Commercial Gas Production Research Articles

A hydrate reservoir renovation device and its application in nitrogen bubble fracturing

Abstract. Natural gas hydrate (GH) is a significant potential energy source due to its large reserves, wide distribution, high energy density, and low pollution. However, the gas production rate of past gas hydrate production tests is much lower than the requirement of commercial gas production. Reservoir stimulation technologies like hydraulic fractures provide one potential approach to enhance gas production from GH. The reservoir reformation behavior of the hydrate-bearing sediments (HBSs), particularly sediments with a high clay content, is a complex process during a hydraulic fracturing operation which has been poorly understood and thus hardly predictable. This paper presents an experimental facility that was developed to analyze the hydraulic fracture mechanism in synthesized HBSs. This facility can be used to form GH in sediments, conduct visual observation of hydraulic fracturing experiments, and measure the permeability of HBSs under high-pressure (up to 30 MPa) and low-temperature conditions (from 253.15 to 323.15 K). It is mainly composed of a pressure control and injection unit, a low temperature and cooling unit, a cavitation unit, a visual sapphire reactor, and a data acquisition and measurement unit. The hydraulic fracture module consists of a gas cylinder, fracturing pump, hopper, proppant warehouse, and valves. The sapphire reservoir chamber is applied to observe and measure the fracture of HBSs during hydraulic fracturing. The permeability test module is composed of a constant-flux pump and pressure sensors, which can evaluate the permeability performance before and after the hydraulic fracture in HBSs. The fundamental principles of this apparatus are discussed. Some tests were performed to verify hydraulic fracture tests, and permeability tests could be practically applied in the HBS exploitation.

Net-zero produced water strategy on gas production in marine gas hydrate bearing sediment

Gas hydrates, commonly found in deep marine sediments, have been considered a potential long-term energy source. Recent field trials demonstrated that well depressurisation, converting solid gas hydrates into fluid in situ, is the most efficient method for gas production. However, this process involves continuously pumping a large volume of water from the ocean that cannot be simply disposed of due to environmental concerns. The produced water, with temperature, salinity and residues different from those of shallower seawater, could impact marine species, habitats and ecosystems if directly discharged into the sea. Storing or transporting this water for treatment is economically impractical. Furthermore, as hydrate dissociation increases sediment permeability, water production rates rise over time. Therefore, re-injecting produced water into gas hydrate reservoirs emerges as a promising net-zero produced water strategy. This study investigates the effects of produced water re-injection on gas productivity and sediment deformation through coupled thermo-hydro-chemo-mechanical numerical analysis. The results indicate that re-injecting the water could improve gas productivity but may cause heave and differential displacement near the injection well. This highlights the importance of considering thermo-hydro-chemo-mechanical processes in comprehensively evaluating energy production strategies and suggests that further studies are necessary for future commercial gas production from gas hydrate reservoirs.

PALEOFACIES — BASIS OF RESERVOIR DEVELOPMENT DESIGN

Apt-Alb-Cenomanian age rocks (K1a-al + K2s) within the northern part of the West Siberian oil and gas province (OGP) are the main commercial gas production target in the Russian Federation. However, at present there are certain prerequisites and significant reserves to increase the raw hydrocarbon base and gas production in the central regions of Western Siberia. For further study of the geological structure of these sediments in order to assess their oil and gas potential, it is necessary to set up and carry out complex geological, geophysical and special studies (including sedimentological identification of sediments, detailed reconstruction of paleogeographic sedimentation settings, paleofacial analysis of rocks, petrophysical support of the works). This will make it possible to increase the accuracy and reliability of the planned works on oil and gas prospecting and exploration, as well as to carry out a qualitative forecast of the area development of promising complex reservoir rocks, to perform a full calculation of the initial geological reserves of hydrocarbons for a number of new objects (including PK5, PK7, PK8) and to build highquality geological and hydrodynamic models of hydrocarbon deposits necessary for the design of their further development.A detailed analysis of the primary geological and geophysical materials at our disposal has shown that during the formation of the Pokur Formation in the Middle Ob oil and gas bearing area (OGO) there were heterogeneous conditions of sedimentation — from purely continental to coastal-marine. High lithologic and facies heterogeneity of the studied sediments is observed everywhere. These circumstances complicate the processes of detailed correlation in these sediments, and in some cases — unrealized in practice even within one exploration area. Stratification of productive strata is the most important part of oil and gas prospecting and exploration. According to the results of our studies, the upper strata are most well traced (in some cases up to the hypsometric level of PK3-4 strata occurrence). Their confident area correlation makes it possible to identify smaller stratigraphic subdivisions (packs) in these strata and to determine the paleofacial genesis of these sediments.

New Extractivism in Ghana’s Salt Sector

Since commercial production of oil and gas started in Ghana over a decade ago, the salt sector which has historically been dominated by artisanal and small-scale mining (ASM) has seen renewed corporate interest. Aided by the state’s preference for large-scale mining (LSM) over ASM since the days of the Economic Reform Program, several tens of thousands of acres of areas previously operated by artisanal and small-scale miners for salt mining have been leased to large-scale salt mining companies. Situated in political settlement and infrapolitics theoretical frameworks, with a focus on two key salt producing sites (Songor and Keta lagoons) and using qualitative research methods through ethnographic engagement with affected regions, the study explores the consequences of this new extractivism in the salt sector to assess the long-term consequences of forced evictions, as well as role of civil society in the retention or otherwise of the now dominant LSM in the salt sector.

Fracture prediction based on attenuative anisotropy theory and its application to a shale gas reservoir

AbstractShale gas reservoirs require artificial hydraulic fracturing to achieve commercial gas production. Continental Jurassic shale reservoirs have several thin interlayers (e.g. sandstone and carbonate), which lead to pseudo-anisotropy of the seismic amplitude and velocity, and traditional technology for predicting anisotropic fractures has difficulty in identifying a true target. Based on the traditional theory of azimuthal anisotropy and the equivalent medium theory, in this paper, the approximate formula for the reflection coefficient of attenuating anisotropy and the equation for the azimuthal attenuating elastic impedance are derived. With the objective function established using Bayesian and group sparse inversion methods, parameters such as the fluid terms and fracture characteristics are obtained by solving the elastic matrix, and a highly accurate prediction of the 3D fracture density is obtained. The validity of this method is confirmed via a test on a single well and application to actual seismic data for a shale gas reservoir.

Numerical Investigation of Depressurization through Horizontal Wells in Methane-Hydrate-Bearing Sediments Considering Sand Production

Sand production has been identified as a key reason limiting sustained and commercial gas production in methane-hydrate-bearing sediments. Production tests in Canada and Japan were terminated partially because of excessive sand production in pilot wells. It is meaningful to carry out numerical investigations and sensitivity analyses to improve the understanding of sand production mechanisms during the exploitation of methane hydrates. This study introduces a numerical model to describe the coupled thermal–hydraulic–mechanical–chemical responses and sand production patterns during horizontal well depressurization in methane-hydrate-bearing sediments. The model is benchmarked with a variety of methane hydrate reservoir simulators. Results show that the spatial and temporal evolution patterns of multi-physical fields are different and the hydromechanical evolutions are the fastest. Gas production and sand production rates are oscillatory in the early stages and long-term rates become stable. Gas production is sensitive to rock physical and operational parameters and insensitive to rock mechanical properties such as cohesion. In contrast, sand production is sensitive to cohesion and insensitive to rock physical and operational parameters. Although cohesion does not directly affect gas productivity, gas productivity can be impaired if excessive sand production impedes production operations. This study provides insights into the sand production mechanism and quantifies how relevant parameters affect sand production during the depressurization in methane-hydrate-bearing sediments.

Lithofacies and its controls on the organic matter-hosted pores in the Cambrian gas-rich Niutitang shale in upper Yangtze Plate, China

The organic-rich shale in the Lower Cambrian Niutitang Formation (Є1n) has great gas resources potential in south China but have no commercial gas production achieved yet. The EYY1 well is the first well located at the eastern edge of the upper Yangtze plate to obtain success in commercial gas production in the Niutitang Formation, providing a rare case for better understanding gas enrichment mechanism in the Niutitang shale. By observation of cores and thin sections, bulk rock X-ray diffraction mineral analysis, the Niutitang shale is classified into three kinds of organic-rich lithofacies: calcareous shale (CS), siliceous shale (SS) and transitional shale (TS). The organic matter (OM) and OM-hosted pore in different lithofacies were examined by using scanning electron microscope (SEM) with argon-ion polishing sample treating, accompanied by energy spectrum test and SEM image analysis. The results show that: (1) Shale lithofacies control the organic matter type and development degree of organic matter-hosted pores (OMPs). (2) CS have plenty of depositional organic matter (DOM) in which nano-micron sized OMPs are poorly developed with surface porosity ranges between 3.05% and 9.08%. Siliceous and transitional shale have more migrated organic matter (MOM), which possess more sponge-like nano-sized pores with surface porosities range of 10.7%–31.5%. The pore development degree and gas content of siliceous shale is higher than that of transitional and calcareous shale. (3) Organic matter abundance (TOC content), type, and mineral composition also have important constrain on OMPs development. TOC has a positive correlation to the OMPs, whereas TOC 4 wt% or so is a balance point between the influence of organic matter content and formation compaction on pore development, higher TOC cannot prevent the pore from collapsing due to compaction in this region. The OMPs associated with or adjacent to clay minerals in siliceous shale are more developed, which indicate clay minerals which have positive effects on the adsorption of organic matter and the formation and preservation of OMPs.

Analysis of Supercritical CO<sub>2</sub> Coiled Tubing Fracturing Technology for Shale Gas Formation

Hydraulic fracturing of shale formations has led to energy boom both in China and abroad. Currently, water is regularly used as fracturing fluid in commercial shale gas and oil production, but it has raised concerns in many aspects such as environment and reservoir protection. Supercritical CO₂, as a non-aqueous fracturing fluid, combined with coiled tubing fracturing technology, can effectively increase shale gas production, shorten operation period, reduce cost, conserve water resources, and minimize environmental impacts. Firstly, the process of supercritical CO₂ fracturing with coiled tubing of shale gas formation was introduced, and the potential advantages of using CO₂ as working fluid in coiled tubing fracturing of shale gas formation were analyzed, including enhanced fracturing and fracture propagation, reduction of flow-blocking, increased desorption of methane adsorbed in organic-rich parts of the shale, and a reduction or elimination of the deep re-injection of flow-back water that has been linked to induced seismicity and other environmental concerns. In addition, shale gas formations may also become a major utilization option for carbon sequestration. Then, the computational fluid dynamics were applied to simulate the flow fields inside cavity of supercritical CO₂ fracturing with coiled tubing, and the pressure boost capability was verified. By comparing the pressure boost effects of water fracturing and supercritical CO₂ fracturing, it could be concluded that supercritical CO₂ fracturing with coiled tubing has stronger pressure boost effect than water fracturing under the same conditions. The research and development status of supercritical CO₂ fracturing equipment and field test were also analyzed. The research results can provide references for the application of supercritical CO₂ fracturing with coiled tubing in shale gas formations and the development of related tools.

Assessing the effect of well completion types on productivity in a class 1G gas hydrate reservoir under pseudo steady state

This work focuses on the assessment of the effect of well completion types on gas productivity in subsea gas hydrate reservoirs of class 1G type where the gas hydrates have decomposed into gas and water. Three types of vertical well completions are considered: frac-packed well with vertical hydraulic fracture; frac-packed well with horizontal hydraulic fracture, and a cased-hole gravel-packed well. Sensitivity analysis was conducted with analytical well inflow models to determine factors that affect the gas well productivity. The results of the analyses indicated that proppant mass pumped during fracture treatment slightly improves well productivity for frac-packed natural gas hydrate wells. Well productivity increases nonlinearly with fracture productivity up to a threshold value of 50,000 md for frac-packed well with horizontal fracture, above which further increase in fracture conductivity would create no benefit. With a proppant mass of 50,000 Ibm and a corresponding proppant volume of 504 ft 3 , commercial gas production rates of 14.9 MMscf/d, 5.621 MMscf/d, and 11.35 MMscf/d are possible for frac-packed well with vertical fracture, frac-packed well with horizontal fracture, and cased-hole gravel-packed well, respectively. Because hydraulic fracture orientation depends on the in-situ formation stress, whether a well should be hydraulic-fractured or not depends on in-situ formation stress.

Influence of organic matter type on porosity development in the Wufeng-Longmaxi Shale: A combined microscopy, neutron scattering and physisorption approach

The upper Ordovician Wufeng Shale and lower Silurian Longmaxi Shale are part of the Fuling shale gas play located in the south-eastern part of the Sichuan Basin, southern China, representing the first commercial shale gas production project outside North America. We studied the occurrence of porosity at the micro- and nano-scale in samples of contrasting organic richness representing the typical lithofacies from the post-mature part of the Wufeng-Longmaxi gas play. Using a combination of site specific, high-resolution scanning and transmission electron microscopy with bulk measurements based on small angle neutron scattering and cryogenic Argon physisorption, along with conventional organic petrology, we highlight the impact of different types of organic matter (OM) (primary versus secondary) on the development of OM-hosted porosity. The results indicate that at the bulk scale the overall porosity in the samples is proportional to their organic content and organic hosted pore account for 30–40% of the total pore volume of the rocks. Nevertheless, most of the pores identified via electron microscopy imaging seem to reside in the organic matter, indicating that potentially a large part of the pores volume detected by neutron scattering and Argon physisorption is visually not detected. Organic matter focused nanoscale imaging revealed that mesopores are preferentially present in the solid bitumen and not in the primary detrital organic particles. Organic lean samples show low porosity and dominance of micropores, while organic-rich samples show higher porosity and a broader spectrum of pore sizes. Importantly, most of the meso pores are located in organic matter petrographically interpreted as solid bitumen, while detrital organic particles like graptolites show minimal visible porosity under high resolution electron microscopy and pore sizes in the micro pore range (i.e. <2 nm).Distinguishing between primary and secondary OM is therefore important for understanding the creation of an interconnected network of porous OM during hydrocarbon migration. This may have an important control on the estimation of gas in place and the gas transport properties of the shale.

Numerical evaluation on the effect of horizontal-well systems on the long-term gas hydrate production behavior at the second Shenhu test site

In 2019–2020, the second natural gas hydrate field trial was successfully performed in the Shenhu Area of the South China Sea by using a horizontal well, however, the long-term production performance is unclear and needs intensive surveys. In this work, a multilayered hydrate reservoir model was constructed to replicate the short-term test result on the basis of the field data obtained at this site for the first time. Then, the long-term gas hydrate production behaviors at this site by using the single-horizontal-well and dual-horizontal-well systems were investigated, and the production strategy of thermal stimulation was proposed to examine the effects of the injection parameters of the hot water on the enhanced gas recovery. From the analysis of the simulation results, it can be known that due to the extremely low permeabilities of the whole reservoir (2.38–6.8 mD), the 10-yr average gas production rates (7.71 × 102–2.88 × 103 m3/d) could only reach 1/10 of the level obtained in the second Shenhu field trial (2.87 × 104 m3/d), which indicated that none of the above methods were quite suitable for future commercial gas production at this site. Therefore, it is recommended that permeability enhancement should be implemented in advance to improve the reservoir permeability before the actual long-term gas production.

Experimental Study on the Propagation Characteristics of Hydraulic Fracture in Clayey-Silt Sediments

The low permeability of clayey-silt hydrate reservoirs in the South China Sea affects the thermal and pressure conductivity of the reservoir, which is difficult to spread to the far end of the wellbore and achieve commercial gas production. In this respect, enhancing the permeability to assist depressurization is necessary. Hydraulic fracturing is a promising reservoir stimulation method for gas hydrate reservoirs. Up to now, majorities of research focus on the fracability of hydrate-bearing sandy sediments, but the studies rarely involved fracture propagation characteristics of clayey-silt sediments in the hydrate dissociation area. In this paper, three sets of hydraulic fracturing experiments under different confining pressure were carried out using the clayey-silt sediments in the Shenhu Area. Computed tomographic (CT) images indicated that clayey-silt sediments could be artificially fractured, and the fracturing fluid could induce tensile fractures and local shear fractures. A multimorphological fracture zone occurred near the borehole. Furthermore, the greater the confining pressure imposed, the greater the breakdown pressure was, and the microfracture arose more easily. The fractures at the top were generally wider than those at the bottom with the same confining pressure. The experimental results could reveal the fracture initiation and propagation mechanism of clayey-silt sediments and provide theoretical support for hydraulic fracture in the hydrate dissociation area.

Numerical study of gas production from fine-grained hydrate reservoirs using a multilateral horizontal well system

Natural gas hydrate is prevalent in ultralow-permeability fine-grained sediments with substantial reserves. However, effective and safe gas production from fine-grained hydrate reservoirs remains a global challenge. Here, a multilateral horizontal well system is innovatively employed to improve production efficiency in fine-grained hydrate reservoirs. A three-dimensional (3D) numerical model of a real gas hydrate reservoir is constructed, and the influences of well configuration, deployment location, depressurization pressure, and reservoir properties on production are systemically and quantitatively evaluated. The spatial distributions of the physical properties of the 3D reservoirs during gas production are clearly revealed. The results indicate that the production efficiency of multilateral horizontal wells improves with increasing branch number and length, particularly when the ratio of branch length to reservoir width exceeds 0.15. Branch interference and perforation length positively affect production enhancement when multilateral horizontal wells are deployed in hydrate reservoirs with specific ultralow permeabilities; these discoveries are revealed for the first time. Multilateral horizontal wells with helically and vertically distributed equal-length branches yield high production efficiencies, and their optimal locations are in the lower sections of the reservoirs, particularly within high-isotropic-permeability reservoirs. Moreover, uniformly low depressurization pressure in helically distributed branches facilitates gas extraction; gas recovery efficiency increases by 8% when production pressure decreases by 1 MPa. This study suggests that the use of a helical multilateral well system is a promising strategy for achieving commercial gas production from fine-grained hydrate reservoirs.

Effective application of proppants during the hydraulic fracturing of coal seam gas reservoirs: Implications from laboratory testings of propped and unpropped coal fractures

Commercial production of coal seam gas is a significant proportion of the total Worldwide natural gas supply due to its high gas storage capacity at shallow extraction depths. Coal seam gas recovery may be enhanced by pure fluid-based or proppant based hydraulic fracturing – the decision whether or not to use proppants depends on coal seam characteristics – in particular stress-permeability characteristics. Although proppant application has been common in deep reservoir fracturing, its application on soft rocks such as coal should be carefully investigated. Higher concentrations of proppant are known to minimise proppant damage in deep reservoirs, with stiffness and flow tortuosity also impacting the response. We explored the impact of proppant loading, coal type and fracture roughness on fluid flow characteristics in propped fractures by conducting a series of triaxial permeability experiments combined with micro-CT imaging. The results reveal that proppant application in coal is only effective for deep coal seam gas reservoirs with effective stress greater than 6 to 8 MPa (~700 to ~900 m). Further, proppant application may cause up to 1–2 folds of fracture conductivity improvement in coal seam gas reservoirs located at over 1.2–1.4 km depths (effective stresses > 12 MPa). The impact caused by proppant embedment on fracture conductivity degradation is much significant compared to other proppant damage mechanisms. The effect, however, depends on the stiffness of the coal rock matrix and the proppant type implemented.

Hydraulic Fracturing Tight Reservoirs: Rock Mechanics and Transport Phenomena

Conventional reservoirs have been fracture stimulated using acid fracturing and proppant fracturing.Acid fracturing is performed to improve well productivity in acid-soluble formations such aslimestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture,which is the main mechanism for maintaining the fracture open during the life of a well. Proppantfracturing is an alternative option that has been applied in carbonaceous and siliceous formations.There is no quantitative method to provide an answer of whether acid fracturing or proppantfracturing is an appropriate stimulation method for a given carbonate formation. How rockmechanics can be applied to decide on what method is more effective? Laboratory experiments havebeen performed to simulate acid etched to study the effect of elastic, plastic and viscoelastic rockbehavior and their effects on fracture conductivity. Comparison of acid vs. proppant fracturingconductivity in carbonate formation is presented.Fracturing low permeability reservoirs is totally different than fracturing tight formations. Thefracture geometry required in low permeability reservoirs need to be planar, conductive andpenetrating deep in the reservoir. Fracture complexity in these reservoirs is to be avoided foroptimum stimulation treatment. However, in fracturing tight formation, a complex fracture networkis desirable for better recovery. Creating multiple fractures in horizontal wells without the use ofmechanical intervention, is becoming essential especially in tight gas reservoirs. We have learnedhow to initiate hydraulic fractures into a specific direction and place as many fractures as desired inhorizontal wells but with casing and perforation. The challenge now is to initiate weak point acrossthe horizontal well such that fracturing fluid will initiate a fracture there. How rock mechanics hasbeen applied to achieve this objective? We are fracturing tight gas sand in harsh environment, atdepth more than 18000 ft, of temperature close to 400 °F, and one can figure out the extreme in-situstresses relevant to this depth.When the reservoir pressure decreases, the elastic displacement in response to the increase ineffective stress will cause natural fractures to close leading to a decline in reservoir productivity.&#x0D; The matrix medium feeds the natural tensile fractures which carry the fluids to the wellbore. Thedecline in conductivity with increasing effective stress should follow a logical declining rate tosupport a given production rate. How the concept of effective stress has been applied to understandthe stress-dependent conductivity of various conductive components of a given reservoir? Rockmechanics testing of these stress sensitive reservoirs becomes vital to optimize fracturing tightformations.Economical production from tight reservoirs, including shale gas and shale oil formations, requireshorizontal well drilling and massive proppant hydraulic fracturing stimulation. The stimulationinvolves generating sufficient fractures network or stimulated reservoir volume (SRV), which isachieved by placing optimized stimulation treatments along the horizontal section of wellboresideally drilled from multi-well pads to increase the production rate and ultimate recovery. Hydraulicfracturing in naturally fractured formations is characterized by generating a fractures’ network thatshould be designed for in extremely low permeability of unconventional reservoirs. Fractures shouldextensively reach shale matrix to achieve commercial gas production. Therefore, production rate andultimate recovery depend on the size of the created SRV.The transport phenomena controlling fluid flow through tight formation is no longer sufficient to bemodeled by Darcy’s flow. Diffusion and imbibition are important transport mechanisms. The conceptof osmosis and flow through a semi-permeable membrane component are critical. Additionally,diffusion and a special case of molecular flow due to Knudson effect will be discussed. Conventionalreservoir simulation collapses when trying to simulate fluid flow through tight reservoirs. Numericalstudies on a hydraulically fractured well to simulate the dynamic processes during fracturinginjection, following well shut-in (soaking), and production are discussed.

Challenges of terrestrial shale gas exploration and development from Chang 7 shale in the Ordos Basin

There has been great success of marine shale gas exploration and production from Lower Silurian Longmaxi Formation (called Longmaxi shale) in Sichuan Basin, China, while whether commercial gas production could be obtained from lacustrine shales is still a question. The 7th Member of Triassic Yanchang Formation (called Chang 7 shale), which is the exploration target for the only national lacustrine shales gas pilot, was investigated to identify the key issues on the accumulation and development of terrestrial shale gas accumulation. It is considered that there are many differences in terrestrial and marine shales including depositional environment and provenance, distribution characteristics, organic matter types, mineral composition, and pore types. So evaluation standards of the two shales should not be the same. The Longmaxi shale was deposited in deep shelf, widely distributed, stable, mature–overmature (in gas window), presence of plenty micro-pores, brittle, and overpressured, which make it a good condition for shale gas accumulation. The key factors that affect the production of the Longmaxi shale concluded that the shale is rich in organic matter, high thermal evolution, brittle, and overpressured. The Chang 7 shale in Ordos Basin was deposited in deep lake, relative limited distribution, in low stage of thermal evolution (in oil window), high clay mineral content, and conducive to shale gas adsorption. On the basis of comparing the geological features of the two shales, it is found that the shale is richer in the organic matter content than in the Longmaxi shale, while the shale is not mature enough to produce more gas, and the strata pressure is relatively lower which means the shale gas was not preserved very well either. So through this study, it is believed that the shale gas formation condition in the Chang 7 shale may not be as good as in the Longmaxi shale, the absorbed gas may be the future of this shale, and the shale oil should be the focus of petroleum exploration and development in this region.

Enhancing Gas Production from Hydrate-Bearing Reservoirs through Depressurization-Based Approaches: Knowledge from Laboratory Experiments

There have been several field tests around the world to recover natural gas from gas hydrate reservoirs. A most recent trial took place in the South China Sea, breaking the records of cumulative and daily gas yield from marine hydrate deposits. However, significant challenges still remain while approaching commercial gas production. These may involve but are not limited to the ultralow permeability of the reservoir, insufficient heat supply, unstable gas yield fluctuations, sand problem upon water production from the silty sediments, and secondary hydrate formation or ice generation blocking the pore spaces. Consequently, intensive efforts have been made to understand and, thereby, manipulate the complicated gas production process. Of special interest are the studies on the determination and optimization of the depressurization scheme, because depressurization is recognized to be most promising toward an economically efficient gas recovery. Therefore, in this work, we elaborated on the effects of pressure regulation on the behavior of gas and water yield and characteristics of the reservoir during the gas production process through depressurization-based approaches. Particular attention was paid on the enhancement of the gas production rate and energy efficiency under various scenarios. The advantages and limitations of the current investigation were also discussed to present preliminary suggestions and perspectives for future studies. This work could provide a brief view of the current efforts on improving the gas production efficiency at a laboratory scale; further investigations are still required to scale-up these findings to provide guidance to the field test in the future.

Analytical study of structural characteristics of South Eastern coal field by FTIR spectroscopy and X-ray diffraction

The present study examines four coal samples from Sohagpur (South Eastern) Coal Field, Madhya Pradesh, India with its geographical coordinates of 22° 42′ 0″ North, 78° 12′ 0″ to recognize the presence of hydrocarbon content using XRD and FT-IR analysis. The peaks observed from FT-IR were compared using standard functional group charts and the adsorption band from XRD analysis used to identify the coal ranks. XRD mineralogical analysis results the existence of hydrogen, carbon, oxygen content and bands at 2θ = 26–28 show the higher rank coal content. The FT-IR study shows the sharp intense peak between 2850 cm−1 and 3000 cm−1 for ensuring presence of unsaturated hydrocarbons and minor amount of aromatic compounds. Results also indicate that the coal samples were matured with moderate to high rank, which possibly possess the aliphatic H and aromatic H. The present study also focusses on sample pattern and other organic compounds to predict the possibility of commercial gas production from those samples.

Numerical evaluation of free gas accumulation behavior in a reservoir during methane hydrate production using a multiple-well system

This study aimed to investigate the free gas accumulation behavior in a reservoir using a multiple-well system for methane hydrate production achieved by depressurization. Twenty-year simulations of gas production from a large-scale 3D methane hydrate reservoir model with different reservoir permeabilities were conducted, and the effects of different reservoir and operating conditions on the free gas accumulation behavior were fully examined. The simulation results indicated that the free gas accumulation behavior was affected by the reservoir permeability, and methane gas was inclined to accumulate within a certain permeability range, which was defined as the “free gas accumulation zone” for the first time. For an actual methane hydrate reservoir with a porosity of 0.31–0.51 and an initial hydrate saturation of 0.34–0.54, the free gas accumulation zone was estimated to be 37–145 mD at most. On the other hand, a low wellbore pressure could contribute to enhancing gas recovery by narrowing the free gas accumulation zone. In addition, the free gas accumulation zone was dramatically enlarged with the increase in well spacing, so a proper well spacing should be carefully designed to avoid the free gas accumulation zone. The prediction method proposed in this study could be applied to future commercial gas production from actual methane hydrate deposits achieved by depressurization using multiple-well systems.

Innovative Energy Solutions-Shale Gas In India

Shale gas is a major domestic option for natural gas of a country where conventional gas reserves had been used up. It is entrapped in between shale formations, having low permeability that makes its commercial production extremely difficult. Major constituent is methane which is utilized for synthesizing Ammonia and Methanol. Natural Gas Liquids (NGLs) constituents such as Ethane, Propane and Butane are utilized for Ethylene synthesis. Ethylene synthesized by Shale gas is preferred over that of manufactured by Naphtha.CO2, N2 and H2S are small fraction non-hydrocarbon constituents. Production of shale gas had lowered the dependency of nations to Middle-east for their energy needs but shale production comes at a high cost of environment degradation. About 3% of extracted gas is being released in the atmosphere, fracturing of underlying rocks can induce small earthquakes and quick exhaustion of shale wells in comparison to conventional gas wells are major disadvantages. Fracking fluid being used for Hydraulic Fracking consists of large quantities of water, sand and chemicals. After the process, vital fractions of it left underground can possibly pollute underground water sources. A long term study of the process is still desired in order to reveal exact intricacies of Environment Contamination. A Shaft is drilled into the ground up to the depth of gas bearing layer Fracking fluid is then pumped using high performance pumps. Fluid mixture penetrates into the rock layer and produces innumerable tiny cracks. Water acts as solvent, sand holds up the opening, Chemicals condense water, kill off bacteria and dissolve minerals. Production of shale gas then begins. After the reserve is exhausted, some amount of fracking fluid is pumped in again and then the drill hole is sealed. A general observed fact is that in every hydrocarbon producing nation there is an equal likelihood regarding the presence of shales holding hydrocarbons. As published in the report of EIA, June 2013 amount of shale gas resources in India is 584 tcf and the technically recoverable amount is about 96 tcf (Cambay, Krishna-Godavari, Cauvery, Damodar Valley, Upper Assam, Pranhita-Godawari, Rajasthan and Vindhyan basins). Vital task before shale gas production includes the ultimate analysis of geological properties of shales in order to produce gas/oil from them. In this regard, government with the support of many private agencies had drilled several thousand wells (mainly in Cambay, KG and Cauvery basins).These wells had provided extensive data on extent, depth and nature of shale formations in sedimentary basins. However, a lot of work is still left to actually start commercial production of shale gas on Indian soil.