decarbonization are proposed and their policy implications are discussed.

This paper proposes decarbonization pathways for Thailand based on a review of the status of renewable and fossil energies, technology evaluation and scenario studies. Results show that renewable electricity generation needs to grow at a 7.1% average annual growth rate (AAGR) between now and 2050 for the power sector to achieve net-zero by 2050. This would require it to reach 400 TWh, exceeding its technical potential. We propose a more achievable scenario of between 5% and 6% AAGR wherein renewable electricity will grow from 51 TWh to 217–291 TWh between 2020 and 2050. Gas-powered electricity will grow from 127 TWh to 185–111 TWh, requiring carbon capture and storage (CCS) to mitigate 75–45 Mtpa CO2 by 2050. For the transport sector, electric vehicles have the highest decarbonization potential, but they would add 45 TWh of electricity demand by 2050. For the industry sector, installing CCS in existing plants has the highest decarbonization potential. Overall, CCS is a key decarbonization technology and its large-scale implementation will be needed for Thailand to achieve net-zero by 2050.

The ten nations of Southeast Asia, collectively known as ASEAN, emitted 1.65 Gtpa CO2 in 2020, and are among the most vulnerable nations to climate change, which is partially caused by anthropogenic CO2 emission. This paper analyzes the history of ASEAN energy consumption and CO2 emission from both fossil and renewable energies in the last two decades. The results show that ASEAN’s renewable energies resources range from low to moderate, are unevenly distributed geographically, and contributed to only 20% of total primary energy consumption (TPEC) in 2015. The dominant forms of renewable energies are hydropower, solar photovoltaic, and bioenergy. However, both hydropower and bioenergy have substantial sustainability issues. Fossil energies depend heavily on coal and oil and contribute to 80% of TPEC. More importantly, renewable energies’ contribution to TPEC has been decreasing in the last two decades, despite the increasing installation capacity. This suggests that the current rate of the addition of renewable energy capacity is inadequate to allow ASEAN to reach net-zero by 2050. Therefore, fossil energies will continue to be an important part of ASEAN’s energy mix. More tools, such as carbon capture and storage (CCS) and hydrogen, will be needed for decarbonization. CCS will be needed to decarbonize ASEAN’s fossil power and industrial plants, while blue hydrogen will be needed to decarbonize hard-to-decarbonize industrial plants. Based on recent research into regional CO2 source-sink mapping, this paper proposes six large-scale CCS projects in four countries, which can mitigate up to 300 Mtpa CO2. Furthermore, this paper identifies common pathways for ASEAN decarbonization and their policy implications.

As a signatory to the Paris Agreement, Singapore is committed to achieving net-zero carbon emissions in the second half of the century. In this paper, we propose a decarbonization roadmap for Singapore based on an analysis of Singapore’s energy landscape and a technology mapping exercise. This roadmap consists of four major components. The first component, which also underpins the other three components, is using centralized post-combustion carbon capture technology to capture and compress CO2 emitted from multiple industrial sources in Jurong Island. The captured CO2 is then transported by ship or an existing natural gas pipeline to a neighboring country, where it will be stored permanently in a subsurface reservoir. Important to the success of this first-of-a-kind cross-border carbon capture and storage (CCS) project is the establishment of a regional CCS corridor, which makes use of economies of scale to reduce the cost of CO2 capture, transport, and injection. The second component of the roadmap is the production of hydrogen in a methane steam reforming plant which is integrated with the carbon capture plant. The third component is the modernizing of the refining sector by introducing biorefineries, increasing output to petrochemical plants, and employing post-combustion carbon capture. The fourth component is refueling the transport sector by introducing electric and hydrogen fuel cell vehicles, using biofuels for aviation and hydrogen for marine vessels. The implications of this roadmap on Singapore’s energy policies are also discussed.

Wettability alteration was proposed as one of the enhanced oil recovery (EOR) mechanisms for nanoparticle fluid (nanofluid) flooding. The effect of nanoparticle adsorption on wettability alteration was investigated by wettability index measurement of Berea sandstone core injected with nanofluids and by contact angle measurement of a glass surface treated with nanofluids. Nanoparticle adsorption was studied by single phase coreflooding with nanofluids in Berea sandstone. The adsorption isotherm and the impact of adsorption on the effective permeability were investigated by measuring the effluent nanoparticle concentration and differential pressure across the core. Results showed that hydrophilic nanoparticles (e.g., fumed silica) made the core slightly more water wet, and hydrophobic nanoparticles (e.g., silane modified fumed silica) delayed spontaneous imbibition but could not alter the original wettability. It was found that hydrophilic nanoparticles treatment reduced contact angle between oil and water by about 10 to 20 degree for a glass surface. Results also showed that different types of nanoparticle have different adsorption and desorption behavior and different ability to impair the permeability of Berea sandstones cores.

To be effective enhanced oil-recovery (EOR) agents, nanoparticles must be stable and be transported through a reservoir. However, the stability of a nanoparticle suspension at reservoir salinity and temperature is still a challenge and how it is affected by reservoir rocks and crude oils is not well understood. In this work, for the first time, the effect of several nanoparticle treatment approaches on the stability of silica nanoparticles at reservoir conditions (in the presence of reservoir rock and crude oil) was investigated for EOR applications. The stability of nanoparticle suspensions was screened in test tubes at 70 °C and 3.8 wt. % NaCl in the presence of reservoir rock and crude oil. Fumed silica nanoparticles in suspension with hydrochloric acid (HCl), polymer-modified fumed nanoparticles and amide-functionalized silica colloidal nanoparticles were studied. The size and pH of nanoparticle suspension in contact with rock samples were measured to determine the mechanism for stabilization or destabilization of nanoparticles. A turbidity scanner was used to quantify the stability of the nanoparticle suspension. Results showed that both HCl and polymer surface modification can improve nanoparticle stability under synthetic seawater salinity and 70 °C. Suspensions of polymer-modified nanoparticles were stable for months. It was found that pH is a key parameter influencing nanoparticle stability. Rock samples containing carbonate minerals destabilized unmodified nanoparticles. Crude oil had limited effect on nanoparticle stability. Some components of crude oil migrated into the aqueous phase consisting of amide-functionalized silica colloidal nanoparticles suspension. Nanoparticles modification or/and stabilizer are necessary for nanoparticle EOR application.

Water uptake induced by fluid−rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 °C or 120 °C. Furthermore, samples’ topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy−field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.

In coalbed-methane (CBM) projects, conventional logs, such as density were used heavily for coal identification, coal-property derivation, and also potentially for coal ranking. This paper presents a novel work flow of density-log normalization for CBM wells. It addresses two major challenges to current normalization methods: absence of a pervasive reference layer and removal of geological effects after normalization. To overcome these disadvantages, the proposed work flow undertakes six steps, which are data quality control (QC), geological- area segmentation, subarea type-well selection, density-control points, variable linear transformation and normalized-log result QC with box plots, matrix crossplots, and several histograms. This work flow removes the systematic errors caused by acquiring logs at different times with different logging instruments provided by different vendors. Furthermore, it possesses the advantages of the automated QC work flow, type-well control, and reference-layer methods without incurring their respective disadvantages. It was applied successfully to approximately 600 wells covering a large area in the Surat basin of Australia. Proper log normalization will reduce the uncertainties involved in 3D geological modeling and will increase the accuracy of reservoir evaluation. This paper should therefore be of interest to petrophysicists and geologists involved in CBM-field characterization. [ABSTRACT FROM AUTHOR]

The development of a coalbed-methane (CBM) field in its early stage is often plagued by the lack of well control and the scarcity of geological data across a large geographical area. Therefore, constructing a representative static model to estimate the in-place volume presents a formidable challenge. In this paper, we propose a work flow to overcome this challenge and apply it to a CBM field in the northern Bowen basin of Australia. One may consider this work flow as a best practice for the following reasons. First, it makes use of data from various sources including cores, well logs, seismic interpretation, and topography. Second, it performs rigorous quality control on these data, such as depth shift and log normalization. Third, coal-ply division and correlation and subsequent structural modeling are based on three types of correlation: well-to-well, well-to-seismic, and well-seismic- geographic information system. Fourth, it establishes the low, base, and high trends for the most-important reservoir properties. Fifth, it constructs a base-case static model by combining the aforementioned structural and reservoir-property models. Sixth, it uses sensitivity analysis, which varies one reservoir parameter at a time, to rank the impact of reservoir parameters on in-place volume. Seventh, it uses uncertainty analysis that varies all reservoir parameters simultaneously to arrive at the P10, P50, and P90 in-place volumes and their corresponding static models that one can use for reservoir simulations to estimate the recoverable volumes. [ABSTRACT FROM AUTHOR]

Discusses the deployment of expandable sand screen in offshore fields in Brunei. Drill-in-fluid; Borehole stability; Mud/shale interaction; Deformation of expandable sand screen.