Recent decreases in the world oil/gas reserves imply that energy producers and consumers are facing a major challenge. Therefore, a thorough exploration and production strategy needs to be carried out to sustain the world energy production level. This session is devoted to present the newest advances in oil and gas exploration and production technologies as well as well as their associated environmental risks and economic benefits. It will be regarded new geophysical monitoring methods for intensify the oil exploration. They will be supported by new results in modelling and inverse problem solutions in a frame of block layer structures with hierarchic inclusions of different anomaly parameters features.

Convener: Olga Hachay | Co-conveners: Mohammed FARFOUR, Said GACI
| Attendance Thu, 07 May, 14:00–15:45 (CEST)

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Chat time: Thursday, 7 May 2020, 14:00–15:45

Chairperson: Said Gaci
D864 |
Yuri Galant, Yuri Pikovskiy, and Pavel Čížek
  • The work was initiated with the aim of assessing the prospects of the Rhine Rift oil potential. The search technique was based on the analysis in basalts of Polycyclic Aromatic Hydrocarbons (PAH) which are an indicator of the oil content of deep horizons. Samples of Rocks were taken from Quarry and Outcrops. PAH analysis was carried out at Moscow State University. All samples contain PAH. 11 components detected. The total amount of the components is 0.052834 mg / kg. Rate of 4 components: Naphthalene and homologous, Phenantren, Difenil, Benz (ghi) perylene is equal more a half of all components (58%). Our study revealed the typical association of PAH, which are characteristic of the oil fields: Phenanthrene, Chrysene, Pyrene, Benz(a)pyren. PAH provide evidence of probable former generation and migration of endogenous hydrocarbons. Existence such components as Phenanthrene, Chrysene, Pyrene, Benz(a)pyren pointed on migrations of Hydrocarbons from depth - (From Oil - deposit?). Samples analyzed show on the existence Hydrocarbons migrations of gases and a more Heavy Hydrocarbons. Favorable geological settings of Rhine Rift, such as seismic activity, new tectonic movements, and presence of Basalt, decompressed rocks of mantle, rift stretching mode, and favorable geochemical indications, such as existence of typomorphic oil-associated PAH (Phenanthrene, Chrysene, Pyrene, Benz(a)pyren), presence the components resembling on compositions of Moravia oil, are positive factors for oil discovery in the Rhine Rift. Data received can serve as base for set detail works for seeking cluster of oil! And in the first instance at areas: Bad Urah, Kaizertuhl-Shellingen.

How to cite: Galant, Y., Pikovskiy, Y., and Čížek, P.: Prospects for oil discovery in the Rhine Rift (Germany), EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-99, https://doi.org/10.5194/egusphere-egu2020-99, 2020.

D865 |
Qian Wang, Paul Glover, and Piroska Lorinczi

Injection of CO2 into subsurface reservoirs occurs during Enhanced Oil Recovery (EOR) and also during Carbon Capture and Storage (CCS) operations. During CO2 injection, the efficacy and distribution of fluid flow in sandstone reservoirs is controlled by the pore-throat microstructure of the rock. Furthermore, CO2 injection promotes asphaltene precipitation on the pore surface and can also affect fluid flow in the pore throats, decreasing the permeability and altering reservoir wettability. In this work, miscible and immiscible CO2 flooding experiments under reservoir conditions (up to 70℃, 18 MPa) have been carried out on four samples with very similar permeabilities but different pore-throat structures in order to study the effects of pore-throat microstructure on formation damage. The features of pore-throat structure were evaluated by fractal theory, based on pore size distributions and rate-controlled porosimetry (RCP) mercury intrusion curves. Reservoir rocks with smaller pore throat sizes and more heterogeneous and poorer pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding 15-20% lower oil recovery and 4-7% greater decreases in permeability than that of rocks with homogeneous and better pore-throat microstructure. However, the water-wettability index of cores with larger and more connected pore-throat microstructures was found to drop by an extra 15-25% than heterogeneous core due to more asphaltene precipitation caused by the larger sweep volume of injected CO2 they consequently experienced, which is a disadvantage for EOR. In addition, immiscible flooding exacerbates the differences from 4-7% to 8-15% in permeability decline of the rocks with different pore-throat structures. Miscible flooding leads to more asphaltenes being precipitated from the crude oil, triggering in average an extra 11% change in wettability in comparison to immiscible flooding.


Keywords: CO2 flooding, asphaltene precipitation, pore size distribution, pore-throat microstructure, reservoir blockage, wettability alteration

How to cite: Wang, Q., Glover, P., and Lorinczi, P.: Effects of pore-throat structure on reservoir blockage and wettability alteration during CO2 injection, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-249, https://doi.org/10.5194/egusphere-egu2020-249, 2020.

D866 |
Jiaxu Chen and Xiaowen Guo

This study investigates the pathway of secondary oil migration which leads to the oil accumulation in Dongying Depression using basin modeling and pyrrolic nitrogen compounds. Modeling of oil migration pathways have been conducted for the third and fourth member (Es3&Es4) of Shahejie Formation including the reconstruction of burial history, thermal maturation and hydrocarbon generation processes, which are calibrated by parameters of pyrrolic nitrogen compounds and further reinforced by distributions of oil wells and fields. Carbazole parameters, such as 1-/4-methylcarbazole (1-/4-MC), 1,8-/2,7-dimethylcarbazole (1,8-/2,7-DMC) and benzo[a]carbazole/(benzo[a]carbazole + benzo[c]carbazole) ([a]/[a] + [c]) are presented to trace the oil migration pathways. The investigated 38 oil samples can be classified into three groups considering the effects of biodegradation, thermal maturation and the variation in source facies. The group I oils are derived from the lower interval of Es3, the group III oils are originated from the upper interval of Es4, and the group II oils are admixing of the source-rock intervals of Es3 and of Es4. Nine migration pathways can be determined using the abovementioned carbazole parameters. In specific, ratios of 1-/4-MC and 1,8-/2,7-DMC increase and [a]/[a] + [c] decreases as the increasing of oil migration distance. Meanwhile, the oil migration pathways resulted from basin modeling are in good agreement with those determined by pyrrolic nitrogen compounds. Most of the investigated oil wells and fields are located on the predicted migration pathways. In a nutshell, two favorable oil accumulation areas have been predicted along the migration pathways of oil in the Es4 member of Dongying Depression.

How to cite: Chen, J. and Guo, X.: Combination of basin modeling and pyrrolic nitrogen compounds to investigate the secondary oil migration pathway in the Dongying Depression of Bohai Bay Basin, China, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-1980, https://doi.org/10.5194/egusphere-egu2020-1980, 2020.

D867 |
| Highlight
Jing Luo and Furong Wang

The Jianghan Basin is a typical eastern fault depression salt lake basin in China, in which the Paleogene strata of the Qianjiang Sag are rich in shale oil resources. As a salt lake sedimentary basin, the developed Qianjiang Formation is a set of inter-salt oil-bearing strata, in which the salt rock strata are especially developed. There are many salt rhythms in the study area and a salt rhythm consists of a argillaceous dolomite layer between a salt rock formation and a salt rock formation. This study focuses on the 10th rhythm of the Qian 34 section of Qianjiang Depression (Eq3410). The samples were investigated by organic geochemical analysis and X-ray diffraction, and the pore structure characteristics of the reservoir were studied by argon ion polishing scanning electron microscope and low temperature nitrogen adsorption test. The research indicates that the average TOC of Eq3410 in Qianjiang Depression is 2.11% and the main distribution is 1%~3%; the type of organic matter is mainly Type II2 and Type II1; the overall maturity of organic matter is low maturity stage(Tmax is 412~441℃with an average of 423℃). The XRD data indicates that the mineral composition of the Qianjiang Formation shale oil reservoir is complex and have strong heterogeneity(quartz content in 2.3%~18.6% with an average of 9.5%, calcite content in 6.9~43.8% with an average of 12.8%, dolomite content in 2.5%~ 61.2% with an average of 27.2%, clay mineral content in 1.0%~45.2% with an average of 20.5%, glauberite content from 7.1% to 92.7% with an average of 22.9%). The pore types of shale oil reservoirs in Qianjiang Sag are complex and diverse and mostly are intergranular pores, which are mainly developed between detrital minerals or between detrital minerals and carbonate minerals. In carbonate mineral particles and quartz particles, some intragranular pores are visible, including calcite dissolution pores, internal pores of calcite and clay minerals, and internal pores of pyrite particles. And organic pores are rare in reservoirs due to the low maturity(Ro ranges between 0.5% and 0.7%). Nitrogen adsorption experiments showed that the pore size distribution of Eq3410 samples was dominated by mesopores and macropores. And the pore volume of the Eq3410 sample was most affected by the macropore pore volume, averaging 66.22%, followed by the mesopore pore volume with an average of 31.45%. To study and understand the characteristics of shale oil reservoir in Qianjiang Depression is conducive to mastering the regularity of shale oil enrichment and provides a basis for the exploration and development of shale oil.

How to cite: Luo, J. and Wang, F.: Characteristics of shale oil reservoirs in Qianjiang Formation, Qiangjiang Depression, Jianghan Basin, China, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-1982, https://doi.org/10.5194/egusphere-egu2020-1982, 2020.

D868 |
Yanhai Chang

Water /gas mobility and interaction in coal plays an important role in achieving the high performance of coalbed methane (CBM) recovery. A large volume of fracturing fluid is permeated into reservoir during the CBM development. The effect of the imbibed liquid on gas recovery is still controversial. To better understand this phenomenon, a systematical investigation of water dynamic imbibition and matrix permeability change during water imbibition were conducted experimentally using different coals collected from Qinshui, Ordos and Junggar Basin of China.

The research stimulates two different case of spontaneous imbibition and the special imbibition process and imbibition in different pores are concluded by analyzing the imbibition characteristics (i.e. imbibition ability, imbibition rate and imbibition dynamic). The water imbibes into smaller pores and larger pores simultaneously, in which the water imbibition rate is relevant to the porosity, permeability and wettability. The water imbibition in coal matrix can bring about the redistribution and existing state change of water, which probably one of the main factors causing the damage of the matrix permeability. By studying the permeability change and imbibition law, a permeability model is used to explain the influence of imbibition on permeability. Finally, the permeability is found as a function of sorting time and invasion depth, which will be useful for field applications.

How to cite: Chang, Y.: Water Imbibition of Coal and its Potential Influence on CBM Recovery, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-2893, https://doi.org/10.5194/egusphere-egu2020-2893, 2020.

D869 |
Cunjian Zhang, Jingdong Liu, and Youlu Jiang

Research on overpressure evolution and its formation mechanisms is of great significance for revealing reservoir formation mechanisms and predicting formation pressures in oil and gas reservoirs before drilling. However, research methods addressing overpressure evolution are not without issues. The fluid inclusion PVT simulation and basin simulation can be used to investigate the paleo-pressure.

The homogenization temperatures of inclusions were tested. The accuracy of the microscopic laser Raman spectroscopy analysis is too limited to fully test the components of gaseous hydrocarbon inclusions so that the organic components of the natural gas in the present-day gas reservoirs represented the gaseous hydrocarbon inclusions. In addition, the vapor-liquid ratio of gaseous hydrocarbon inclusions cannot be measured by CLSM. Firstly, A series of images at different slice depths was obtained by adjusting the focal length of a high-resolution microscope. Secondly, CorelDRAW software was used to calculate the areas of inclusions and bubbles; fitting functions were established between the inclusion areas and slice depths, and between the bubble areas and slice depths. Finally, the inclusion and bubble volumes were integrated to obtain the vapor-liquid ratios of the inclusions. PVTsim software can calculate the trapping pressures of inclusions. Combined with basin simulation, the evolution of paleo-pressure can be determined.

The above methods were used to investigate the paleo-pressure of the Upper Triassic Xujiahe Formation in the northeast portion of the Sichuan Basin. Overpressure began to develop in the Middle Jurassic period. Due to hydrocarbon generation taking place, the formation pressure increased rapidly from the Middle Jurassic period to the early Late Cretaceous period. Since the early Late Cretaceous period, the formation pressure has gradually decreased due to tectonic uplift and erosion. From the Oligocene period to the present, the formation pressure have increased again in local areas due to tectonic compression.

How to cite: Zhang, C., Liu, J., and Jiang, Y.: Determination of formation paleo-pressure and evolution process using gaseous hydrocarbon inclusions, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-3882, https://doi.org/10.5194/egusphere-egu2020-3882, 2020.

D870 |
Aliya Mukhametdinova, Natalia Bogdanovich, Alexey Cheremisin, and Svetlana Rudakovskaya

In recent years, the share of unconventional reserves in global oil production has grown. Exploration and development of unconventional resources require novel effective laboratory methods for characterizing the reservoir properties. The study and analysis of local shale deposits such as Bazhenov Formation (BF) in Western Siberia is a priority among non-traditional reservoirs. Wettability of the reservoir rock is one of the most important factors affecting the residual saturation and filtration properties in the formation. However, as multiple petrophysical studies show, conventional laboratory methods for characterizing the wettability are not applicable for this type of formations.

In this work, the fluid saturation and wettability of BF rock samples were studied utilizing a nuclear magnetic resonance (NMR) and the method of determining the wetting contact angle by a surface drop. We have provided the petrographic description of rocks using ultrathin sections for grouping the samples. In addition, we used data on the organic content (TOC) obtained by the Rock-Eval method on a HAWK RW instrument (Wildcat Technologies) and the results of lithological typing on thin sections using an Axio Imager A2m polarizing microscope (Carl Zeiss) for detailed analysis of NMR and contact angle methods results.

To assess wettability by NMR, T2 relaxation curves were constructed for extracted (cleaned), kerosene-saturated and water-saturated samples. A comparison of the relaxation spectra for kerosene and water enabled evaluation of the wettability for each by T2 log mean values. The calculation of the wetting angle was carried out for samples before and after the extraction, which revealed minor changes in the nature of the rock wettability because of cleaning. Thus, for this type of rock, the drop method for determining wettability turned out to be significantly sensitive to the shape of the OM distribution in the rock. Correlations built on wettability (by NMR results and calculated wetting angle) vs. TOC and lithotyping illustrated the dependence of rock wettability behavior on both the lithotype and the TOC content.

The calculation of the wetting angle provided an initial assessment of the surface wettability of the rock and made it possible to establish the relationship between the wetting angle and the content of organic carbon (TOC), which is relevant for BF rocks. The lithological description of thin sections was used to highlight groups with a similar wettability of the rock. For the integral characteristics of the samples wettability, the NMR relaxometry method was proposed.

How to cite: Mukhametdinova, A., Bogdanovich, N., Cheremisin, A., and Rudakovskaya, S.: Experimental Determination of the Shale Wettability, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-22681, https://doi.org/10.5194/egusphere-egu2020-22681, 2020.

D871 |
Andrey Khachay

A new method has been developed for modeling acoustic monitoring of a layered-block elastic medium with several inclusions of various physical, mechanical and phase hierarchical structures. An iterative process is developed for solving the direct problem for the case of three hierarchical inclusions of l, m, s-th ranks based on the use of 2D integral-differential equations. The degree of hierarchy of inclusions is determined by the values ​​of their ranks, which can be different. Hierarchical inclusions are located in one layer: the first is anomalously dense, the second is anomalously plastic, and the third is anomalously elastic and fluid-saturated density. The degree of filling with inclusions of each rank for all three hierarchical inclusions is different. The simulation results can be used in monitoring studies of the control of fluid return from oil fields developed as part of horizontal drilling.


How to cite: Khachay, A.: Algorithm for 2D Modeling of the Propagation of a Sound Wave in an N-layer Elastic Medium with Inclusions with Various Physical-Mechanical Properties of a Hierarchical Type Located in an Oil Reservoir, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-1324, https://doi.org/10.5194/egusphere-egu2020-1324, 2020.

D872 |
Ruijing Yan and Li Zhou

The stratum of Qingxudong Formation (Longwangmiao Formation) in Southern Sichuan-Northern Guizhou is generally thin in the west and north, thick in the east and south. The thickness of the stratum is 100m-250m, which is missing only in ya’an-chengdu area. The Qingxudong Formation in the study area mainly develop restricted platform facies and open platform facies deposits. The northern to central part of the study area mainly develop restricted platform facies, which can be divided into mixed tidal flat, inner beach, inter beach lagoon and other subfacies. The lithology is dominated by micrite-aplite dolomite and bioclastic dolomite with a thin layer of mud crystal limestone, siltstone, etc. Bean grain limestone and oolitic limestone can be seen at the bottom. The limestone composition of the Qingxudong Formation in the study area gradually increase from north to south, and the lithology of the Qingxudong Formation in the Songlin-Yankong area is dominated by micritie-aplite limestone and granular limestone, followed by dolomite. Open platform facies are developed, which can be furtherly divided into subfaces such as intra-platform beaches and inter-shoal beaches. The reservoirs in intra-platform subfacies of the Qingxudong Formation in the southern Sichuan-northern Guizhou area are relatively developed. Due to the high terrain of the beach, the karstification is favorable. Secondly, later-stage burial dissolution tends to selectively dissolve multi-phase intergranular cements or fillers to form intergranular dissolution pores, providing a lot of storage space.The analysis about the reservoirs’ physical properties of different microfacies suggest that, the porosity of the granular beach microfacies reservoirs ranges from 0.29% to 7.32%, with an average of 3.3%; the matrix permeability ranges from 0.006×10-3μm2 to 0.043×10-3μm2,with an average of 0.014×10-3μm2. the porosity of Yunping microfacies reservoir ranges from0.56% to 7.25%, with an average of 2.9%; the matrix permeability ranges from 0.006×10-3μm2 to 0.027×10-3μm2, with an average of 0.01×10-3μm2.The porosity of other microfacies reservoir ranges from 0.08% to 2.65%, with an average of 1.22%; the matrix permeability ranges from 0.008×10-3μm2 to 0.01×10-3μm2, with an average of 0.009×10-3μm2. It can be seen that the intra-platform subfacies have a constructive effect on reservoir development, which is the basis of reservoir development.

Keywords: Southern Sichuan-Northern Guizhou; Qingxudong Formation; sedimentary facies; reservoir physical property; reservoir characteristics

How to cite: Yan, R. and Zhou, L.: The depositional characteristics of Cambrian Qingxudong Formation in Southern Sichuan-Northern Guizhou and its control effect on reservoir beds, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-2421, https://doi.org/10.5194/egusphere-egu2020-2421, 2020.

D873 |
Jian Chen, Jie Xu, Zhenyu Sun, Susu Wang, Wanglu Jia, and Pingan Peng

Introduction: Organic acids which are commonly detected in oilfield waters, can partially enhance reservoir properties. Previous studies have suggested that cleavage of the oxygen-containing functional group in kerogen is a major source of organic acids. However, this cleavage is assumed to occur before the source rock enters the oil window. If this is correct, then these acids can dissolve only minerals in the source rocks. Presently, no detailed study of the generation of organic acids during the whole thermal maturation of source rocks has been conducted. It is unclear whether organic acids could migrate into reservoirs.

Aim: This research simulated the thermal evolution of source rocks in order to build a coupled model of organic acid and hydrocarbon generation, and investigate if organic acids generated in source rocks can migrate into reservoirs.

Methods: Three immature source rocks containing type I, II, and III kerogens were crushed to 200 mesh. These powders, along with deionized water, were sealed in Au tubes and heated to 220–360°C for 72 h (EasyRo 0.37-1.16%). All the run products, including organic acids, gas, and bitumen, were analyzed.

Results: At all temperatures, the organic acids dissolved in the waters are composed of formate, acetate, propionate, and oxalate. Acetate is the major compound with a modal proportion of >83%. The maximum yield of total organic acids was from source rocks containing type I kerogen (31.0 mg/g TOC), which was twice that from source rocks containing type II and III kerogens (13.3–15.4 mg/g TOC). However, for the type I and II kerogen-bearing source rocks, the organic acids reached a maximum yield (EasyRo = 1.16%) following the bitumen generation peak (EasyRo = 0.95%). Organic acids from type III kerogen-bearing source rocks reached their maximum yield (EasyRo = 0.95%) before the source rock entered the gas window (EasyRo > 1.16%).

Conclusions: Our data suggest that the generation of organic acids is coupled with the generation of oil from type I and II kerogen-bearing source rocks, but form earlier than gas from type III kerogen-bearing source rocks. As such, some organic acids dissolved in pore waters are possibly expelled from source rocks containing type I and II kerogen with oils, which can then migrate into reservoirs. Migration of organic acids into reservoirs from source rocks containing type III kerogen is also possible in some situations. For example, when a source rock is rapidly buried for a short period, such as in the Kuqa Depression, Tarim Basin, China, the generation interval of organic acids and gas is short. Both could be expelled outside and migrate upwards into reservoirs. In conclusion, organic acids derived from source rocks can contribute to reservoir alteration.

How to cite: Chen, J., Xu, J., Sun, Z., Wang, S., Jia, W., and Peng, P.: The coupled generation of organic acids and hydrocarbons during source rock maturation, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-3402, https://doi.org/10.5194/egusphere-egu2020-3402, 2020.

D874 |
Nian Liu and Nansheng Qiu

The geochemical characteristics and source of natural gases in the northern Subbasin, Bohai Bay Basin, eastern China are investigated systematically by the chemical components, stable isotopic compositions, noble gases isotopic compositions, and geochemical characteristics of associated oils. The results show that several genetic gases are identified in the study area, including thermogenic gas (sapropelic and humic gas), biogenetic gas (primary and secondary microbial gas) and mixed gas. Gases in the shallow strata (Ed, Es1, Es2, Es3 and some Es4 samples) are mainly oil-associated gases, whereas the gases in the deep strata (some Es4 samples, C-P and O) are mainly coal-derived gases and mixed-source gases. Some microbial gases including primary and secondary microbial gases can be identified in shallow Es1 and Es3 reservoirs. The carbon dioxide reduction under anaerobic conditions may be responsible for the anomalously heavy carbon isotope in carbon dioxide and light carbon isotope in methane in the biodegradation gases from the shallow strata (<1900 m), whereas carbon dioxide with heavy isotope compositions in the deeply buried Ordovician reservoirs may be the production of strong acids react with carbonate rocks during acidification and fracturing. The oil-associated gases in shallow strata are derived primarily from the Paleogene Es3 and Es4+Ek bearing sapropelic organic matters, whereas the coal-derived gases in the relatively deep reservoirs are mainly derived from the Paleozoic C-P coal-bearing source rocks and mixed organic matters in Es4+Ek. In addition, the dry gas (secondary cracking gas) in deep to ultra-deep carbonate reservoir may be the potential and favorable exploration field.

How to cite: Liu, N. and Qiu, N.: Geochemical characteristics and source of natural gases in the northern Jizhong Subbasin, Bohai Bay Basin, eastern China, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-3789, https://doi.org/10.5194/egusphere-egu2020-3789, 2020.

D875 |
anan wu

Research on hydraulic fracture initiation and vertical propagation

behavior in laminated tight formation

Anan Wu1, Bing Hou*1, Fei Gao2,Yifan Dai1,Mian Chen1

  • (1. State Key Laboratory of Petroleum Resources and Engineering, China University of Petroleum-Beijing, Beijing, China No.1 Cementing Company, Bohai Drilling Engineering Company Limited, CNPC, China. Renqiu,062550)


Abstract: The extent of hydraulic fracture vertical propagation extent is important in evaluating simulated reservoir volume for laminated tight reservoirs. Given that it is affected by the discontinuities (beddings, natural fractures, and other factors), fracture geometry is complex in the vertical plane and is different from a simple fracture in a homogeneous formation. Because the tight formation bedding is very developed, hydraulic fracture is difficult to spread vertically. Now,the propagation mechanism of hydraulic fracture in the vertical plane has not been well understood. To clarify this mechanism, several groups of large-scale tri-axial tests were deployed in this study to investigate the fracture initiation and vertical propagation behavior in laminated tight formation. The influences of multiple factors on fracture vertical propagation were studied.

we carried out the indoor hadraulic fracturing physical simulation experiments of the bedding-developed rocks. Tight cores obtained from the core well were wrapped with cement into 30 cm cubes, and samples were drilled and cemented. Before the experiment ,three-dimensional axial stress was applied to simulate the stratigraphic environment. When the stress was balanced, a certain flowing rate was set for hadraulic fracturing. After the fracturing work was completed, the cement block was opened to observe the hydraulic fracture propagation pattern.

The results showed that the ultimate fracture geometries could be classified into three categories: simple bedding fracture, slight turning fracture, stair-like fracture, and multilateral fishbone-like fracture network. Here comes some research knowledge:(1)When the difference between the vertical stress and the minimum horizontal principal stress is less than 12Mpa, the hydraulic fracture will only expand along the rock bedding plane Furthermore. (2)when the vertical stress difference is close to 14 MPa, hydraulic fractures will generate vertical fractures that will communicate multiple beddings of the rock. (3)Increasing flowing rate will cause a slight turning or jumping fractures and improve the complexity of fractures to a certain extent. (4)because of the influence of beddings and lithology,the fracture pressure is usually high.

Key words: Hydraulic fracturing, tight reversior Bedding plane, fracture morphology.

How to cite: wu, A.: Research on hydraulic fracture initiation and vertical propagation behavior in laminated tight formation, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-6427, https://doi.org/10.5194/egusphere-egu2020-6427, 2020.

D876 |
Fudong Xin, Hao Xu, and Dazhen Tang

Find out the changes in lignite properties accompanying dehydration will not only benefit the development of lignite CBM, but also play a guiding role in the underground gasification, combustion, coal cleaning, and carbon dioxide sequestration. Especially for the utilization of lignite coalbed methane resources, the dehydration can greatly improve the gas flow capacity in lignite reservoir with originally low permeability. Through nuclear magnetic resonance (NMR) tests, imaging experiments, and permeability tests, the changes of reservoir properties of different lithotypes of lignite during dehydration were comprehensively summarized. Additionally, a bituminous coal sample was also tested as a supplement to better understand the impact of coal rank on changes in reservoir structure after dehydration. Drying and dehydration will cause the coal matrix to shrink, and NMR results show that its effect on the structure of the lignite reservoir is shown in two aspects: the rapid expansion of large fractures, and the shrinkage of relatively small pores. Due to the influence of material composition and molecular structure, the change of the reservoir structure of bituminous coal after dehydration was not as obvious as that of lignite. Overall, dehydration improves both total porosity and connected porosity. However, due to the shrinkage of the matrix, the pore connectivity may deteriorate. As a paramagnetic material, Mn2+ dissolved in water shorten the transverse relaxation time of the 1H by dipole-dipole interaction (dipolar coupling) between the electronic magnetic moment of the ion and the nuclear magnetic moment of the hydrogen proton. As Mn2+ enters the connected pores, the signal of the water in these pores is dampened and becomes invisible. It is clear that the disappeared portion on the T2 spectrum represents the connected pores into which Mn2+ can enter. By combining the NMR experiment with Mncl2 imbibition, it was found that the connectivity of some of the micro-mesopores was worsened: the disconnected porosity of the matrix lignite and xylite lignite after 12 hours of drying increased from 0.32% and 0.08% to 1.19% and 1.82%. NMR imaging and X-ray computed tomography imaging results show different fracture propagation rules of different types of lignite during drying. Matrix lignite can quickly generate evenly distributed fractures with drying, but these fractures are short in length and poor in orientation; xylite lignite has a lower dehydration efficiency, and the fractures generated follow a pattern that gradually expands from the surface to the interior, but can eventually form a long and well-oriented fracture network. The results of permeability tests show that dehydration greatly improves the permeability of lignite reservoirs. Since coal permeability is highly stress-sensitive, the effect of stress on the permeability of these samples before and after dehydration was further analyzed. Although the effect of stress on permeability after drying has increased, the effective permeability after drying is always orders of magnitude higher than before drying. In sum, dehydration is an effective measure to improve the seepage capacity of lignite reservoirs, which provides a basis for the efficient development of lignite CBM and the clean use of lignite resources in other ways.

How to cite: Xin, F., Xu, H., and Tang, D.: Change in reservoir structure of different lithotypes of lignite with dehydration, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-7404, https://doi.org/10.5194/egusphere-egu2020-7404, 2020.

D877 |
aobo zhang and shuling Tang

In order to investigate the controlling of the sedimentation environment evolution on the coalbed methane system in Xishanyao Formation on the southern margin of Junggar Basin,using drilling wells,logging wells,outcrops and other data with the assistance of fine analysis methods,such as scanning electron microscope and image granularity,the coalbed methane system was divided,and its sedimentation evolution process was researched. The research results show that sand body of five types of sedimentation microfacies,whose water and air blocking capacity is sorted as “diversion channel<crevasse splay and beach dam<natural levee and shore-shallow lake”,can be identified in the research area,and single-well vertical coalbed methane system was divided; during the SQ1—SQ2 period,the rise of lake level led to the expansion of the development area of lacustrine facies,as well as the weakening of the coal-accumulating process which was mainly concentrated in the TST and LST stages of SQ1,and the east-west characteristic difference regarding the coalbed development and gas content appeared and was in accordance with the plane distribution of sedimentary facies; during exploitation,the coalbed methane system should be defined according to the blocking capability of surrounding rock,appropriate exploitation methods should be selected according to the characteristics of each system,and the avoidance of vertically joint-developing sandstone aquifer and combined layer series of development should be paid attention to.

How to cite: zhang, A. and Tang, S.: Study on the composition and inter-layer correlation of coalbed methane system of Xishanyao Formation under sedimentary control, Southern Junggar Basin, NW, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-7747, https://doi.org/10.5194/egusphere-egu2020-7747, 2020.

D878 |
Elizabeth Trudel and Ian Frigaard

Canada is an important player in the global oil and gas industry and is ranked fourth largest producer of natural gas and crude oil. Alberta and British Columbia are the two largest producing provinces of natural gas with a combined 98% of the national production. Recent development of the Montney formation, a low permeability unit, has led to a rise in the number of unconventional (horizontal and hydraulically fractured) wells drilled in Western Canada. Recent studies have shown that 28.5% of wells drilled starting in 2010 in British Columbia have reported an instance of wellbore leakage, and 4.0% of the wells drilled in Alberta during the same time period have also reported an instance of wellbore leakage resulting in several thousand wells with known leakage issues in these two provinces. Wellbore leakage is the unwanted flow of hydrocarbons from the reservoir, or a formation intersected by the well, through leakage pathways found along the wellbore and discharging to the atmosphere through either the surface casing assembly, surface casing vent flow (SCVF) or a surrounding permeable formation, gas migration (GM). In addition to the greenhouse gas emissions produced by wellbore, groundwater contamination may occur. Provincial regulations state that the remediation of cases of non-serious wellbore leakage, which represents 85.5% of the cases of wellbore leakage in Alberta and over 94% of the cases in British Columbia, can be delayed until the time of well abandonment. Less than 30% of the gas wells in these provinces have been abandoned and both provinces are seeing an alarming number of suspended wells which can be considered ready for abandonment. At which point, wells experiencing wellbore leakage will need to be remediated. Understanding of wellbore leakage, which occurs through leakage pathways such as radial cracks and microannulus, is limited. The model presented in this study relies on flow through a Hele-Shaw cell of varying thickness representing a microannulus. Microannulus thickness data is obtained through experimental data available in the literature. The aim of the model is to determine the flow rate of natural gas through a microannulus of varying thickness and the resulting permeability of the leakage pathways.

How to cite: Trudel, E. and Frigaard, I.: Hele-Shaw Cell of Varying Thickness for Modeling of Leakage Pathways , EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-10609, https://doi.org/10.5194/egusphere-egu2020-10609, 2020.

D879 |
| Highlight
Gabriela Gonzalez Arismendi and Kalis Muehlenbachs

Despite the emerging new technology in renewables, society still relies overwhelmingly on fossil fuels for energy. Overall, data indicate that there is an increase in natural gas production as a less expensive, more “environmentally friendly” and efficient resource.  ẟ13C studies are a standard tool to understand the origin, migration and mixing of natural gases. In the Western Canada Sedimentary Basin (WCSB), which is a major hydrocarbon producer, the isotopic variability of formations gases have been well characterized (i.e., Tilley and Muehlenbachs, 2006). Industry implements such information for predicting where economically substantial amounts of natural gas form. Ethane isotopic fingerprinting is more diagnostic of such thermally matured gases. Thus, it is a useful tool to identify unwanted fugitive gas emissions associated with petroleum resource development and activities. In an initiative to better understand, constrain and ultimately mitigate this historic engineering challenge, we contoured the isotopic values of 2800 SCV wells and 1200 GM, and used the production data to identify the source of gas emissions. Our outcomes are not only valuable to industry, but also to regulatory agencies to increase awareness about the use of organic (e.g. n-alkanes) and inorganic (e.g. CO2) carbon isotope fingerprinting as retrospective environmental indicators at a local and regional scale.


Tilley, B., and Muehlenbachs, K. (2006). Gas maturity and alteration systematics across the Western Canada Sedimentary Basin from four mud gas isotope depth profiles. Organic Geochemistry, 37(12), 1857–1868.

How to cite: Gonzalez Arismendi, G. and Muehlenbachs, K.: The Western Canada Sedimentary Basin energy wells: δ13C gas isotopic mapping, from production to ground migration , EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-11963, https://doi.org/10.5194/egusphere-egu2020-11963, 2020.

D880 |
Taehun Lee, Kyungbook Lee, Hyunsuk Lee, and Wonsuk Lee

Artificial intelligence is applied in various fields of human life and is being actively studied and applied in the oil fields. Especially, the digital oil field, which has recently been spotlighted, is required to simulate the reservoir using artificial intelligence. However, there is almost little research to date. Therefore, in this study, we applied TDRM using artificial intelligence technology to Zama field located on the land of Canada. The required static and dynamic data were obtained from Accumap, a Canadian well information S/W. As a result, the reservoir model was constructed successfully and the well location optimization could be performed in a short time using TDRM.

How to cite: Lee, T., Lee, K., Lee, H., and Lee, W.: Well location optimization of Zama reservoir using top down reservoir modeling(TDRM), EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-12089, https://doi.org/10.5194/egusphere-egu2020-12089, 2020.

D881 |
Hongyang Jiang, Zhenxue Jiang, and Xin Li

Compared with marine shale with plentiful research and successful exploration, fewer studies on transitional shale reservoirs limit further exploitation of shale gas. In this paper, comparative analysis, between Lower Silurian marine shale and Upper Permian transitional shale in the Upper Yangtze region, is carried out to analysis pore features of both shales and the main controlling factors, which can provide theoretical guidance for further exploration. A combination of methods is ultilized in terms of organic-chemistry geology measurement, X-ray diffraction (XRD), high-pressure mercury injection, gas adsorption, and focused ion beam milling and scanning electron microscopy (FIB-SEM). The results show that Lower Silurian marine shale and Upper Permian transitional shale have similar organic matter (OM) abundance (2.72% and 2.31%) and thermal degree (2.56wt%Ro and 2.68wt%Ro). However, the kerogen of Lower Silurian shale is type I derived from algae and plankton, while that of Upper Permian shale is mainly type III from higher plant debris. As for mineral composition, Siliceous minerals (> 43wt%) account for the majority in Lower Silurian shale, while clay (> 57wt%) is the main mineral in Upper Permian shale. Variations in material basis trigger to differences in pore characteristics between the two shales. Firstly, the pores in Lower Silurian shale are mostly hosted by OM with an average pore diameter of 7.94 nm, while Upper Permian shale mainly develops pores associated with clay minerals with an average pore diameter of 28.60nm. Moreover, Lower Silurian shale presented relatively higher pore properties than Upper Permian in both average pore volume (0.020ml/g and 0.015ml/g) and average pore surface area (7.99 m2/g and 1.2 m2/g). Various factors lead to the differences in pore types and pore properties between the two shales. For marine shale, OM with thermal convertibility tend to be mobilizable and porous. OM-hosted pores are the dominated type which is controlled by OM abandauce and thermal degree. However, in transitional shale, OM is featured by phase stability without porous feature. Pores associated with clay flakes are the main type which is controlled by the specifc material composition. Hence, the discrepancies of pore properties may be attributed to material diversities between marine shale and transitional shale.

How to cite: Jiang, H., Jiang, Z., and Li, X.: Different controlling factors of pore features between marine shale and transitional shale in the Upper Yangtze region, South China, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-12146, https://doi.org/10.5194/egusphere-egu2020-12146, 2020.

D882 |
Parvin Mehr, Bradley M. Conrad, and Matthew R. Johnson

Flares in the upstream oil and gas (UOG) industry are an important and poorly quantified source of black carbon (BC) emissions and may be a dominant source of black carbon deposition in sensitive Arctic regions (Stohl et al. 2013).  Accurate estimation of flare BC emissions to support informed policy decisions, accurate climate modeling, and new international reporting regulations under the Gothenburg protocol is a critical challenge.  To date few studies have focussed on the primarily buoyancy-dominated turbulent non-premixed flames typical of upstream oil and gas flares, such that existing emission factor models are highly uncertain (see (McEwen and Johnson 2012)).  Although recent progress has been made in measuring black carbon from flares in the field (e.g. (Conrad and Johnson 2017; Johnson et al. 2013), data have also shown that emissions of individual flares may vary by more than 4 orders of magnitude. 

The objective of the current study is to develop a robust data-backed model to predict black carbon emissions from flares considering variations in flare gas composition, flow rates, and stack diameters.  Laboratory measurements of black carbon (soot) for a range of turbulent non-premixed jet diffusion flames of up to 3 m in length were performed at the Carleton University Flare Facility in Ottawa, Canada.  Two hundred and thirty cases spanning five flare stack diameters (25.4 to 76.2 mm), exit velocities from 0.16 to 15.15 m/s, and a broad range of industrially-relevant multicomponent (C1-C7 hydrocarbons, CO2, N2) flare gas compositions were studied.  Emissions were captured in a large (~3.1 m diameter) sampling hood and forwarded to gas- and particulate phase analyzers. 

Black carbon concentrations were measured via a Sunset Labs thermal-optical instrument using the OCECgo software tool (Conrad and Johnson 2019) to quantify uncertainties via Monte Carlo analysis.  BC yields were subsequently calculated using a mass-balance methodology (Corbin and Johnson 2014).  Variability in BC yield was well-predicted by an empirical model incorporating both the aerodynamic and chemistry effects.  For this range of conditions, it was observed that primary independent variables (such as exit velocity and higher heating value) act as reasonable surrogates for sooting propensity.  Further experiments are underway to test the proposed model over a broader range of conditions.  However, results to date represent a significant advance in our ability to predict black carbon emissions from flares.

How to cite: Mehr, P., Conrad, B. M., and Johnson, M. R.: Experimental Modelling of Black Carbon Emissions from Gas Flares in the Oil and Gas Sector, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-12187, https://doi.org/10.5194/egusphere-egu2020-12187, 2020.

D883 |
Dina Gafurova, Anton Kalmykov, Dmitriy Korost, Tikhonova Margarita, and Vidishcheva Olesia

The Domanic and Bazhenov Formations are the largest unconventional oil and gas resources in Russia. In this regard, research of mechanisms and transformation features of pore space structure, as well as hydrocarbon fluids composition are of greatest interest. In recent time technologies for modeling of thermal maturation of rocks under close to reservoir conditions similar, such as pyrolysis and aqua pyrolysis can be used. The natural process of organic matter maturation has a direct impact on the rock pore space alterations. Experimental studies of rocks (more than 100 experiments) with monitoring of the pore space using computer microtomography were performed. As a result of research, it was possible to clarify the influence of rock characteristics on the transformation of the pore space, as well as on the hydrocarbons composition. The structural features of the mineral part of the rock control the distribution of organic matter: for rocks with a layered distribution of organic matter, the formation of a crack system is characteristic. In samples with a massive structure, newly formed pores were noted. The rocks with the highest organic matter content from 20% were characterized by the formation of lenses (Fig. 1). The content of organic matter and its maturity directly affect the volume of the newly formed pore space.

Performed investigations allowed to reveal the trends of hydrocarbons generation in source rocks and unconventional reservoirs formation. Also heating of rocks by various methods under reservoir conditions approved potential of tertiary methods of reservoir stimulation. Pyrolysis in-situ of Bazhenov and Domanic source rocks would allow to generate “synthetic” oil of similar to natural one composition and increase permeability of rocks by pores and cracks formation.

This work was partially (fully) supported by RFBR grant 18-35-20036.

How to cite: Gafurova, D., Kalmykov, A., Korost, D., Margarita, T., and Olesia, V.: Porosity and hydrocarbon composition evolution in shales from the Domanic and Bazhenov Formations: Insights from pyrolysis and aqua thermolysis experiments., EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-17423, https://doi.org/10.5194/egusphere-egu2020-17423, 2020.

D884 |
Yanhua Xu and Dengfa He

Title: Paleogeographic framework and Paleo-sedimentary environmental restoration in the Lower Part of Yanchang formation in Triassic of Ordos Basin, China

Ordos basin is a craton basin, rich in coal, oil and natural gas resources. The Yanchang formation includes the lower part (Chang 10- Chang 8 oil bearing intervals) and the upper part (Chang 7- Chang 1 oil bearing intervals) in which we found many hydrocarbon-rich depressions. The sedimentary period of Chang 10-Chang 8 formation is the transition stage from the North China Craton depression basin to  Ordos basin due to the influence of the Indosinian movement. Previous studies mainly focused on the the interior of the present residual basin rather than the peripheral of the basin.

Twenty five outcrops out of Ordos basin and one hundred drilling cores in the basin are used and multiple methods including microscope, SEM observation , the major-trace elements analysis ; zircon U-Pb geochronological studies and seismic profile interpretation are applied to study the paleoredox, paleosalinity , paleoclimate and provenance of the the lower part of the Yanchang formation in the Ordos basin.

It is concluded that: (1)the main charateristics of the sedimentary facies about Chang 10 is rivers-deltas- shore-shallow lacustrine. The sedimentary facies of Chang 9 has the features of “multi-deltas surrounding the lake” with a transitory lake transgression. The main charateristics of Chang 8 is that the rivers became more powerful and the area of lake increased.(2) based on the zircon U-Pb age structure comparision beween the lower part the Yanchang formation and its periphery old land, the results indicate that it has consistent source, which are mainly northern and southern margin of Huabei block. However, the north-east Alashan old land and south Qinlin-Qilian tectonic belts may just supply few detrital sediments.(3) according to the seismic interpretation, we have found a large number of synsedimentary fault. Seismites developed in Chang9 and Chang8 and turbidite developed in Chang9. The distribution of the synsedimentary fault, seismites and turbidite can cetify that the structure activity was more active in the sedimentary period of the Yanchang formation.

How to cite: Xu, Y. and He, D.: Paleogeographic framework and Paleo-sedimentary environmental restoration in the Lower Part of Yanchang formation in Triassic of Ordos Basin, China, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-18048, https://doi.org/10.5194/egusphere-egu2020-18048, 2020.

D885 |
Pawel Jodlowski, Jakub Nowak, and Jan Macuda

The radiological risk in natural gas industry is mostly connected with radon (Rn-222) and its progeny: Po-218, Pb-214, Bi-214, Po-214 and Pb-210. The radon activity concentration in natural gas transported by gas pipelines varies in a wide range from dozens of Bq/m3 to several thousand Bq/m3 and mainly depends on the proximity of mines and geological structure of the deposit from which natural gas is extracted and transported. The radon progeny are ion metals, which are easily adsorbed on aerosols and deposited on the inner surfaces of gas pipe and other gas processing equipment such as scrubbers, compressors, reflux pumps, control valves and product lines creating thin radioactive films. Additionally, radon progeny together with aerosols (in contrast to radon) are retained on filters. In the aftermath of successive radioactive decay of short-lived radon progeny, long-lived Pb-210 is accumulated on filters.

             The paper presents the study of the Rn-222, Pb-210 connected with the transport of natural gas by the gas pipeline network in Poland. In the scope of the study the measurements of activity concentration of radon (Rn-222) in the gas samples (with alpha scintillation cells), radiolead Pb-210 in spent filter cartridges and dust samples collected from the gas pipeline network (with gamma-ray spectrometry) were performed.

             The results show that the Rn-222 activity concentration in natural gas varies from the detection limit of the applied method (30 Bq/m3) to around 1400 Bq/m3. Generally, the Rn-222 concentration in natural gas samples fluctuate around the mean radon concentration in the air of dwellings in Poland. The elevated radon activity concentrations in natural gas of several hundreds of Bq/m3 and more are observed at locations where the gas directly comes from local gas mines or where there is a blend of the national gas with imported one. Relatively low radon concentration in imported natural gas is connected with the fact that this gas was imported from abroad. Therefore, the time elapsed from the gas extraction to the collection of samples was relatively long. In consequence, the concentration of Rn-222 in the gas significantly decreased due to radon decay (3.4 days). Additionally, the temporal variability (daily and weekly) of the radon activity concentration in the natural gas were assessed. The results show radon concentrations does not statistically change in daily or weekly time scale.

             The Pb-210 activity concentration in dust ("black-powder") from gas filters and spent filter cartridges is high and varies from 500 to 17000 Bq/kg and from 200 to 2900 Bq/kg respectively.

How to cite: Jodlowski, P., Nowak, J., and Macuda, J.: Radioactivity in the gas pipeline network in Poland, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-22215, https://doi.org/10.5194/egusphere-egu2020-22215, 2020.

D886 |
Askarova Aysylu, Cheremisin Alexander, Solovyev Aleksei, and Cheremisin Alexey

The considerable decline of conventional oil and gas reserves and respectively their production introduces new challenges to the energy industry. It resulted in the involvement of hard-to-recover reserves using advanced enhanced oil recovery (EOR) techniques. Thermal methods of EOR are recognized as most technically and commercially developed methods for the highly viscous crude. High-Pressure Air Injection (HPAI) is one of the thermal production methods that reduce oil viscosity and increases the recovery (Yoshioka et al, Moore et al., 2002). HPAI has been already effectively applied for different types of reservoirs development and proven to be economically feasible. 

The application performance of the HPAI technology strongly depends on the quality of experimental and numerical modeling conducted on the the target object basis. Prior to the field tests physicochemical and thermodynamic characteristics of the process were studied. Further consequent numerical modeling of laboratory-scale oxidation experiments and field-scale simulation were conducted to estimate HPAI method feasibility based on the results of oxidation studies. A medium pressure combustion tube (MPCT) oxidation experiment was carried out to provide stoichiometry of the reactions and field design parameters. A 3D numerical model of the MPCT experiment was constructed taking into account the multilayer design, thermal properties, heating regimes and reaction model (Sequera et al., 2010; Chen et al., 2014; Yang et al., 2016). The “history” matched parameters such as fluid production masses and volumes, temperature profiles along the tubes at different times and produced gas composition demonstrated good correspondence with experimental results. The results obtained during the experiment and modeling of MPCT (fluid properties, relative phase permeability, kinetic model, technological parameters) were used in field-scale modeling using various thermal EOR scenarios. Air breakthrough into production wells was observed, thus a 2 percent oxygen concentration limit where implied. The overall performance of four different scenarios was compared within 15 years timeframe. The development system was also examined to achieve the maximum economic indicators with the identifications of risks and main uncertainties.


How to cite: Aysylu, A., Alexander, C., Aleksei, S., and Alexey, C.: Evaluation of the subject geological area suitability for oil recovery by High-Pressure Air Injection method, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-22560, https://doi.org/10.5194/egusphere-egu2020-22560, 2020.