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An aqueous suspension of silica nanoparticles or nanofluid can alter the wettability of surfaces, specifically by making them hydrophilic and oil-repellent under water. Wettability alteration by nanofluids have important technological applications, including for enhanced oil recovery and heat transfer processes. A common way to characterize the wettability alteration is by measuring the contact angles of an oil droplet with and without nanoparticles. While easy to perform, contact angle measurements do not fully capture the wettability changes to the surface. Here, we employed several complementary techniques, such as cryo-scanning electron microscopy, confocal fluorescence and reflection interference contrast microscopy and droplet probe atomic force Microscopy (AFM), to visualize and quantify the wettability alterations by fumed silica nanoparticles. We found that nanoparticles adsorbed onto glass surfaces to form a porous layer with hierarchical micro- and nano-structures. The porous layer is able to trap a thin water film, which reduces contact between the oil droplet and the solid substrate. As a result, even a small addition of nanoparticles (0.1 wt%) lowers the adhesion force for a 20-$\mu$m-sized oil droplet by more than 400 times from 210$\pm$10 nN to 0.5$\pm$0.3 nN as measured using droplet probe AFM. Finally, we show that silica nanofluids can improve oil recovery rates by 8% in a micromodel with glass channels that resemble a physical rock network.

SummaryA new classification of gas-hydrate deposits is proposed that takes into account their location (marine vs. permafrost), porosity type (matrix vs. fracture), and gas origin (biogenic, thermogenic, or mixed). Furthermore, by incorporating currently used Classes 1 through 4, which describe the nature of adjacent strata, a total of 16 classes of hydrate deposits have been identified. This new classification provides detailed information on the properties of the hydrate-bearing layer and adjacent strata that can be used for both scientific research and ranking of field-development potential. Using this new classification system, a qualitative ranking of field-development potential for different classes of hydrate deposits according to likely productivity, capital, and operating costs can be conducted. Finally, we demonstrate the usefulness of this new classification by applying it to 11 well-known gas-hydrate deposits worldwide.

In this paper, we review and analyze the salient features of the ongoing energy transition from a high to a low carbon economy. Our analysis shows that this transition will require decarbonizing th...

Herein, Austenitic 316 low carbon stainless steel, a widely used grade for various applications, was studied to understand the effect of processing methods on the material properties. Steel samples were processed using spark plasma sintering (SPS), laser metal deposition (LMD), and cold spray (CS) techniques. Significant difference in hardness and yield strength was observed among the processed samples. The CS sample showed highest hardness (~ 378 Hv) and yield strength (~ 1390 MPa) compared to other samples. In addition to the desirable mechanical properties, corrosion resistance has a significant role in determining the service life of steel in corrosive environments. All the processed samples showed lower corrosion rate than the commercial steel. Results obtained from various characterization tools will be presented in-detail.

The objective of this paper is to propose a decarbonization roadmap for Taiwan to achieve net-zero emissions by 2050 by analyzing the status of fossil and non-fossil energies, screening applicable decarbonization technologies for their effectiveness, and then proposing an energy mix for the future. The novelty of this work lies in the screening process, which considers six, instead of one or two, categories: sustainability, security, affordability, reliability, technology readiness, and technology impact. Based on this screening, a decarbonization roadmap is proposed and compared with the announced net-zero emissions (NZE) plan. The proposed roadmap requires renewable electricity to grow at an average annual growth rate of 7% between now and 2050, instead of the 10.1% required by the NZE plan, which is more achievable based on issues identified with renewable energies during our screening exercise. The proposed roadmap improves on the NZE plan in the following aspects: (1) using clean coal technologies to decarbonize existing coal-fired power plants, (2) relying more on gas than wind and solar energies to replace coal and nuclear energy for power generation, (3) accelerating carbon capture and storage (CCS) implementation, (4) delaying the phaseout of nuclear energy until 2050, and (5) using blue instead of green hydrogen to decarbonize the transport and industry sectors. Implications of this roadmap for future research and development and energy policies are also discussed.

The tropical waters of West Africa is a top growth region for floating, production, storage and offloading units (FPSO) deployment and is the home to approximately one-quarter of the world's operating FPSOs. This study shows that a typical FPSO operating in this region with a nameplate oil production capacity of 60,000 bbl/d may emit as much as 0.8 Mtpa CO2. Therefore, the aggregate of CO2 emission from FPSOs operating in West Africa can reach as much as 40 Mtpa. The urgent need to decarbonize FPSO operations will soon become a license-to-operate issue due to the world's aspiration to achieve net-zero around the middle of the century. This study further shows that in the context of West Africa, offshore wind energy is probably the most mature and impactful technology to decarbonize FPSO operations at a water depth less than 130 m. Current technology gaps include adaptation to low wind speeds, robust power cable design, design of on/off strategy to switch between deck boilers and wind turbines, and extension of floating substructures to water depth exceeding 130 m.

As a region, the ten countries of ASEAN emitted 1.65 Gt of CO2 in 2020 which was 4.75% of worldwide emission. The biggest CO2 emitting nations were Indonesia, Malaysia, Thailand, Vietnam and Philippines. This paper conducts a detailed analysis of total primary energy consumption (TPEC) and CO2 emission profiles from these five countries as well as Singapore and Brunei (ASEAN-7). Analyses show that in 2018, TPEC of ASEAN-7 consisted of 35% oil, 29% coal, 19% gas and 17% renewables, whereas CO2 emission came 44% from coal, 39% from oil, and 17% from gas. Seven pathways for rapid decarbonization of ASEAN are proposed. They include: (1) increasing the share of renewable energies in power generation, (2) replacing coal by gas in power generation, (3) electrification of road transport, (4) hydrogen for marine transport, (5) biofuels for aviation, (6) blue hydrogen for hard-to-decarbonize industries, and (7) establishing regional carbon capture and storage (CCS) corridors to accelerate implementation of large-scale CCS projects.

As a region, the ten nations of ASEAN emitted 1.65 Gtpa CO2 in 2020 from the combustion of fossil fuels. Analyses reveal that ASEAN's renewable energy resources are low to moderate and unevenly distributed geographically. Furthermore, there are substantial sustainable issues related to hydropower and bioenergy. The current rate of addition of new renewable power capacity is too slow to allow ASEAN countries to achieve net-zero by the middle of the century. More tools, in addition to renewable energies, will be needed. It is found, however, that carbon capture and storage (CCS) is a key enabling technology to decarbonize ASEAN's fossil-fuel power and industrial plants and to produce blue hydrogen needed to decarbonize the industry sector. Furthermore, results of CO2 source-sink mapping exercises show that there is enough capacity in major sedimentary basins in ASEAN to permanently store two centuries of anthropogenic CO2 emission. Six first mover large-scale CCS projects in ASEAN with potential to mitigate up to 300 Mtpa CO2 from Singapore, Indonesia, Malaysia and Thailand have been identified. Furthermore, the steps needed to implement these CCS projects are also discussed.

In this work, a systematic investigation was performed on the structural, mechanical and corrosion properties of CNT incorporated 304 stainless steel. Various concentrations of CNT from 0.5 to 4 wt% were incorporated into the 304 stainless steel matrix to investigate the feasibility of fabrication and enhancement of strength and other material properties. The fabrication of CNT-steel composite was achieved through a spark plasma sintering process at a sintering temperature of 800 °C. Raman and morphological studies confirmed that the CNT structure was retained in the sintered pellets. Optimum performance was found at 0.5 wt% CNT giving a Vickers hardness of 351 Hv and compressive yield strength of 404 MPa which were 5.5 and 2.0 times, respectively, those of pristine steel. Corrosion studies with 3.5 wt% NaCl solution revealed a slight increase in the corrosion rate for CNT dispersed samples. Keywords: Carbon nanotube, 304-Stainless steel, Spark plasma sintering, Hardness, Compression, Corrosion

Surfactant flooding process is one of the chemical methods widely used for enhanced oil recovery (EOR) from petroleum reservoirs that utilizes chemically synthesized surfatants. Such surfactants are not bio-degradable and hence pose environmental concerns. Because of stringent environmental restrictions, it is a high time for petroleum exploration and production industry to move towards biosurfactants. Since biosurfactants are generally more expensive than chemical surfactants, one of the ways to reduce its cost is to use fermentation extracts which contain significant amount of biosurfactants know as surfactin. Surfactin is a cyclic lipopeptide produced by various strains of Bacillus subtilis. In this work, a lyophilized surfactin extract produced by Bacillus subtilis organism was evaluated for its potential in EOR application as an alternative to chemical surfactants. The surfactin mixture was produced by fermentation and characterized by liquid chromatography-mass spectroscopy (LC–MS) and matrix-assisted laser desorption/ionization time-of-flight mass spectrometry (MALDI-TOF MS) techniques. Interfacial tensions (IFT) between two light crude oils and aqueous phases were measured. Wettability alteration potential was evaluated by contact angle measurements. EOR performance was evaluated by oil/water displacement experiments at room conditions using a glass micromodel and sandstone rock samples. The analysis showed presence of surfactin containing nearly 80% of surfactin C. IFT measurements showed a significant reduction in IFT in the presence of surfactin. Contact angle measurements showed alteration of wettability of glass surface from near neutral-wet to water-wet condition. Coreflooding experiments on Berea sandstones showed about 1.7–5% incremental oil recovery by surfactin flooding. Glass micromodel experiment also showed reduction in residual oil and oil-in-water emulsions after surfactin injection.

Steel is known for its low cost of fabrication, high mechanical strength and hence is extensively used for drilling equipment, pipelines, ship building and offshore structures. Corrosion of steel is a costly problem in many applications especially in oilfield and marine environments which are known for the high temperature, high pressure and corrosive conditions. In this paper, nanocomposite coating is being explored as the preferred strategy to improve corrosion resistance for steel. Here, we will give details on the various coating materials, deposition techniques and the challenges involved in realising the most suitable coating on steel based on results of recent research. In addition, we also detail the filler specifications for getting high performance nanocomposites.

Energies may be described as brown, blue or green. Brown energies are CO2-emitting fossil fuels. Blue energies employ carbon capture and storage (CCS) technologies to remove the emitted CO2 from brown energies. Green energies are zero or low CO2-emitting renewable energies. Likewise, energy carriers such as electricity and hydrogen may be described as brown, blue or green if they are produced from brown, blue or green energy, respectively. The transition from a high carbon intensity to a low carbon intensity economy will require the decarbonization of three major sectors: power, transport and industry. By analyzing the CO2 intensity and levelized cost of energy (LCOE) of energy and energy carriers of different colors, we show that renewable energies are best used in replacing fossil fuels in the power sector where it has the most impact in reducing CO2 emission. This will consume the majority of new additions to renewable energies in the near to medium future. Consequently, the decarbonation of the transport and industry sectors must begin with the use of blue electricity, blue fossil fuels and blue hydrogen. To achieve this, implementation of large-scale CCS projects will be necessary, especially outside of USA and northern Europe. However, this will not happen until significant financial incentives in the form of carbon tax or carbon credit becomes available from national governments. Furthermore, private-public partnership and intergovernmental cooperation will be needed to implement these CCS projects.

The world of energy is transitioning from one based on fossil-fuels to one based on renewable energies and hydrogen as an energy carrier. At present, only 11% of the world's final energy consumption and less than 1% of industrial hydrogen come from renewable energies. Our analysis shows that this energy transition will take several decades because of two factors. First, renewable energies give more CO2 savings in replacing fossil fuels in the power sector than producing hydrogen for heat generation in the industry sector. Therefore, significant quantities of green hydrogen will not be available until renewable energies have replaced fossil fuels in power generation. This will take at least two decades for advanced economies and twice as long for developing economies. Second, even if blue hydrogen produced by fossil fuels with carbon capture and storage (CCS) is available in large quantities, it is still more expensive than blue fossil fuels which is also decarbonized by CCS. Consequently, fossil fuels and CCS will continue to play a key role in this energy transition. To accelerate this energy transition, governments should introduce a significant carbon tax or carbon credit to incentivize companies to implement large-scale CCS projects. Nations whose governments adopt such policies will go through this energy transition faster and benefit from the associated job creation and economic opportunities.

A new assessment tool for evaluating decarbonization technologies that considers each technology’s sustainability, security, affordability, readiness, and impact for a specific country is proposed. This tool is applied to a set of decarbonization technologies for the power, transport, and industry sectors for the ten Southeast Asian countries that constitute ASEAN. This results in a list of the most promising decarbonization technologies, as well as the remaining issues that need more research and development. This study reveals several common themes for ASEAN’s decarbonization. First, carbon capture and storage (CCS) is a key technology for large-scale CO2 emission. Second, for countries that rely heavily on coal for power generation, switching to gas can halve their CO2 emission in the power sector and should be given high priority. Third, hydropower and bioenergy both have high potential for the majority of ASEAN countries if their sustainability issues can be resolved satisfactorily. Fourth, replacing conventional vehicles by electric vehicles is the overarching theme in the road transport sector, but will result in increased demand for electricity. In the medium to long term, the use of hydrogen for marine fuel and biofuels for aviation fuel are preferred solutions for the marine and aviation transport sectors. Fifth, for the industry sector, installing CCS in industrial plants should be given priority, but replacing fossil fuels by blue hydrogen for high-temperature heating is the preferred long-term solution.

Due to their large surface-area-to-volume ratio and enhanced chemical reactivity, nanoparticles have attracted increasing interest among researchers in the upstream petroleum industry for enhanced oil recovery (EOR) applications which target the recovery of oil left behind by primary and secondary recoveries, by pressure depletion and waterflooding, respectively. In EOR applications, fluids not originally present in the reservoir, such as polymer, surfactant, carbon dioxide or steam, are injected into the reservoir to either increase the sweep efficiency or to mobilize remaining oil so as to reduce the residual oil saturation. In these applications, EOR agents are used to either reduce the mobility of the injected fluid relative to that of oil or to increase the ratio of viscous to interfacial forces, that is, capillary number. In this chapter, we begin with a discussion of the potential use of nanoparticles in the upstream oil industry. This will be followed by a discussion of the unique physics and chemistry of nanoparticles. Then a detailed discussion on how nanoparticles can be used to improve the mobility control and capillary number will be given. It is shown that nanoparticles hold promise in either augmenting existing EOR agents (e.g., surfactant and polymer) or may even replace them to become EOR agents in their own right, although many technical challenges still exist and research is in its early stage. Next the HSE aspects of nanoparticles both in laboratory investigation and field applications will be discussed. We will then conclude with suggestions for future research. With ever increasing advances of nanoparticle technology in many fields of science and engineering, we believe translation of this knowledge to EOR will yield tangible fruits in the not too distant future. However, concerted multidisciplinary efforts will be needed to realize this goal.

Experiments were carried out to study the effectiveness of CO2 injection to enhance the recovery of CH4 in a shale core sample. Two types of experiments were performed. The first was the adsorption isotherm of CH4 on the core at 30°C. The second was a series of coreflooding experiments where the core was initially saturated with CH4 at 30°C and 100 bar. CH4 recovery by depressurization to 80 bar and that by N2 or CO2 injection to 140 bar followed by depressurization to 80 bar were compared. Results showed that depressurization alone gave a recovery factor of 27%. However, N2 injection followed by depressurization gave an additional 17% in CH4 recovery due to reduction in partial pressure of CH4 during depressurization. CO2 injection followed by depressurization gave a further 4% in CH4 recovery compared to N2 injection followed by depressurization due to competitive adsorption of CO2-CH4. However, the CH4 recovery due to competitive adsorption would have been significantly higher had the dead volume in the apparatus been eliminated. Our experiments suggest that CO2 injection followed by depressurization may be an effective enhanced gas recovery method for shale reservoirs due to the combined effect of partial pressure reduction and competitive adsorption. Therefore, more research in this area is warranted.

Studies show that coastal regions of the East China Sea, Japan Sea, Philippine Sea and parts of the South China Sea have adequate wind speeds for offshore wind energy while coastal regions in equatorial Asia do not. Inexperience in installation, operation and maintenance (O&M) and the high levelized cost of electricity (LCOE) are major challenges in Asia’s roadmap to implement offshore wind farms. Several technologies in wind turbine design that will aid implementing offshore wind farms in Asia have been identified. They are weight reduction, increased reliability to reduce O&M, typhoon resistant design, integrating substructure into wind turbine design, electrifying oil and gas platforms by wind turbines, and combining multiple renewable energy systems in a single floating platform.

Experiments have demonstrated the successful fabrication of composites of multi-wall carbon nanotubes (CNT) with both 304 and 316 stainless steel (SS) using ball milling and spark plasma sintering (SPS). The retention of CNT structures after the SPS process was confirmed by x-ray diffraction, Raman spectroscopy and field emission scanning electron microscopy. At a concentration between 0.5-2.0 wt.%, CNT increased the Vickers hardness and compressive yield strength of 304 SS and 316 SS significantly. These results show that composites of CNT and SS are harder and stronger materials than pristine steels. Potential oilfield and offshore applications can be many depending on whether the CNT-SS composites are fabricated as pellets, coatings or wires.

An ultrasonic flow meter that is calibrated in single phase flow has inherent errors when applied to measure dilute water-bentonite mixture flow. This paper endeavors to use artificial intelligence for recalibration of an ultrasonic flow meter. A commercial ultrasonic transit time flow meter was tested for measuring dilute water-bentonite mixture flow of 0.1-1.0 vol% concentration at room temperature. Results show the test data had a systematic error of -8.3% and a random error of 20.3%. The machine learning LLS regression,2D interpolation and Gaussian Naive Bayes methods were considered in this exercise. Finally, a combined 2D interpolation method and Gaussian Naive Bayes classifier approach was preferred. It reduced the systematic error to -0.6% and random errors to ±13.7%. Our study shows a high accuracy ultrasonic flow meter with systematic errors smaller than 1% for oil and gas multiphase application is possible with the aid of artificial intelligence technology.

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 &deg, 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 &deg, 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.

At present, China has three major deepwater oil and gas fields located in the Qiongdongnan and Pearl River Mouth basins in the South China Sea (SCS) at water depths ranging from 300 m to over 1500 m. In this paper we compare the geology, reservoir and fluid properties and development concepts of these deepwater fields with those in the Gulf of Mexico (GOM), Nigeria and Brazil. Based on this comparison, we have identified several key subsurface challenges and opportunities for future deepwater field developments in the SCS. Major subsurface challenges include smaller in-place volumes, heavier oil, lower reservoir energy and higher reservoir temperature. Opportunities identified include locating continental margin systems with high accommodation volumes and thick sandstone supply, use of alternative development concepts such as Floating Liquified Natural Gas (FLNG) and complaint platforms with dry tree wells and learnings from the recent development of lower-permeability reservoirs in deepwater GOM and the heavy oil deepwater developments and CO2 handling techniques in Brazil.

Summary Review of published geological data shows that permafrost regions in China's Mohe Basin, Qilian Mountain, and Qinghai-Tibet Plateau hold promise for gas-hydrate accumulation according to identifiable source rock, migration path, and reservoir seal, among others. In addition, they show some common characteristics: source rock consisting mostly of shale, relatively poor reservoir quality, and gas migration through fractures. However, formation lithology, source-rock type, origin of organic matter, and total organic carbon (TOC) exhibit significant differences.

Carbon nanotubes (CNT) are rolled graphene sheets and are an exceptional invention in the field of nanotechnology. They have outstanding material characteristics such as high surface-to-volume ratio, high tensile strength, high thermal conductivity, and low density. Carbon nanotubes are many times stronger and yet lighter than steel and other metals, and thus a good candidate for reinforcing them. However the integration of CNTs into a metal or steel matrix is challenging and dispersion uniformity depends on processing parameters. The composite material properties are a function of the uniformity of CNT dispersion, interfacial bonding, CNT weight percent, length and alignment with the matrix. This paper reviews various methods of processing CNT-metal and CNT-steel nanocomposites, and their reported mechanical and material properties. Ways to overcome technical challenges are proposed and potential applications of CNT-steel composites as next generation structural material for the operationally demanding offshore oil petroleum industry are specifically discussed.

Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 °C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.

Gas hydrate is a promising energy resource. Permafrost regions in China are natural gas hydrate prospects. In this study, we summarized the conditions for gas hydrate formation, and analyzed the probable thickness and area of gas hydrate stability zones in the permafrost regions in China. Then the probability of porosity within the gas hydrate stability zones was estimated from lithology, burial history, and compaction curves. Finally, the total reservoir volume for gas hydrate stability zones in permafrost regions was estimated from the joint probability distribution of the effective thickness, area, and porosity. The probable total reservoir volume of the gas hydrate stability zones in the permafrosts in China is in the range of 2.995 × 1012 m3 to 5.081 × 1012 m3, with the best estimate at 4.002 × 1012 m3. The Qinghai-Tibetan Plateau including Qilian (where the occurrence of natural gas hydrate has been proven by coring) has about 55% of the total reservoir volume of the gas hydrate stability zones in China, indicating it has a great resource potential. In the Mohe Basin the reservoir volume of the gas hydrate stability zone ranges from 0.49 × 1012 m3 to 0.79 × 1012 m3, suggesting it is a hopeful future resource exploration area. The best estimate of the total reservoir volume of the gas hydrate stability zones in Northwest China is 1.2 × 1012 m3 which is considerable. However, occurrence of gas hydrate is yet to be confirmed by future exploration. These estimates provide much needed data for further gas hydrate resource exploration and evaluation, as well as environmental protection.

Commercial development of coalbed methane (CBM) in China has lasted for a decade. However, in 2015 annual CBM production in China was less than 5 Bcm and lagged far behind those in US (35 Bcm) and Australia (18 Bcm). In this paper, we review the published literature to determine the engineering challenges and opportunities of CBM production in China. Our review has identified seven major engineering challenges to CBM development in China. They are low cleat permeability and underpressured formation pressure of high-rank coals, ductility of coal seams, suboptimal fracturing fluids, formation damage during drilling, borehole instability in horizontal wells, frequent pump failures during production, and inadequate produced water treatment methods. Each of these challenges provides an opportunity for improvement. We propose a refocus on low-rank coals which have higher permeability. Other opportunities include development of better hydraulic fracturing fluids, non-formation damaging drilling fluids, use of geomechanics to understand borehole instability, optimization of the artificial lift methods and more robust and environmentally friendly produced water treatment methods.

CO2 has been successfully sequestered in aquifers at shallow water depth as supercritical CO2. However, at a water depth larger than 630 m in tropical regions, there exists a hydrate stability zone (HSZ) extending below the seafloor where CO2 and water can exist as solid CO2 hydrate. It is generally believed that CO2 cannot be stored inside the HSZ as formation of CO2 hydrate will impair CO2 injectivity. In this study, we investigate the feasibility of storing CO2 inside this HSZ by reservoir pressure management vis-a-vis the CO2 hydrate formation pressure through the use of water producers and CO2 injectors. We carry out simulations to investigate CO2 storage in three aquifers in tropical waters each with an area of 94 km2 (9.7 km × 9.7 km), thickness of 50 m, porosity of 30% and permeability of 3,000 md. Three confined aquifers are compared. Aquifer 1 is a shallow water aquifer without a HSZ. It has a water depth of 300 m and buried depth of 830 mbsf. Aquifer 2, straddling (60% inside and 40% outside) the HSZ, has a water depth of 800 m and buried depth of 70 mbsf. Aquifer 3, residing inside the HSZ, has a water depth of 800 m and buried depth of 30 mbsf. The reservoir pressure is managed by four corner wells which function either as CO2 injectors or water producers. We simulate CO2 injection into these aquifers with the help of water production to manage the reservoir pressure to stay below either the reservoir fracture pressure or the hydrate formation pressure. For Aquifer 1, our study shows that by reducing the reservoir pressure to below the fracture pressure through water production, up to 6% PV or 61 Mt of CO2 can be stored. The amount of CO2 stored is limited by the amount of water produced and the breakthrough of CO2 in the water producers. On the other hand, by reducing the reservoir pressure to below the hydrate formation pressure through water production, up to 12% PV or 164 Mt and 21% PV or 13 Mt of CO2 can be stored in Aquifers 2 and 3, respectively. Results show that during CO2 injection, CO2 hydrate formation delays CO2 breakthrough and moderates reservoir pressure due to volume shrinkage thus allowing more CO2 to be stored. Furthermore, over half of the CO2 is stored as immobilized CO2 hydrate which also limits post-injection migration of free CO2 and leakage through the caprock. These results demonstrate the potential of storing CO2 in aquifers having a HSZ with important ramifications for CO2 geological storage.