ERE3.1

Hydraulic fracturing is one of the key technologies to stimulate shale gas production and may have some environmental impacts while enhancing shale gas development. Through the introduction of hydraulic fracturing technology from the design and construction aspects, analysis of its potential adverse environmental impacts in water resource consumption, surface water and groundwater pollution, geological disasters, and other aspects, and based on the existing problems to form targeted solutions.

According to EIA report, during the stimulation process of shale gas fracturing, the amount of water resources is about 10,000m³, of which 20%-80% can be returned, and the flowback rate of Shale gas in China is 20%-60%, which means that at least 20%-40% polluted water containing various chemical raw materials will be hidden in the formation for a long time. The shale flowback rate in China is significantly lower than that in the United States, not only due to formation conditions, but also due to equipment and technology. In view of this situation, it is necessary to control the whole process from design to construction.

In the design process of hydraulic fracturing of shale gas, real-time control of the fracture range is carried out in conjunction with seismic monitoring and software simulation fitting, so as to reduce the consumption of water resources on the premise of achieving the purpose of increasing production. Especially, to reducing the fracturing program as much as possible in the water-scarce areas, so as to ensure the security of public water resources. Reduce the use of chemical additives to alleviate the pollution of surface water and groundwater. After detection of possible pollution, determine the amount of pollution sources on site and carry out comprehensive pollutant recovery and treatment. Strictly prohibit high-risk pollution sources from entering the fracturing fluid process. At the same time, the fracturing fluid is used to recycled and purified. In terms of geological disasters caused by fracturing, high-risk geological disaster zones should be identified and monitored in advance to prevent large-scale geological activities caused by micro-earthquakes caused by fracturing from causing uncontrollable geological disasters.

How to cite: Wang, H. and Zhou, L.: Environmental impact and treatment of hydraulic fracturing in shale gas, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-14, https://doi.org/10.5194/egusphere-egu21-14, 2021.

In order to finely describe the hydrocarbon generation and expulsion process of source rocks and provide reasonable key parameters for quantitative evaluation of oil and gas resources, we carried out a simulation research under semi-open system on hydrocarbon generation and expulsion for the dark mudstone with Type-Ⅲ kerogen in the Eocene Pinghu Formation in the Xihu Sag, East China Sea Shelf Basin. The results show that the process of hydrocarbon generation and expulsion can be divided into five stages as follows:

• R_o = 0.5%~0.7%, oil was generated slowly without expulsion;
• R_o = 0.7%~1.0%, oil was generated and expelled rapidly;
• R_o = 1.0%~1.5%, oil began to be cracked into hydrocarbon gas;
• R_o = 1.5%~2.3%, gas generation predominated;
• R_o > 2.3%, only dry gas was generated.

Oil expulsion threshold (R_o) of the source rock of this type is about 0.7% (R_o = 0.7%), having a wide gas-window of R_o = 1.0%~3.0%. So it can maintain relatively strong gas generation ability at high- and over-mature stages, belonging to gas-prone source rock. Following the study on experimental results and the characteristics of hydrocarbon generation and expulsion in samples, we established a set of mathematical models for the evaluation of the process and potential of gas generation and oil generation and expulsion of the dark mudstone with Type-Ⅲ kerogen in the study area. Compared with the thermal simulation experiment in a closed system, the cumulative yield of oil in the semi-open system is higher and closer to that under actual geological conditions. Accordingly, we may conclude that more oil and gas resources may exist in the Xihu Sag.

How to cite: Xu, C.: Simulation of hydrocarbon generation and expulsion for the dark mudstone with Type-Ⅲ kerogen in the Pinghu Formation of Xihu Sag in East China Sea Shelf Basin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-291, https://doi.org/10.5194/egusphere-egu21-291, 2021.

Determining the timings of oil charge in sedimentary basins are essential to understand the evolutionary histories of petroleum systems, especially in sedimentary basins with complicated tectonic evolution and thermal histories. The Ordovician carbonate reservoir in the Tahe Oilfield, which is located in the northern Tarim Basin, comprises the largest marine reservoirs in China with reserves up to 3.2×10⁸ t. This study aims to determine the timings of oil charge in the Ordovician carbonate reservoir in the Tahe Oilfield, Tarim Basin, which basin is subjected to multiple phases of tectonic deformations and oil charge. The phases of calcite veins that contain oil inclusions were systematically investigated by cathodoluminescence observation, in situ rare earth element, C, O, and Sr isotope analyses. The homogenization temperatures of aqueous inclusions that are coeval with oil inclusions were measured to determine the timings of oil charge by combining the burial and geothermal histories. Two phases of calcite veins were judged by the differences in cathodoluminescence color, Ce anomaly, δ¹⁸O, and ⁸⁷Sr/⁸⁶Sr values, which might be caused by variations in the water-rock interaction processes during different calcite phases. Primary oil inclusions with yellow fluorescence were observed in the two phases of calcite veins, suggesting two phases of oil charge. By combining the homogenization temperatures of aqueous inclusions with the burial and geothermal histories, the timing of phase I oil charge was inferred to be 336–312 Ma, and the timing of phase II oil charge was inferred to be 237–217 Ma.

How to cite: Chen, J. and Guo, X.: Determination of oil charge timing in the Ordovician carbonate reservoir of the Tahe Oilfield, Tarim Basin, NW China, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-1547, https://doi.org/10.5194/egusphere-egu21-1547, 2021.

      Element geochemical analysis of 94 ditch cutting samples of the shale source rock from the Wenchang Formation in the Zhuyi sub-basin and the Liushagang Formation in the Weixinan sub-basin was conducted to determine their palaeoenvironment and main controlling factors and to further establish development models. The results indicate that freshwater and a warm and humid climate were characteristics of the depositional palaeoenvironment between Wenchang and Liushagang formations. During the deposition of Wenchang Formation, the parent rocks mainly consisted of felsic volcanic rocks, the water was characterized by a high palaeoproductivity, shallow-deep water depths, and weakly reducing conditions, whereas during the deposition of Liushagang Formation, the parent rocks mainly consisted of mafic volcanic rocks, and the palaeoproductivity, palaeowater depth, and reducing conditions of the water were better than during the deposition of Wenchang Formation. The formation of high-quality source rocks in the Liushagang Formation were mainly controlled by two factors: (1) the mafic igneous rock provenance and strong weathering provided macronutrients (e.g. P, Fe) for water; (2) high palaeoproductivity provided the source of organic matter, which played a much important role than preservation condition of organic matter. For Wenchang Formation, the good preservation of organic matter which was created by the reducing environment in deep water was also necessary. Accordingly, two models were briefly summarized: a productivity and preservation model for the Wenchang Formation source rocks and a productivity model for the Liushagang Formation source rocks, both of them can develop high-quality source rocks, but the source rock quality of the former were lower than of the latter, this was mainly attributed to the difference in the nutrients and palaeoproductivity. This study provides valuable guidance for oil and gas exploration in the northern South China Sea and the study of lacustrine source rocks in other areas.

How to cite: Zhao, N.: Depositional Palaeoenvironment and Models of the Eocene Lacustrine Source Rocks in the Northern South China Sea, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-298, https://doi.org/10.5194/egusphere-egu21-298, 2021.

The overpressure has a significant effect on hydrocarbon migration and accumulation. Scholars have gradually focused on the quantitative characterization of overpressure, which proposes many overpressure quantitative models suitable for different overpressure mechanisms. However, there are few studies on quantitative characterization of overpressure in crude oil cracking. In view of this, taking the south of Aman transition zone in Tarim Basin as the research object, recovered the overpressure characteristics of the research area in the reservoir forming period, and established the quantitative model of crude oil cracking pressurization.

Firstly, according to the data about fluid inclusions tested by some experimental apparatus, the paleo-pressures were calculated by PVTx simulation method and basin simulation method. Next, based on the volume increment of crude oil cracking is equal to the volume reduction caused by overpressure compression, established the quantitative model for pressurization of total crude oil cracking. Moreover, equaled to the mass of residual oil plus the quality of cracked gas and pyrobitumen, put forward the quantitative model for pressurization of partial crude oil cracking and proposed these two model combined with some parameters, which included density and compressibility of oil, gas ,water and pyrobitumen and conversion rate of crude oil cracking and so on. Then, using these two models, calculated the intensity of pressurization of Shunnan gas reservoir. At last, the accuracy of the model was tested by restored paleo-pressure values.

The study shows that the southwest of Shunnan slope is a typical overpressure area. The formation pressure coefficients of Yijianfang formation and Yingshan formation are between 1.15 and 1.48, and those of Penglaiba formation are as high as 1.94. Based on the homogenization temperature of the inclusions and combined with burial history and thermal history, the paleo-pressure in Shunnan is restored through fluid inclusion method. There were two periods of overpressure in Cisuralian (292-280ma) and Neogene (21-2ma). The paleo-pressure coefficient of Neogene is 1.57-1.64, which is generally higher than that of Cisuralian(1.39～1.48). The main mechanism of overpressure in Shunnan area is the cracking of crude oil and the author tried to establish the quantitative characterization of crude oil cracking. The overpressure of crude oil cracking during Neogene reaches around 30 MPa, of which the contributions is respectively 66.7 %.

How to cite: Zhang, H. and Liu, H.: Quantitative characterization of crude oil cracking pressurization in the south of transition zone of Aman, Tarim Basin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-354, https://doi.org/10.5194/egusphere-egu21-354, 2021.

Tectonic evolution of Thrace Basin in the offshore area surrounding the Gokceada island has been widely studied except for pressure and temperature conditions. This study aims to fill this scientific gap while introducing the discovery of NW-SE oriented Gokceada Volcanic Zone, represented by extinct volcano geometries and chaotic seismic facies on seismic sections. Presence of such a significant heat source causes inevitable effects on pressure-temperature behaviour that might manifest itself as abrupt changes and makes the understanding of petroleum system essential. Hence, an integrated workflow involving seismic & well log interpretation, post-drill ppfg & temperature analysis, conversion of interval velocities into a 3D pore pressure model and 1D basin modelling has been conducted for the first time. 1D models focus especially on the oldest sedimentary unit of gas prone Thrace Basin, known as Early-Mid Eocene aged Karaagac Formation in the Northern Aegean region.

Basin analysis has yielded unique results by providing clues to better understand pore pressure mechanism and maturity rate of the Karaagac Formation, including type-III Eocene shales. The shallower parts of the Karaagac Formation, dominated by the Eocene deltaic succession, is in main oil window. On the other hand, between 4-5 km. depth at where the Eocene shales exist, maturity rate reaches late oil-wet gas. Maturity profile also suggests that entrance to the early oil window is at 38-35 Ma, corresponding to the Oligocene. It can be claimed that high burial rates caused fast maturation which can also be supported by the sedimentation rates, calculated approximately as 450 m/Ma. The post-collisional extensional regime in the Early-Mid Eocene, characterised by wedge-shaped growth strata on seismic sections, can be considered as the main reason for the high sedimentation rates. Thus, it can be proposed that the main causes for increasing pore pressures are disequilibrium compaction and possibly hydrocarbon generation process.

Gokceada Volcanic Zone can be suggested as another driving force of fast maturation. Temperature profiles of two wells exhibit a significant increase towards the volcanic zone. In terms of geothermal gradients, the abrupt changes resulted with temperature fluctuations. Gradient values change between 35-45 ⁰C/km during Eocene-Oligocene at when the basin has experienced severe volcanism due to the crustal thinning. By the ongoing burial, values decrease and approach present-day conditions, ranging between 25-35 ⁰C/km. Present day temperatures reach at least 150-160 ⁰C interval for the deepest part of the basin.

Unlike the temperatures, pore pressures slightly decrease along the volcanic zone. This trend can be related to low porosities of products of intrusions and extrusions. For a better comparison of pressure conditions, a pore pressure cube has been reflected on the seismic sections. According to the model, present-day pressure values range between 5000-12000 psi in the Karaagac Formation. A very similar pressure profile has been illustrated by burial history charts and post-drill ppfg graphs as well. Although different inputs were used, outcomes of all methods validate each other. Therefore, findings of this study can act as a reliable foundation for pore pressure prediction and static temperature prognosis in the area.

How to cite: Uyanik, A.: Uncovering the impact of Gokceada Volcanic Zone on pressure and temperature conditions of Thrace Basin in the Northern Aegean Sea using 1D basin modelling and seismic velocity extraction, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-567, https://doi.org/10.5194/egusphere-egu21-567, 2021.

In recent years, new models of continuum mechanics, generalizing the classical theory of elasticity, have been intensively developed. These models are used to describe composite and statistically heterogeneous media, new structural materials, as well as in complex massifs in mine conditions. The paper presents an algorithm for the propagation of longitudinal acoustic waves in the framework of active well monitoring of elastic layered block media with inclusions of hierarchical type of L-th rank. Relations for internal stresses and strains for each hierarchical rank are obtained, which constitute the non local theory of elasticity. The essential differences between the non local theory of elasticity and the classical one and the connection between them are investigated. A characteristic feature of the theory of media with a hierarchical structure is the presence of scale parameters in explicit or implicit form. This work focuses on the study of the effects of non locality and internal degrees of freedom, reflected in internal stresses, which are not described by the classical theory of elasticity and which can be potential precursors of the development of a catastrophic process in a rock massif. Thanks to the use of a model of a layered block medium with hierarchical inclusions, it is possible, using borehole acoustic monitoring, to determine the position of the highest values ​​of internal stresses and, with less effort, to implement the method of unloading the rock massif. If it is necessary to conduct short-term predictive monitoring of geodynamic regions and determine a more accurate position of the source of a dynamic phenomenon using borehole active acoustic observations, it is necessary to use the values ​​of the tensor of internal hierarchical stresses as a monitored parameter.

How to cite: Hachay, O. and Khachay, A.: Study of internal stresses in rock massif within the framework of elastic layered block models with inclusions of the hierarchical structure of the L-rank., EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-300, https://doi.org/10.5194/egusphere-egu21-300, 2021.

The Ordos Basin is located in the central and western part of China, which is rich in oil resources in Mesozoic strata. Huanxian area is located in the west of the Ordos Basin, covering an area of about 3000 km². With the wide distribution of Jurassic low resistivity reservoir, it is difficult to identify reservoir fluid by logging, which restricts the efficient promotion of oil resources exploration and development in this area to a certain extent.

Based on the basic geological law, this study makes full use of the data of oil test conclusion, production performance and formation water analysis to deeply analyze the genesis of low resistivity reservoir in this area. The average formation water salinity of Jurassic in Huanxian area is 63.5g/l. Through the correlation analysis of mathematical methods such as fitting and regression, the formation water salinity and reservoir apparent resistivity show a good negative correlation in the semi logarithmic coordinate, and the correlation coefficient is 0.78. Therefore, it is considered that the main controlling factor for the widespread development of low resistivity reservoir in this area is the high formation water salinity. Irreducible water saturation, clay mineral content and nose bulge structure amplitude are the secondary controlling factors for the development of low resistivity reservoir in this area, and their correlation coefficients with apparent resistivity are 0.23, 0.25 and 0.31, respectively.

On the basis of clarifying the genesis of Jurassic low resistivity reservoir in Huanxian area, the comprehensive identification of reservoir fluid type by logging is carried out. For the whole area, there are obvious differences in geological characteristics, so conventional methods such as cross plot method of acoustic time difference and apparent resistivity can not effectively identify reservoir fluid. According to the main controlling factors of reservoir apparent resistivity, the salinity of formation water is combined with apparent resistivity and resistivity index of reservoir respectively to establish the cross plot. Using these two kinds of cross plot, the accuracy of reservoir fluid type identification is 62.9% and 88.6% respectively. This method can meet the accuracy requirements of reservoir fluid identification, realize the rapid identification of reservoir fluid types in the whole area, and provide technical support for efficient exploration and development of Jurassic low resistivity reservoir in this area.

How to cite: Guo, J. and Zhou, L.: Analysis of main controlling factors and identification method of Jurassic low resistivity reservoir in Huanxian area, Ordos Basin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-664, https://doi.org/10.5194/egusphere-egu21-664, 2021.

This study is designed to evaluate the heterogeneity of the Chang 6 reservoirs in Study area, and to analyze the effect of heterogeneity on the distribution of oil. Mainly based on the sedimentary microfacies of the chang 6 reservoir, to calculate the mudstone by using the gamma curve in the logging curve, the separation layer and the interlayer were separated by 2 meters, then analyse the data of intercalation and interlayer by means of sedimentary facies, core and thin etc. We believe that the distribution of the sand in the plane and the heterogeneity of the reservoir is the main control factor of the oil distribution in the area, and it has a good area of oil, which own better properties, and the grain size more coarse; The main control factors of the Chang 6 reservoir in D area is the distribution and physical property of the sand body plane, the better the continuity and physical property of the sand body plane, and the better display of the oil-bearing property of the reservoir; The migration will occur in the vertical direction When the oil and gas meet the thinner interlayer, which will have a great influence on the distribution of oil and gas in the vertical direction; The full extent of oil and gas in the reservoir is controlled by the microscopic heterogeneity of the reservoir. In the study area, the reservoir heterogeneity influence the oil and gas distribution by the physical and lithologic characteristics, the distribution of sand body surface and the distribution of layer interval etc mainly. The study on the relationship between the heterogeneity and reservoir distribution of the Chang 6 reservoirs in the research area can be reasonably evaluated for the favorable areas of oil and gas reservoirs and prediction research areas, so as to guide the development of rational development plans in the next step.

How to cite: Yang, G. and Ren, Z.: Analysis on the heterogeneity of reservoir Chang 6 in D district of Ordos Basin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-564, https://doi.org/10.5194/egusphere-egu21-564, 2021.

We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximisation, although the oil recovery and CO₂ storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterising both physical and economic processes. We show that the production life of oil fields should not be fixed in optimisation studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.

The authors acknowledge funding from the Russian Foundation for Basic Research under grant # 20-31-80009.

How to cite: Chernova, A., Afanasyev, A., and Andreeva, A.: Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-6217, https://doi.org/10.5194/egusphere-egu21-6217, 2021.

Advances in the field of nanoscience and nanotechnology have resulted in the development of engineered nanoparticles, with unique physico-chemical properties, and their applications to all the sectors of industry, including the petroleum industry. This presentation will discuss several advances and applications of silica-based nanofluids in chemical enhanced oil recovery (EOR) processes related to interfacial phenomena in multiphase systems and physics of multiphase flow in porous media, and in particular the oil recovery characteristics resulting from nanofluids based low-salinity water flooding and chemical EOR processes. Laboratory experiments were carried out using homogeneous sandpack columns simulating oil-wet and water-wet reservoirs. To simulate oil-wet reservoirs, the sandpack columns were saturated with a light crude oil (West Texas Intermediate) at first. While in the case of the simulated water-wet reservoirs, these reservoirs were made by saturating the sandpack columns initially with a 1.0 wt% brine (NaCl) and then followed by an injection of the light crude oil. The subsequent oil-saturated (oil-wet system) and oil-brine mixture (water-wet system) within the sandpack columns were then subject to water flooding (non-sequenced recovery) or EOR processes (sequenced recovery) utilizing brine and/or surfactant as controls as well as low (0.01 wt%) and high (0.1 wt%) silica-based nanofluids. When compared with the high concentration of silica-based nanofluid, the low silica-based nanofluid concentration produced low fractional and cumulative oil recovery results in the water flooding process of oil recovery for both oil-wet and water-wet reservoir systems; however, the low silica-based nanofluid concentration was found to be the most effective with EOR process for both oil-wet and water-wet reservoir systems. Our findings permit to choose optimal concentrations of silica nanoparticles to be employed for either water flooding or EOR processes in order to increase the oil extraction efficiency.

How to cite: Darnault, C., Phibbs, B., McCarroll, C., and Blanton, B.: Chemical Enhanced Oil Recovery and Nanotechnology: Effects of Silica-Based Nanofluids on Low-Salinity Water Flooding and Enhanced Oil Recovery Processes in Oil-Wet and Water-Wet Reservoirs, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13079, https://doi.org/10.5194/egusphere-egu21-13079, 2021.

In the present study, we apply our validated stoichiometric equilibrium model [1], based on direct minimisation of Gibbs free energy, to predict the synthesis gas compositions produced by in-situ coal conversion at three European coal deposits. The applied modelling approach is computationally efficient and allows to predict synthesis gas compositions and calorific values under various operating and geological boundary conditions, including varying oxidant and coal compositions. Three European coal deposits are assessed, comprising the South Wales Coalfield (United Kingdom), the Upper Silesian Coal Basin (Poland) and the Ruhr District (Germany). The stoichiometric equilibrium models were first validated on the basis of laboratory experiments undertaken at two different operating pressures by [2] and available literature data [3]. Then, the models were adapted to site-specific hydrostatic pressure conditions to enable an extrapolation of the synthesis gas composition to in-situ pressure conditions. Our simulation results demonstrate that changes in the synthesis gas composition follow the expected trends for preferential production of specific gas components at increased pressures, known from the literature, emphasising that a reliable methodology for estimations of synthesis gas compositions for different in-situ conditions has been established. The presented predictive approach can be integrated with techno-economic models [4] to assess the technical and economic feasibility of in-situ coal conversion at selected study areas as well as of biomass and waste to synthesis gas conversion projects.

[1] Otto, C.; Kempka, T. Synthesis Gas Composition Prediction for Underground Coal Gasification Using a Thermochemical Equilibrium Modeling Approach. Energies 2020, 13, 1171.

[2] Kapusta et al., 2020

[3] Kempka et al., 2011

[4] Nakaten and Kempka, 2019

How to cite: Otto, C. and Kempka, T.: Prediction of feasible synthesis gas compositions at three European coal deposits, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-2328, https://doi.org/10.5194/egusphere-egu21-2328, 2021.