Deep geothermal heat represents a massive opportunity to provide low-carbon district heating for towns and cities. Space heating represents a large percentage of total energy use in Northern Europe; nearly 40% of all UK energy use (BEIS, 2022) is for heating, predominantly from natural gas. Global pressures on the international gas market and the urgent need to decarbonise the heating system to deliver NetZero highlight the need for identifying renewable heat sources to replace gas.

However, finding reliable high temperatures requires drilling to several-kilometres depth. Achieving sustainable heat supply, without depletion, means that wells must intersect deep permeable strata which are impossible to detect from the surface. Well prognosis is therefore heavily reliant on data from legacy drilling. Drilling is always an expensive process and any operational issues can impose significant additional costs, as rigs capable of drilling such boreholes have rental rates of many €1000s per day. Even when the drilling is completed, financial returns are slow and reaching profit takes years. Therefore, reassuring investors requires de-risking such projects through mitigating avoidable additional costs.

Digital data from wells penetrating many kilometres are needed for understanding subsurface processes. Only small numbers of deep geothermal wells have been drilled, so the best alternatives are legacy hydrocarbon exploration boreholes; these are good analogies for geothermal wells as they rely on permeability at depth. Such legacy hydrocarbon data are increasingly openly available through National Data Repositories (NDR) and/or Geological Survey Organisations. 

The EU Horizon programme funded OptiDrill project (101006964) is using legacy well data to optimise the drilling process, by linking drilling parameters with petrophysical data to understand the constraints upon the drilling processes. This will allow causes of interruptions to drilling and unnecessary down-time to be assessed and hopefully eliminated.

NDR archives have been trawled for modern drilling and logging data that admits optimal analysis. An Isolation Forest machine-learning algorithm was used to analyse Measurement-While-Drilling derived Rate-of-Penetration data and geophysical log data, identifying zones of anomalous responses quickly and without supervision. Examination of newly available daily drilling reports (DDR) data, from the NDR, allows these anomalous responses to be associated with breaks in drilling operations and their causes to be understood. This allows both refinement of the anomaly-detection algorithm for the identification of drilling problems, and differentiation between problems caused by drilling or geological issues and those caused by operational and logistical difficulties (e.g. procurement delays). Where drilling issues are identified these can be used to develop remediation strategies for future wells drilled in similar conditions, through revised drilling programmes and optimised well designs that minimise avoidable drilling operations such as unnecessary round trips etc.

How to cite: Kingdon, A., Arran, M., Fellgett, M., Jamali, S., Knauer, H., and Mallin, K.: Optimising the drilling process for geothermal wells using legacy oil field data and machine learning, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-3408, https://doi.org/10.5194/egusphere-egu23-3408, 2023.

Geothermal reservoir characterisation benefits from the oil and gas petrophysics experience in areas such as porosity and permeability estimation, rock-fluid interactions etc.. Permeability is the crucial parameter in assessing water transmissibility with geothermal reservoirs. Permeability impairment is a key worry due to rock-fluid interactions within the reservoir life cycle management. The laboratory techniques help in recreating the reservoir conditions and determining formation damage. Uncertainty increases for tight geothermal reservoirs (permeability < 1 mD), which often contain significant amounts of clay that reacts with water or ionic species during hydraulic fracturing used in Enhanced Geothermal Systems.

Clay-bearing sandstones are complex reservoirs since their clay minerals actively interact with water, causing formation damage by clay swelling and migration mechanisms. Core flooding experiments study the clay minerals' behaviour in different water conditions - e.g. salinity, electrolytes species, pH, and temperature - helping to understand the impact of clays on reservoir quality and identifying optimal conditions to reduce formation damage.

A multi-salinity experiment was undertaken to study the clay effect of three tight clay-bearing sandstones, samples A, B and C, of different reservoir provenance. Sample A has a core porosity of 18%, gas permeability of 1.28 mD, and 15.5%v/v of XRD clay minerals and kaolinite as the primary group. Sample B has a core porosity of 20.2%, gas permeability of 0.56 mD, and 37%v/v of XRD clay minerals and chlorite as the primary group. Sample C has a core porosity of 18.8%, the gas permeability of 1.95 mD, and 36.3%v/v XRD clay minerals and mica as the primary group. The experiment consisted of flooding brine with constant inflow at different salinities and monitoring the rock resistance, pressure drop, and outlet brine conductivity. High- and low-salinity batteries were flooded, ranging from 200,000-75,000 and 50,000-0 ppm NaCl respectively, at a constant room temperature of 21⁰C. In addition, the brine permeability was measured in steady- and unsteady-states techniques, and pore size distribution was NMR scanned at each run per battery.

Permeability impairment increased in all samples. Samples A (kaolinite) and C (mica) show a staggered increase in the salinity range. In contrast, sample B (chlorite) shows a peculiar upside-down trend in the low-salinity range. Clay migration was detected in the last brine runs since fines grain were released in the outflow. NMR T2 distribution shows a bimodal pore distribution for samples B and C, and the pore-throat connectivity rearranges as salinity decreases in both samples, indicating a clay swelling mechanism. The cation-exchange capacity (CEC) of samples A and C resulted in 3.7 and 3.6 meq/100g, respectively, and sample B was 71.5 meq/100g. CEC values are directly related to the clay mineral content. The highest CEC (sample B) relates to the upside-down permeability impairment with clay swelling. This investigation contributes to the geothermal reservoir characterisation in understanding how the water salinity controls the clay effect in tight clay-bearing sandstone reservoirs.

How to cite: Navarro-Perez, D., Fisher, Q., Lorinczi, P., Allshorn, S., and Grattoni, C.: Multi-salinity core flooding study in clay-bearing sandstones, a contribution to geothermal reservoir characterisation, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-8407, https://doi.org/10.5194/egusphere-egu23-8407, 2023.

Coaxial Deep Borehole Heat Exchanger (DBHE) provides an alternative way to extract geothermal energy by circulating a working fluid without producing geofluids or performing injection processes. It can be used to avoid induced seismicity issues caused by injection operations in hydrothermal doublets or to repurpose damaged or non-productive wells. A detailed numerical model is required to accurately capture as well the thermo-hydraulic processes within the DBHE and the cooling effects in the surrounding reservoir. This numerical model is often high dimensional. For a real-time monitoring purpose and optimization study, a direct numerical simulation with this model is computationally intractable.

In this study, we use a physics-based machine learning method to reduce the computational cost of the performed forward model run. The physics-based machine learning method here is based on the non-intrusive reduced-basis method which expresses a physical solution in a linear combination of basis functions and weights. It is a model-order reduction technique that is mathematically proven to produce physically consistent predictions. The structure of the physics is maintained in basis functions and a machine learning model is deployed to calculate the weight for each basis function.

We show the advantages of using the physics-based machine learning method by applying it to the planned coaxial DBHE in Eden (Cornwall, UK). The forward simulation is performed using the open-source simulator GOLEM, a finite-element (FE) based simulator that is built within the MOOSE framework. In this study we provide a running time comparison between the FE simulations and the physics-based machine learning simulations. We will also evaluate the accuracy of the physics-based machine learning predictions towards the FE solutions. Here, we would like to emphasize the significant computational speed-up that allow us to obtain new temperature and pressure state predictions in real-time context and to perform optimization with numerous iterations.

How to cite: Teza, D., Santoso, R., Koltzer, N., Degen, D., Bennett, T., and Wellmann, F.: Physics-based machine learning for modeling thermo-hydraulic processes in a coaxial deep borehole heat exchanger, considering an explicit reservoir-wellbore representation: A case study of Cornwall, UK , EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-16369, https://doi.org/10.5194/egusphere-egu23-16369, 2023.

The decarbonization of communities and their energy supply is considered as a contemporary priority path forward, although it poses many challenges. In this scenario, geothermal energy can cover a pivotal role in the energy transition and in a wider spread of renewable energies. Moreover, the possibility to reuse or modifying existing wells for geothermal purposes is becoming a hot and promising topic. In Italy, there are more than 8000 abandoned/inactive on-shore wells drilled for hydrocarbon exploration subsequently abandoned either for the end of the resource (exhausted well) or for sterility (barren well). This can represent a huge opportunity for geothermal energy exploitation. The drilled borehole available data, collected during the exploration activity, provide useful information about the sub-surface reservoirs, highly reducing the mining risk level, and allowing direct and low cost access to the sub-surface heat energy.

This work aims to analyse the feasibility of the retrofitting of abandoned oil and gas wells focusing on the Italian territory, proposing a selection methodology of wells starting from raw data collection. We want to evaluate which could be the best technical solutions for the retrofitting of an inactive oil&gas well considering the closed loop geothermal options, both coaxial and deep-U heat exchangers options. We decided to concentrate on the closed loop solution for the retrofitting because of its low environmental impact due to the absence of fluid exchange with the surrounding underground, despite the lower efficiency, compared to a system that involves the extraction of fluids from the subsoil.

A database, that collects data of wells drilled since the middle of 1900, provide by public information, is used, applying a first filter by considering the following discriminant parameters: the depth (more than 1000 m), the Bottom Hole Temperature (BHT), higher than 65°C, and the nearness of possible end-users. After this operation a set of 541 wells has been obtained.  A focus on the status of the well has been performed,  such as vertical or deviated and the availability of a litho-stratigraphic data to thermally characterize the rock formations around the well.  Then, the measured temperature data was analysed to figure out the distribution of geothermal gradient and to identify different situations in terms of temperature at national scale, that could be selected later as representative case studies of high, medium and low enthalpy geothermal plant.  Moreover, the Horner plot approach have been adopted for computing equilibrium temperature at depth after drilling, obtaining the real temperatures for each well. The proximity to possible heat stakeholders was then assessed using a GIS system.

How to cite: Facci, M., Di Sipio, E., and Galgaro, A.: Energy transition and Deep Geothermal solution role: a screening procedure for the retrofitting and reuse of ex Oil&Gas wells as deep closed-loop borehole heat exchangers in Italy, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-14599, https://doi.org/10.5194/egusphere-egu23-14599, 2023.

In the past decades, boreholes were drilled all over the world for the purpose of hydrocarbon prospection. Data from these boreholes are a very valuable resource, that can be used in current geological, geothermal and hydrogeological studies. Since the process of drilling is both expensive and disturbing to the environment the possibility of incorporating data that already exists in the current studies is always worth consideration. However, in the case of older boreholes quality of data is not on par with modern standards which limits its usefulness, especially in the case of data from boreholes drilled in thin-bedded rock formations.

Resistivity logs are one of the main logs used both in hydrocarbon prospection and other applications such as geological, geothermal and hydrogeological studies. Resistivity logs measured by older generations of logging tools are characterized by significantly lower vertical resolution in comparison to logs measured by newer logging tools which affect the quality of the interpretation. However, the information averaged in the process of logging can be partially restored in the process of iterative inversion.

The focus of the presentation is on the utilization of open-source global optimization software in the process of inversion of resistivity well logs. Since inverse problems encountered in geophysics tend to be on the difficult side, relatively simple optimization schemas that often can be found in open-source software are not always giving good results. Therefore, in the presentation, a few methods that allow adapting those algorithms to the problem of inversion of well logs are discussed. The performance of the inversion procedure is validated on synthetic data and real data from the borehole where resistivity logs were measured by different generations of logging tools in the same depth intervals, which allows for comparison of the inversion results to logs measured by modern equipment.

The research was funded by the National Science Centre, Poland, grant number 2020/37/N/ ST10/03230.

How to cite: Wilkosz, M.: Adaptation of open-source global optimization software to the process of iterative inversion of resistivity well logs, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-10004, https://doi.org/10.5194/egusphere-egu23-10004, 2023.

Three-dimensional seismic data and well-log data analysis deliver complete information on the petrophysical characteristics of reservoir rock and its fluid content. The current study shows the combined interpretation of 3D seismic data and well log responses such as gamma ray, delay time (DT)- P wave and S wave, resistivity, neutron, density, and lithology logs from eight wells under the research area of Krishna-Godavari (KG) basin. The main target of the paper is focused on the prominent positive topographic features in the bathymetry data and on the porous and fractured/faulted hydrocarbon rocks. Fluid/gas migration characteristics like acoustic voids, chimneys, and turbid layers may be seen in the present mounds. Coherence, dip, curvature, and saliency attributes are used to enhance the discontinuities within the seismic volume. After then, well logs were used to identify the hydrocarbon-bearing zones. Finally, the seismic to well tie step was initiated, and the complete earth model of the given data was generated.

The goal of this paper is to describe the offshore KG basin reservoir areas, in a qualitative way using 3D seismic and well log data and its possible correlation with facies. The possible data and wells information are conjugated with other attributes, which are relatively recent methods in this field study, yet it is crucial to reducing geological uncertainty and predicting facies. The characterization of reservoirs using only the seismic volume (impedance dependent data) characteristics is difficult due to the shally environment of the area, which might obscure reservoir identification. As a result, combining a variety of techniques and data is important for better understanding geological settings and identifying meaningful geological features in the shally environment of the KG basin.

How to cite: Singh, G., Rani, A., Mohanty, W. K., and Routray, A.: Subsurface mechanical modeling of Krishna Godavari basin using petrophysical properties of the rocks by utilizing 3D seismic and well log data sets, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-543, https://doi.org/10.5194/egusphere-egu23-543, 2023.

Measurements of the zeta potential using streaming potential method are frequently used to characterise flows in subsurface settings owing to a broad range of applications of this petrophysical property; examples include CO₂ geological storage, hydrocarbon reservoirs, geothermal sources and freshwater aquifers. Many experimental studies of the zeta potential have been carried out covering a wide range of parameters including different rock mineralogy, brine concentration and composition, and temperature to understand the impact of each parameter. The capability of the streaming potential method to be used on intact rock samples, single-/ and multi-phase flows, wide range of salinity, pressure and temperature makes the method suitable for representation of typical subsurface conditions. However, none of previous studies reported high multi-phase measurements at high pressure conditions typical for deep reservoirs. To adequately represent subsurface conditions of carbon geological storage sites, the minimum experimental pressure of 7.38 MPa and minimum temperature of 31 °C, consistent with the supercritical-CO₂ (scCO₂), need to be used. Obtaining stable measurements of the streaming potential under these conditions is extremely challenging. We report a detailed design of a high-pressure experimental system and experimental protocol for multi-phase streaming potential measurements that were carried out on scCO₂-sandstone-brine systems at temperature of 40 °C, pressures ≤10 MPa and with a variety of aqueous solutions.

The obtained results demonstrate for the first time that the multi-phase zeta potential correlates with the measured scCO₂ residual saturation and rock’s wetting state interpreted from other parameters. Moreover, our results unambiguously identify for the first time the polarity and likely magnitude of the scCO₂-brine interfacial zeta potential. Our findings improve the current understanding of the complex wetting behaviour of scCO₂ and provide important experimental data for numerical (surface complexation, molecular dynamics), analytical (DLVO) or combined models.

How to cite: Hidayat, M., Vinogradov, J., Sarmadivaleh, M., Iglauer, S., Vega-Maza, D., and Derksen, J.: New Insights into Underlying Mechanisms of CO2 Wettability and Residual Saturation from Laboratory Measurements of Multi-Phase Zeta Potential in Supercritical CO2-Rock-Brine Systems, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-11350, https://doi.org/10.5194/egusphere-egu23-11350, 2023.

Many bacteria have been proved to change physical (viscosity, wettability, and tension), and compositions of crude oil, which can make it easier for oil to be released from rock pores and achieve the purpose of improving recovery, which is called Microbial Enhanced Oil Recovery (MEOR). Our team has previously isolated six emulsified and viscosity-reducing bacteria (Bacillus. sp.) in low permeability layers (Chang 4+5 and Chang 6) of Ordos Basin. However, environmental tolerance of the strains is limited, and the components of crude oil used by the strains were also different. The combination of strains of different species and genera may enhance the effects of single bacteria, surpass the tolerance upper limit, and optimize the viscosity reduction and degradation. Therefore, in this study, it is extremely necessary to study the bacterial consortium. Two consortia were obtained and each consortium consisted of three bacterial strains and was designated as Consortium A (51+61, 61+H-1, 51+H-1; A-ALL) and Consortium B (34(2)+42, 34(2)+A-3; 42+A-3. B-BLL). The performance of the mixed strains was evaluated by the analysis of change in emulsification rate, crude oil composition, viscosity, and the tolerance (temperature, salinity, and pH) though GC-MS, rotational rheometer, and other methods. The results showed that bacterial consortiums had higher alkali resistance and could survive temperatures of 55 °C and salinity of 50 g/L in comparison to single bacterium. The emulsification rate was 22%-48%. Consortium B has better effects than Consortium A. The viscosity reduction rate of the Consortium A after 7 days was exceeded 30% as a whole, and the rate of Consortium B was more than 35%. The crude oil of Consortium B is basically non-stick to flask. Compared with single bacteria, the utilization components of crude oil to bacteria are still different, including both long chain hydrocarbons and short chain hydrocarbons. However, the proportion of long chain n-alkanes is further reduced compared with that of single bacteria, and the highest ratio is reduced by 23.81% (B-ALL). Overall, the bacterial consortium outperforms the single strain in terms of tolerance, viscosity reduction, and degradation, which further optimizes the application of MEOR.

How to cite: Bian, Z., Zhi, Z., Zhang, X., Qu, Y., Wei, L., Wu, Y., and Wu, H.: Viscosity-reducing and Biosurfactant-producing Bacterial Consortia Isolated from Low-permeability Reservoir in Ordos Basin, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-1627, https://doi.org/10.5194/egusphere-egu23-1627, 2023.

With increasing global demand for oil and gas, the exploration of unconventional resource plays (shale oil and gas) continues to gain relevance. Such plays could be significant for maximising the production value in proven geological basins, allowing the exploration of a cleaner fossil fuel. Unconventional resources could play a part in the energy transition to lower-impact CO₂ fuels while meeting current energy security needs.

For several decades, the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Kimmeridge Clay Formation (KCF). In this study, we have used 3-D geostatistical modelling of the distribution of key geochemical and geomechanical properties for the KCF to investigate the potential of shale oil and gas plays within Quadrant 15 in the Outer Moray Firth region of the UK North Sea.

The utilized geochemical and geomechanical property logs were generated from sixteen selected drilled wells using machine learning and established property equations, while the top and base KCF structural depth maps used for modelling were created using grid- and isopach creation tools in Zetaware's Trinity software, an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 58 wells within the study area.

The geostatistical property maps created for the KCF in Schlumberger’s Petrel software were then normalised and integrated to identity sweet spots for potential shale oil/gas exploitation, after the application of various cut-offs using standard industry thresholds for unconventional resources.

The modelling results suggest that the KCF show good potential for shale oil and gas exploitation within the central part of the Witch Ground Graben and limited areas of the Piper Shelf and Claymore-Tartan Ridge in the study area.  Further investigations on maturity, saturation and producibility will be conducted by 3-D basin modelling.

How to cite: Akinwumiju, A.: Sweet-spot mapping of the Kimmeridge Clay Formation in the UK North Sea for unconventional resource exploitation using a geostatistical modelling approach, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-63, https://doi.org/10.5194/egusphere-egu23-63, 2023.

Inland salinisation due to the upwelling of highly mineralised deep waters formed by leaching of Upper Permian salt diapirs is a typical phenomenon in the North German Basin. In the German State of Brandenburg, the local absence of the regionally most important aquiclude, the Lower Oligocene Rupelian Clay, separating deep saline waters from the overlying freshwater aquifers, is considered to be the main cause of local salinisation in the freshwater column.

The present study uses density-driven 3D flow and transport simulations to assess saltwater upwelling across Quaternary window sediments in the Rupelian for an area in southeastern Brandenburg with detectable salt concentrations in the freshwater column. Previous simulations along a 55 km long transect in Brandenburg using a 2D model have already demonstrated the potential negative impact of groundwater extraction, the use of the deep subsurface as a storage reservoir or lower precipitation rates and decreasing groundwater levels as a consequence of global climate change on the degree of upper aquifer salinisation (Chabab et al., 2022; Tillner et al., 2016; Wetzel et al., 2016).

The presented simulation results show that 3D flow strongly affects the temporal and spatial distribution of upper aquifer salinisation due to the varying extent of layers and erosion windows in the Rupelian Clay. The location of groundwater extraction sites, hydraulically conductive faults and spatial variations in groundwater recharge additionally influence the location and degree of shallow aquifer salinisation, and must therefore be carefully considered. Depending on topographic gradients and density variations occurring due to differences in pressure and temperature, convective cells with descending flow and freshwater lenses in the saltwater column also develop locally. We show that 3D flow simulations are essential for site-specific analysis to represent the dynamics of the system with many different hydrogeologic interacting and controlling factors.

Literature

Chabab, E., Kühn, M., Kempka, T. (2022): Upwelling mechanisms of deep saline waters via Quaternary erosion windows considering varying hydrogeological boundary conditions. Advances in Geosciences, 58, 47-54.

Tillner, E., Wetzel, M., Kempka, T., Kühn, M. (2016): Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage. Hydrology and Earth System Sciences, 20, 1049-1067.

Wetzel, M., Kühn, M. (2016): Salinization of Freshwater Aquifers Due to Subsurface Fluid Injection Quantified by Species Transport Simulations. Energy Procedia, 97, 411-418.

How to cite: Chabab, E., Kühn, M., and Kempka, T.: Saltwater upwelling quantified by density-driven 3D flow and transport simulations for a study area in Brandenburg, Germany, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-12741, https://doi.org/10.5194/egusphere-egu23-12741, 2023.

After a long period of water flooding development, oilfields will enter the production stage of "high water cut, high recovery degree, and low oil recovery rate". On the one hand, due to the displacement effect of the water injection, some oil layers already reached the water flooding limit. On the other hand, due to the effect of reservoir heterogeneity, dominant seepage channels, and imperfect injection-production well pattern, some oil layers are enriched with a large amount of remaining oil. Unbalanced production of reservoirs and difficulty in development and adjustment are common problems in mature oilfields. Mature multi-layer oilfields generally develop many sets of oil-bearing layers vertically. After a long water injection period, the water-flood law and the remaining oil distribution are complex, and the production of different well patterns or strata varies greatly. Through strata and well pattern reorganization, combined with the evaluation results of water flooding adjustment potential, some reservoir engineers and researchers established a stereoscopic development adjustment mode for enhanced oil recovery in mature multi-layer oilfields. This paper summarizes the main technologies of stereoscopic development adjustment mode for enhanced oil recovery in mature multi-layer oilfields. The main technologies of stereoscopic development adjustment mode include research on the remaining oil distribution, evaluation of water flooding adjustment potential, selection of tertiary oil recovery methods, reorganization of strata and well pattern, and optimization of timing from water flooding to tertiary oil recovery, etc. For strata with low water flooding adjustment potential, the tertiary oil recovery well pattern is reorganized and tertiary oil recovery is adopted to improve oil recovery. For strata with large water flooding adjustment potential, the water drive well pattern is reorganized and water flooding development is used to excavate the remaining oil. As for strata with general water flooding adjustment potential, the tertiary oil recovery well pattern is reorganized and water flooding development is used to excavate the remaining oil first, and then transfer to tertiary oil recovery at the proper time. The stereoscopic development adjustment mode is applied to test block K of Q reservoir which is a mature multi-layer oilfield. After stereoscopic development adjustment, the development effect of test block K meliorates. It is estimated that the EOR will be increased by more than 8% after stereoscopic development adjustment in test block K.

How to cite: Lai, L., Zou, C., Jiang, Z., Su, H., Zhang, X., Li, S., and Zhang, H.: Stereoscopic Development Adjustment Mode for Enhanced Oil Recovery in Mature Multi-Layer Oilfield, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-3107, https://doi.org/10.5194/egusphere-egu23-3107, 2023.

Reservoir heterogeneity is one of the key geological problems in the process of oil and gas exploration and development of clastic rocks. Understanding reservoir heterogeneity is imperative to improve the effectiveness of exploration and development. The primary porosity calculation model proposed by the authors in the previous study is used to calculate the primary porosity of samples from modern braided river sands and sandstone outcrops of braided sand bodies, and the primary porosity heterogeneity (PPH) model of the braided sand body is established. The architectural-elemental structures of braided sand bodies have obvious control effects on the distribution of its primary porosity heterogeneity. The central braided channel and braid bars have strong primary physical properties; the primary porosity is high and always greater than 38%. The contact areas between the braided channel and braided bars have a low value of primary porosity and are always lesser than 33%. The distribution characteristics of the present porosity of braided river reservoirs are also influenced by sedimentary architecture. To compare the relationship between PPH, present porosity heterogeneity (pPH), and sedimentary architecture (SA), the images of PPH, pPH, and SA were digital, graying, and normalized. The digital image Q-Q plots of the distribution probability of PPH, pPH, and SA are calculated. The results show that: the Q-Q plots of the probability distribution of present porosity and architectural-elemental structures (or lithofacies) can reflect the influence and degree of primary porosity and diagenesis on the present heterogeneity of the reservoir. The Q-Q plots of distribution probability primary porosity and present porosity identify the distribution areas; the points are always distributed on different lines. The line ‘y = x’, is derived from compaction and primary porosity; the line ‘y = ax, a > 1’, is derived from diagenesis, which is unfavorable to the reservoir porosity preservation (such as cementation); the line ‘y = ax, a < 1’ is derived from diagenesis, which is beneficial to reservoir porosity preservation (such as dissolution). Based on the Q-Q plots of distribution probability, the influence from primary porosity and diagenesis can be quantitatively analyzed. The influence of primary porosity on pPH in braided sand bodies of Ahe formation (Kuqa depression), middle Jurassic fluvial sandstone (Datong basin), and Karamay Formation (Junggar basin) were 19%, 90%, and 10%, respectively. A quantitative probability distribution Q-Q model of reservoir PPH and pPH is effective for reservoir physical modeling.

How to cite: Yiming, Y., Liqiang, Z., Shuai, J., and Zuotao, W.: The primary porosity heterogenetic model of braided river sandstone reservoirs and its influence on the present porosity heterogeneity in the Kuqe depression, Tarim basin, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-6856, https://doi.org/10.5194/egusphere-egu23-6856, 2023.

Continental shale oil can be divided into two categories according to vitrinite reflectance of kerogen: medium-high maturity (R_o > 0.9%) and medium-low maturity (R_o ≤ 0.9%). Due to high ratio of gaseous (C_1-5) and light hydrocarbons (C_6-14), high GOR and overpressure of the shale section, medium-high maturity shale oil has commercially productivity, which is considered as the target of unconventional resources in China. Shale oil composition is the basic and key parameter for resource evaluation, prediction of favorable areas, well location and field development plan. However, in shale oil composition research projects, the samples used and the analytical methods are quite different, and evaluation standard has not been established, which has restricted the exploration and exploitation of continental shale oil in China.

To understand this effect, we took the first member of Qingshankou Formation (Late Cretaceous) in Songliao Basin in eastern China as the target section. The section develops pure shale oil at a burial depth of 2000-2500m, with vitrinite reflectance of kerogen (R_o) of 1.20%-1.70% and high clay minerals content (40 wt%-60 wt%). We performed four sets of experiments on molecular composition of shale oil, including oil produced from shale section, the full-closure coring shale, the conventional coring shale and extracted hydrocarbons of shale with chloroform. The crude oil and saturated hydrocarbons (extracted hydrocarbons) separated by chromatographic column were directly analyzed by gas chromatography. The full-closure coring and conventional coring shale samples were conducted TG-GC (thermogravimetry-gas chromatography) experiment, where the powder samples were thermally desorbed at 300 ℃ for 3 minutes.

The experimental results show that carbon number of n-alkanes in crude oil is 4–38. The carbon number of n-alkanes in full-closure coring shale is 1–26, and it contains a large amount of gaseous and light hydrocarbons, accounting for up to 60 wt%–80 wt%. It is worth noting, however, that due to the loss of gas and light hydrocarbons in conventional coring, the carbon number of n-alkanes in conventional coring shale is 11–26, and the main peak carbon is 13–16. In the process of shale placement in core library, extraction and concentration, a large amount of hydrocarbons are lost. Through chromatographic analysis, carbon number of n-alkanes in saturated hydrocarbons is 15-38, and the main peak carbon is 18–22. C_15- components are totally lost in extraction (Figure 1).

The comparison data we assembled show that shale oil components obtained from different samples vary significantly, especially for medium-high maturity shale containing large amounts of gaseous and light hydrocarbons. The heavy hydrocarbon components (C₁₅₊) can be determined by combining the produced oil with extracted hydrocarbons, and the gaseous and light hydrocarbons retained in shale can be determined by combining the produced oil with TG-GC analysis for full-closure coring shale. Pressure-retained coring or full-closure coring is indispensable for obtaining shale oil components in place.

Figure 1 (a) Gas chromatogram of oil produced from shale section; (b) TG-GC chromatogram of conventional coring shale sample; (c) TG-GC chromatogram of full-closure coring shale sample; (d) Gas chromatogram of saturated hydrocarbon extracted from shale sample.

How to cite: Li, M., Wang, M., and Li, J.: Composition of pure shale oil with medium-high maturity, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-2535, https://doi.org/10.5194/egusphere-egu23-2535, 2023.