Tight Gas Production Research Articles

Chemical and bioassay assessment of waters related to hydraulic fracturing at a tight gas production site

Publicly available chemical assessments of hydraulic fracturing related waters are generally based on shale gas practices in the U.S. There is a lack of information on hydraulic fracturing related gas development from EU countries and more generally on other types of extractions. This research fills this knowledge gap by presenting chemical and bioassay assessments of hydraulic fracturing related waters from a tight gas development in the Netherlands. Fracturing fluid, flowback water and groundwater from surrounding aquifers before and after the actual fracturing were analysed by means of high resolution liquid chromatography tandem mass spectrometry, the Ames test and three chemical activated luciferase gene expression bioassays aimed at determining genotoxicity, oxidative stress response and polyaromatic hydrocarbon contamination.After sample enrichment a higher number of peaks can be found in both fracturing fluid and flowback samples. No clear differences in chemical composition were shown in the groundwater samples before and after hydraulic fracturing. Preliminary environmental fate data of the tentatively identified chemicals points towards persistence in water. Clear genotoxic and oxidative stress responses were found in the fracturing fluid and flowback samples. A preliminary suspect screening resulted in 25 and 36 matches in positive and negative ionisation respectively with the 338 possible suspect candidates on the list.Extensive measures relating to the handling, transport and treatment of hydraulic fracturing related waters are currently in place within the Dutch context. The results of the present study provide a scientific justification for such measures taken to avoid adverse environmental and human health impacts.

Analyzing Tight Sand Characteristics and Its Influence on Aqueous Phase Removal by Gas Displacement

Tight sand gas is an important unconventional natural gas. Liquid filtration plays a main role in the formation damage. Flowback rate is closely related to the formation permeability recovery. Usually, the more flowback rate is, the better the permeability recovery is. In order to research the factors that influence the liquid flowback, the tight sand characteristics and gas displacement have been investigated. Some experiments were carried out, including porosity, permeability, XRD, casting thin section, SEM, stress sensitivity, rock expansion, and gas displacement. The results are shown as follows. Taiyuan formation has average high clay content than H8 formation. Illite is the main clay in Taiyuan formation; chlorite is the main clay in H8 formation. From the casting thin section, the rock has strong compression. Taiyuan formation has large pore. However, H8 formation mainly has small cracks. Through the SEM, there are many micro- to nanocracks as well as some pores in these two formations. In some cases, cracks penetrate the clays. From the permeability stress sensitivity, these tight sands have strong stress sensitivity. Permeability decreases quickly with increasing confining pressure. In the rock expansion experiment, the tight sand has less expansion rate compared with shale gas rock and volcanic gas rock. Rock expansion rate has positive relationship with clay content. In the gas displacement experiment, usually the higher the clay content, the lesser the liquid flowback. Some samples have high clay content. However, it has high flowback rate, which may account for good pore connection. Through the above study, the flowback rate has negative relationship with clay content and positive relationship with pore size, pore connection, and displacement pressure. In order to increase tight gas production in the study area, the formation should have high flowback rate and less liquid retention. Therefore, clay expansion preventing additives should be added into the fracturing liquid to reduce the liquid retention. The quick flowback should be implemented after hydraulic fracturing for reducing the interaction between liquid and rock. At the same time, the drawdown pressure should keep in a certain value to reduce stress sensitivity.

A new quantitative evaluation method for development area selection of tight gas and CBM commingled production

Existing evaluation methods used for the development area selection for commingled production of tight gas and coalbed methane (CBM) are poorly universal and their parameters (e.g. reserves and reservoir physical properties) cannot reflect the production rate difference during commingled production of tight gas and CBM. In this paper, an integrated evaluation coefficient used for evaluating favorable commingled production areas of tight gas and CBM was defined so as to establish a universal quantitative evaluation index system. Then, by means of orthogonal design together with numerical simulation, the key parameters influencing the commingled production rate and their influence degree on the production rate were determined by taking the commingled production rate as the evaluation target. Finally, a new quantitative evaluation method for the development area selection for commingled production of tight gas and CBM was established. And the following research results were obtained. First, by virtue of the new quantitative evaluation method, the geological occurrence model of tight gas and CBM, the key evaluation parameter and the orthogonal experiment design are established, and the influence degree of evaluation parameters on production rate and the integrated evaluation coefficient of favorable commingled production area of tight gas and CBM are determined. Second, the quantitative evaluation results on the development areas of commingled production of tight gas and CBM in KNW Block based on 12 selected key parameters show that the southern KNW Block and the Well block KNW-37 in the north of KNW Block are the favorable areas for single production of tight gas, Well blocks KNW-10, KNW-33 and KNW-9 are the favorable areas for single production of CBM, and the central and southwestern areas are the favorable areas for the commingled production of tight gas and CBM. In conclusion, this new quantitative evaluation method is universal and can be used as reference for the development area selection for commingled production of tight gas and CBM.

The damage mechanisms of fracturing fluid on production in tight gas reservoirs

Hydraulic fracturing is generally required for tight gas formation with low matrix permeability to achieve economic production rate. Hydroxypropyl guar gum (HPG) fracturing is one of most commonly used technology. During fracturing, million gallons of guar gum fluid are pumped downhole to initiate fractures, and lots of fluid would filtrate into formation matrix. The guar gum will be adsorbed in the porous medium of sandstone and decrease the permeability of the reservoir. For improving the production of tight gas well after being stimulated, the adsorption mechanism between the guar gum and sandstone is studied. The action force is analysed through the Flourier transformation infrared spectroscopy (FT-IR), Zeta potential instrument and X-ray photoelectron spectroscopy (XPS). The result indicate that the hydrogen bonding is the key force between the guar gum and sandstone. To observe the adsorption morphology, scanning electron microscope (SEM) and atomic force microscope (AFM) are employed. Nuclear magnetic resonance (NMR) and computer tomography (CT) showed that the adsorption and retention of guar gum in tight gas reservoir resulted in the decrease of pore and throat ratio, the decrease of porosity by 2.7%~3.1%, and most adsorption occurs at grain edges and rock beddings.

Geological and Geochemical Characteristics and Exploration Prospect of Coal‐Derived Tight Sandstone Gas in China: Case Study of the Ordos, Sichuan, and Tarim Basins

AbstractThis work extensively investigated global tight sandstone gas, and geologically and geochemically analyzed the tight sandstone gas in China's Ordos, Sichuan, and Tarim basins. We compared typical tight sandstone gas in China with that in North America. We proposed six conditions for the formation of China's tight sandstone gas, and illustrated the geological characteristics of tight sandstone gas. In China, gas‐bearing tight sandstones were mainly deposited in continental lake deltas and marine‐terrigenous facies basin environments, associated with coal‐measure strata, and were mostly buried deeper than 2000 m under a formation pressure of 20–30 MPa, with pressure coefficients varying from overpressure to negative pressure. In other countries, tight gas bearing sandstones were dominantly deposited in marine to marine‐terrigenous facies environments, occurred in coal‐measure strata, and were mostly buried shallower than 2000 m in low‐pressure systems. We systematically analyzed tight sandstone gas in the Ordos, Sichuan, and Tarim basins in terms of chemical compositions, geochemical characteristics of carbon isotopes, origins, and sources. Tight sandstone gas in China usually has a hydrocarbon content of >95%, with CH41 content >90%, and a generally higher dry coefficient. In the three above‐mentioned large tight sandstone gas regions, δ13C1 and δ13C2 mainly ranges from –42‰ to –28‰ and from –28‰ to –21‰, respectively. Type III coal‐measure source rocks that closely coexist with tight reservoirs are developed extensively in these gas regions. The organic petrology of source rocks and the carbon isotope compositions of gas indicate that tight sandstone gas in China is dominantly coal‐derived gas generated by coal‐measure strata. Our analysis of carbon isotope series shows that local isotope reversals are mainly caused by the mixing of gases of different maturities and that were generated at different stages. With increasing maturity, the reversal tendency becomes more apparent. Moreover, natural gas with medium‐low maturity (e.g., Xujiahe Formation natural gas in the Sichuan Basin) presents an apparent reversal at a low‐maturity stage, a normal series at a medium ‐maturity stage, and a reversal tendency again at a high‐maturity stage. Finally, we proposed four conditions for preferred tight sandstone gas “sweep spots,” and illustrated the recoverable reserves, proven reserves, production, and exploration prospects of tight sandstone gas. The geological and geochemical characteristics, origins, sources, and exploration potential of tight sandstone gas in China from our research will be instructive for the future evaluation, prediction, and exploration of tight sandstone gas in China and abroad.

An overview of the new Geological and Bioregional Assessments Program

As part of the AU$86.3 million ‘Towards a New Energy Future’ package, the Australian Government has committed AU$30.4 million to undertake the Geological and Bioregional Assessments Program. This program aims to encourage sustainable gas development through a series independent scientific studies into the potential environmental impacts of shale and tight gas exploration and production. These studies, conducted by Geoscience Australia and CSIRO, supported by the Bureau of Meteorology and managed by the Department of the Environment and Energy, will focus on three basins (regions) that are prospective, but underexplored for shale and tight gas. The program seeks to encourage exploration to bring new gas resources to the East Coast Gas Market within the next 5–10 years, increase the understanding of the potential environmental impacts posed by gas developments and increase the efficiency of assessment, monitoring and ongoing regulation, including improved data capture and reporting. The Cooper Basin and the Isa Superbasin have been selected for investigation with a third basin expected to be announced by mid-2018. The program will be delivered in three stages over 4 years and will investigate areas prospective for shale and tight gas within these regions. This independent, transparent, science-based approach aims to assist in building community understanding of, and confidence in, the capacity for safe and environmentally sustainable unconventional gas developments.

Unexpected viscoelastic deformation of tight sandstone: Insights and predictions from the fractional Maxwell model

Tight gas is one important unconventional hydrocarbon resource that is stored in tight sandstone, whose mechanical property greatly influences the tight gas production process and is commonly believed to be simply elastic when designing the stimulation plan. However, the experimental evidence provided in this work surprisingly shows that tight sandstone can deform in a viscoelastic way. Such an unexpected observation poses a challenge in accurately modelling the deformation process. We solve this problem by adopting the fractional Maxwell model to successfully derive the constitutive equation of tight sandstone, based on which not only all the experimental data can be interpreted quantitatively, but also reasonable and consistent predictions as to tight sandstone’s long-term deformation behaviour can be made. We then investigate the typicality of our results in China’s Changqing oilfield, which is one major centre of tight gas production and where the rock samples for experiments are obtained. It is estimated that a non-negligible portion of 18% tight sandstone samples in this area will probably display viscoelasticity. Finally, our work implies that the mechanical properties of other materials may also need further scrutiny to possibly uncover any unexpected behaviour, overlooking which may result in misleading predictions.

Economic evaluation on tight sandstone gas development projects in China and recommendation on fiscal and taxation support policies

China is rich in tight sandstone gas resources (“tight gas” for short). For example, the Sulige Gasfield in the Ordos Basin and the Upper Triassic Xujiahe Fm gas reservoir in the Sichuan Basin are typical tight gas reservoirs. In the past decade, tight gas reserve and production both have increased rapidly in China, but tight gas reservoirs are always managed as conventional gas reservoirs without effective fiscal, taxation and policy supports. The potential of sustainable tight gas production increase is obviously restricted. The tight gas development projects represented by the Sulige Gasfield have failed to make profit for a long period, and especially tight gas production has presented a slight decline since 2015. In this paper, a new economic evaluation method was proposed for tight gas development projects. The new method was designed to verify the key parameters (e.g. production decline rate and single-well economic service life) depending on tight gas development and production characteristics, and perform the depreciation by using the production method. Furthermore, the possibility that the operation cost may rise due to pressure-boosting production and intermittent opening of gas wells is considered. The method was used for the tight gas development project of Sulige Gasfield, showing that its profit level is much lower than the enterprise's cost level of capital. In order to support a sustainable development of tight gas industry in China, it is recommended that relevant authorities issue value-added tax (VAT) refund policy as soon as possible. It is necessary to restore the non-resident gas gate price of the provinces where tight gas is produced to the fair and reasonable level in addition to the fiscal subsidy of CNY0.24/m3, or offer the fiscal subsidy of CNY0.32/m3 directly based on the on-going gate price. With these support policies, tax income is expected to rise directly, fiscal expenditure will not increase, and gas consumption cost in China will be significantly cut down.

A simple dilation-recompaction model for hydraulic fracturing

Production of unconventional oil and gas resources has played a significant role on the global energy supply, of which tight oil and gas reservoirs are drawing greater focus. The key enabler behind tight oil and gas production has been multi-stage hydraulic fracturing along extended reach horizontal wells. Despite many advances in multistage fracturing, it still remains unclear how to model the hydraulic fracturing process to provide the basis to optimize and predict the properties of fracture networks and associated enhancement of fluid production. In typical reservoir simulation practice, the conventional way to represent the hydraulic fracture is to place high permeability planes around the horizontal well – this means that the user has prescribed the orientation and length scale of the fracture before the simulation has started. In the research documented here, we explore a dynamic fracturing approach that uses a dilation-recompaction model in a reservoir simulator to model hydraulic fracturing. The key strength of the approach is that the geometry and length scale of the fracture is not prescribed a priori. The results of the simulation show that dilation-recompaction model is capable of modeling the hydraulic fracturing process prior to the flow-back and production. The oil, gas, and water rates of the model are well matched to the field data and the extent of the fractured zone predicted by the model is reasonable.

3D seismic attributes for a tight gas sand reservoir characterization of the eastern Sulige gas field, Ordos Basin, China

The Lower Permian Xiashihezi Formation of the Ordos Basin is the largest producer of tight gas sand in China. The controls on tight gas production are many and include a variety of geologic, hydrodynamic, and engineering factors from one well to another throughout the basin. In this study, we considered data from a [Formula: see text] 3D seismic volume and logs from 17 wells to investigate the geologic controls on gas production in the [Formula: see text] member of the Xiashihezi Formation, eastern Sulige gas field, Ordos Basin. Our objective was to determine the potential of applying multiple seismic attributes to identify the higher productivity areas of a tight gas sand reservoir. To achieve this, we used amplitude, complex traces, spectral decomposition, and seismic attenuation attributes derived from the 3D seismic volume to detect gas-bearing sand areas. The results of seismic attribute analysis revealed that no single attribute is correlated to higher productivity areas. The qualitative correlations between attributes and production records reflected that higher productivity areas are associated with seismically definable higher amplitude, more stable phase, tuning frequency, and stronger attenuation features in the study area. Meanwhile, three outlier wells in the seismic attribute analysis provided a reminder of the uncertainty in geologic interpretation. The gas-sand reservoir evaluation results suggested that the Pareto principle helps to enhance the interpretation needed to determine the productivity distribution of [Formula: see text] tight-gas reservoir in the study area.

Optimizing nanoemulsions as fluid flowback additives in enhancing tight gas production

Abstract Nanoemulsions with d -limonene as oil have been studied as flowback additives in enhancing tight gas production. Nanoemulsions have been prepared by the low energy emulsification process. The surface tension and contact angle of fluid have been studied and correlated to the capillary pressure in the reservoir. The surfactants and oil adsorbed on the surface as monolayer gives high contact angle at low surfactant concentration. A modified column test was used to evaluate fluid recovery. The results show that fluid recovery of nanoemulsion is higher than that of surfactants alone. The fluid recovery is higher with higher oil/surfactant ratio in nanoemulsions.

Genesis and Spatial Distribution of Interlayer in Tight Gas Reservoirs: A Case Study from the Lower Cretaceous Sandstones, Songliao Basin, China

Interlayer is a kind of rock body that reflects the seepage barrier in the reservoir sandstones. As the interlayer playing a blocking role of hydrocarbon accumulation, we can better understand the characteristics of the reservoir heterogeneity through the analysis of the causes and spatial distribution of the interlayer. Empirically, identification of four types of interlayer, including muddy interlayer, calcium interlayer, physical layer, and indistinguishable interlayer, contributes to effective production of tight gas sandstones. Each category of interlayer has a separate characteristic of the lithology and logging curves. Identifying interlayer provides a way to analyzing spatial distribution of interlayer in the tight gas field. 2-D and 3-D geological models corresponding to the distribution of interlayer can be able to establish to characterize distribution variations within the reservoirs, which show the space matching relation serving for the tight gas production.

The Use of Rate-Transient-Analysis Modeling To Quantify Uncertainties in Commingled Tight Gas Production-Forecasting and Decline-Analysis Parameters in the Alberta Deep Basin

Summary The evaluation of expected ultimate recovery (EUR) for tight gas wells has generally relied upon the Arps equation for decline-curve analysis (DCA) as a popular approach. However, it is typical in tight gas reservoirs to have limited production history that has yet to reach boundary-dominated flow because of the low permeability of such systems. Commingled production makes the situation even more complicated with multiboundary behavior. When suitable analogs are not available, rate-transient analysis (RTA) can play an important role to justify DCA assumptions for production forecasting. The Deep-basin East field has been developed with hydraulically fractured vertical wells through commingled production from multiple formations since 2002. To evaluate potential of this field, DCA type curves for various areas were established according to well performance and geological trending. Multiple-segment DCA methodology demonstrated reasonable forecasts, in which one Arps equation is used to describe the rapidly decreasing transient period in early time and another equation is used for boundary-dominated flow. However, a limitation of this approach is the uncertainty of the forecast in the absence of extended production data because the EUR can be sensitive to adjustments in some assumed DCA parameters of the second segment. In this paper, we used RTA to assess reservoir and fracture properties in multiple layers and built RTA-type well models around which uncertainty analyses were performed. The distributions of the model properties were then used in Monte Carlo analysis to forecast production and define uncertainty ranges for EUR and DCA parameters. The resulting forecasts and EUR distribution from RTA modeling generally support the DCA assumptions used for the type curves for corresponding areas of the field. The study also showed how the contribution from the various commingled layers changes with time. The proposed workflow provides a fit-for-purpose way to quantify uncertainties in tight gas production forecasting, especially for cases when production history is limited and field-level numerical simulation is not practicable.

Risky Business: The Issue of Timing, Entry and Performance in the Asia-Pacific LNG Market

Canada’s federal government has championed the prospect of exporting liquefied natural gas (LNG) to overseas markets. The government of British Columbia is aggressively planning to turn itself into a global LNG-export hub, and the prospect for Canadian LNG exports is positive. However, there are market and political uncertainties that must be overcome in a relatively short period of time if Canada is to become a natural gas exporter to a country other than the United States. This report assesses the feasibility of Canadian exports and examines the policy challenges involved in making the opportunity a reality.Demand for natural gas in the Asia-Pacific region is forecast to grow over 60 per cent by 2025. LNG trade is expected to make up nearly two-thirds of global natural gas trade by 2035. Supply in the Asia-Pacific region is limited, requiring significant LNG imports with corresponding infrastructure investment. This results in substantial price differentials between North America and the Asia-Pacific countries, creating a potentially lucrative opportunity for Canada.The lower North American prices are a reflection of the fact that there is a surplus of gas on this continent. Canada’s shipments to its sole export market, the United States, are shrinking in the face of vast increases in American production of shale and tight gas. Canada has a surplus of natural gas and there is growing demand in the Asia-Pacific region. Proponents argue that all Canada needs to do is build and supply facilities to liquefy gas and ship it across the Pacific; thereality is not so simple.Timing is one of the key challenges Canada faces. Producers around the world — including in the newly gas-rich U.S. — are racing to lock up market-share in the Asia-Pacific region, in many cases much more aggressively than Canada. While this market is robust and growing, the nature of the contracts for delivery will favour actors that are earliest in the queue; margins for those arriving late will be slimmer and less certain over time. As supply grows, so too does the likelihood of falling gas prices in the Asia-Pacific region, making later projects less lucrative. LNG projects are feasible only on the basis of long-term contracts; once a piece of market share is acquired, it could be decades before it becomes available again. Currently, there are more proposed LNG-export projects around the world than will be required to meet projected demand for the foreseeable future.Delays beyond 2024 risk complete competitive loss of market entry for Canadian companies. B.C. is behind schedule on the government’s goal of having a single terminal operational by 2015. Of equal concern is the lack of policy and regulatory co-ordination, with disagreements between governments over standards, process and compensation for those stakeholders involved in the potential LNG industry. Issues as basic as taxing and royalty charges for gas shipments between provinces and locating facilities and marine-safety standards remain unsettled in Canada. The B.C. government has announced plans to levy special taxes on LNG, a policy that could render many current proposals uncompetitive. The LNG market is much more complicated than current discussions suggest; this report delves into every aspect relevant for Canada as a potential exporter. The prospect for Canada expanding into the Asia-Pacific market is entirely viable. Canada has almost everything going for it: political stability, free-market principles, immense resources, extensive infrastructure and industry experience. Everything, that is, except a coordinated regulatory and policy regime. Withoutthat, Canada could be shut out, stuck relying on a single U.S. gas-export market that, increasingly, does not need us.

Environmental and Economic Significance and Feasibility Analysis of Tight Sand Gas Reservoir in China

Currently, with a sharp increase in demand for natural gas and a strict energy supply circumstances, the development of tight sand gas becomes a pressing need for the rapid development of Chinas society and economy. At the end of 2010, the reserves and annual production of tight sand gas in China accounted for 39.2 percent and 24.6 percent of national natural gas, respectively, and the proportions are expected to increase. Compared with other unconventional gas such as shale gas and coal bed methane, the techniques of tight sand gas are relatively mature and development costs of it are relatively low. So tight sand gas should be considered in priority in the exploration and exploitation of unconventional gas in China. The total reserves of tight sand gas in China are 12 trillion cubic meters. Tight sand gas in China possesses the rich reserves and enormous potential to develop, which can ease the current shortage of energy. Besides, China has mastered a series of key techniques such as the well drilling and completion protection supporting technique; well completion and staged fracturing technique of horizontal well, which guarantees the technical feasibility of the development of tight sand gas reservoirs. From the perspective of market, social and environmental meaning, reserves, technique and economic feasibility, this paper presents a systematical analysis about the importance of developing tight sand gas in China.

Development of new type curves for production analysis in naturally fractured shale gas/tight gas reservoirs

As a result of ultra-low rock permeability and hydraulic fracturing, both shale gas and tight gas production exhibit long-term transient and linear flow behaviour. Previous studies have introduced the type curves for linear flow reservoir and assumed that the production is dominated by the stimulated reservoir volume (SRV). Later the type curves were extended to include the production contribution from un-stimulated region which has been assumed to be a homogeneous system. At present, no type curves have been developed for naturally fractured shale gas/tight gas reservoirs in which the un-stimulated region has double porosity flow behaviour. In the current study, we have developed new analytical solutions for shale gas/tight gas reservoirs with multi-stage fractured horizontal well in order to account for the un-stimulated region as a dual porosity system. The solutions are more general for type curve analysis and applicable in both homogeneous and naturally fractured reservoirs. Numerical models were used to validate the analytical solutions and obtained an excellent agreement. We have also developed new type curves for shale gas/tight gas evaluation. The flow regimes are identified to show linear flow and transition flow alternately, and are more complicated than the assumption of homogeneous un-stimulated reservoir in late period. We have compared the new type curves with the curves based on SRV and Brohi's solutions. It is concluded that the double porosity behaviour of un-stimulated region has a positive effect on production even if the fracture permeability is in the order of matrix permeability and the matrix bulk shape factor is low.

Accurate Resolution of Near-Well Effects in Upscaled Models Using Flow-Based Unstructured Local Grid Refinement

Summary We present a new approach for representing wells in coarse-scale reservoir simulation models. The technique is based on an expanded well model concept which provides a systematic procedure for the construction of the near-well grid. The method proceeds by first defining an underlying fine-scale model, in which the well and any key near-well features such as hydraulic fractures are fully resolved using an unstructured grid. In the (coarse) simulation model, the geometry of the grid in the expanded well region, and the associated "radial" transmissibilities, are determined from the solution of a fine-scale, single-phase, well-driven flow problem. The coarse-scale transmissibilities outside of the well region are computed using existing local upscaling techniques or by applying a new global upscaling procedure. Thus, through use of near-well flow-based gridding and generalized local grid refinement, this methodology efficiently incorporates the advantages of highly-resolved unstructured grid representations of wells into coarse models. The overall model provided by this technique is compatible with any reservoir simulator that allows general unstructured cell-to-cell connections (model capabilities, in terms of flow physics, are defined by the simulator). The expanded well modeling approach is applied to challenging 3D problems involving injection and production in a low-permeability heterogeneous reservoir, tight-gas production by a hydraulically-fractured well, and production in a gas-condensate reservoir. In the first two cases, where it is possible to simulate the fine-grid unstructured model, results using the expanded well model closely match the reference solutions, while standard approaches lead to significant error. In the gas-condensate example, which involves a nine-component compositional model, the reference solution is not computed, but the solution using the expanded well model is shown to be physically reasonable while standard coarse-grid solutions show large variation under grid refinement.

Seismic Tomography from the Old to the New Millennium

During the past two decades, seismic tomography has been landing from the blue sky of academic or pioneering papers to the hard ground of industrial processing over a large scale. Actually, this happened for a few specific applications, such as tomostatics and velocity modeling for pre-stack depth migration. Other more recent or sophisticated developments, involving full waveform inversion or interferometry, are still maturing in terms of theoretical refinements or viable implementations. In this paper, I review the major practical or theoretical impact. I also propose a list of weak or missing items in the state-of-the art technology that needs to be addressed, to cope with current challenges in exploration, monitoring and production of unconventional tight gas.

Tight gas in China and its significance in exploration and exploitation

Abstract Tight gas reservoirs refer to the tight sandstone fields or traps accumulating natural gas of commercial values. According to reservoir characteristics, reserves, and structural height, they can be divided into two types, continuous-type and trap-type: the former are located at the lower part of the structure and have indistinct trap boundaries, inconsistent gas-water boundaries and reversal of gas and water, and their reservoirs are the same as or near the source; the latter are located at the higher part of the structure, with gas above water in traps, low reserves, and relatively high production. Tight gas in China is all coal-derived, dominantly alkane gases (C1–4), in which the amount of methane is greatest and the alkane gases have positive carbon isotopic series. The content of non-hydrocarbon gases (mainly CO2 and N2) is low. At the end of 2010, the reserves and annual production of tight gas in China accounted for 39.2% and 24.6% of the total natural gas, respectively, and the proportions are expected to increase. Compared to the shale gas and coalbed gas, tight gas should be considered in priority in the exploration and exploitation of unconventional gas in China.

Potential Restrictions for CO2 Sequestration Sites Due to Shale and Tight Gas Production

Carbon capture and geological sequestration is the only available technology that both allows continued use of fossil fuels in the power sector and reduces significantly the associated CO(2) emissions. Geological sequestration requires a deep permeable geological formation into which captured CO(2)can be injected, and an overlying impermeable formation, called a caprock, that keeps the buoyant CO(2) within the injection formation. Shale formations typically have very low permeability and are considered to be good caprock formations. Production of natural gas from shale and other tight formations involves fracturing the shale with the explicit objective to greatly increase the permeability of the shale. As such, shale gas production is in direct conflict with the use of shale formations as a caprock barrier to CO(2) migration. We have examined the locations in the United States where deep saline aquifers, suitable for CO(2) sequestration, exist, as well as the locations of gas production from shale and other tight formations. While estimated sequestration capacity for CO(2) sequestration in deep saline aquifers is large, up to 80% of that capacity has areal overlap with potential shale-gas production regions and, therefore, could be adversely affected by shale and tight gas production. Analysis of stationary sources of CO(2) shows a similar effect: about two-thirds of the total emissions from these sources are located within 20 miles of a deep saline aquifer, but shale and tight gas production could affect up to 85% of these sources. These analyses indicate that colocation of deep saline aquifers with shale and tight gas production could significantly affect the sequestration capacity for CCS operations. This suggests that a more comprehensive management strategy for subsurface resource utilization should be developed.