Reduce Exploration Risk Research Articles

A Machine Learning Zircon Trace Element Tool to Predict Porphyry Deposit Type and Resource Size

AbstractPorphyry deposits are primarily known for their association with base metals like copper and to some extent molybdenum and gold. Here we present machine learning models, based on zircon composition, that provide quantitative distinction between different deposit types and resource sizes. Using a global zircon compositional database for different porphyry deposits (9,649 samples), we trained several machine learning models. A porphyry deposit type model (PDT model) was developed using XGBoost, which distinguishes between barren, Cu, and Mo bearing deposits. Furthermore, porphyry Cu and Mo reserve models (Porphyry Cu Reserve [PCR] and Porphyry Mo Reserve [PMR] model) were also developed using XGBoost and LightGBM, respectively, to give prediction of resource size in unexplored area. F1‐scores for the models are 0.97, 0.91, and 0.82. The model‐built feature importance and Shapley Additive exPlanations values imply that (EuN/EuN*)/Y, Th/U, Th/U and Ce are important in the PDT model, Ti, T (°C), U, and Hf are important for the PCR model, and Hf, U, Th/U, and EuN/EuN* are important for the PMR model. From a mineral system perspective, the three models imply that water, temperature, and magma evolution are pivotal to the type of deposits that forms. Temperature and magma evolution in particular are important in prediction of Cu and Mo resource size. Application of models to the Wunugetushan deposit gives ore type and resource predictions that are consistent with known deposit occurrence and geochemistry. These findings suggest that machine learning models may not only assist in understanding the main geological processes linked to porphyry mineralization, but also have application in reducing exploration risk.

Integrated Sequence Stratigraphic and Seismic Facies Analysis for Hydrocarbon Prospectivity of the Taranaki Basin, New Zealand

This study analyses the hydrocarbon potential and basin characteristics of the Taranaki Basin in New Zealand, the country's primary petroleum-producing region. The research, which uses a robust methodology involving 2D seismic data, well logs, and other geological information, examines the basin's stratigraphy, structural features, and petroleum systems. Key findings include the identification of two genetic sequences with associated system tracts, multiple reservoir and source rock units, and both structural and stratigraphic trapping mechanisms. Seismic facies analysis revealed eight distinct facies types which characterize the depositional environments. Play fairway mapping identified sweet spots where all petroleum system elements overlap. Risk assessment highlighted factors like gas chimneys and fault-compromised seals. The study concludes by presenting the geologic chance of success for three identified plays and one prospect in different stratigraphic intervals. This comprehensive analysis provides new insights into the under-explored portions of the Taranaki Basin and its hydrocarbon potential. By enhancing the understanding of the basin's stratigraphic architecture and depositional history, this study aims to improve reservoir distribution and quality predictability. Moreover, integrating seismic facies analysis with sequence stratigraphy offers a robust tool for delineating potential hydrocarbon-bearing zones, thereby reducing exploration risk and aiding the efficient reassessment of existing prospective zones and future exploration efforts.

Probabilistic assessment of deep geothermal resources in the Cornubian Batholith and their development in Cornwall and Devon, United Kingdom

Geothermal energy could play a pivotal role in decarbonisation as it can provide clean, constant base-load energy which is weather independent. With a growing demand for clean energy and improved energy security, geothermal resources must be quantified to reduce exploration risk. This study aims to quantify the untapped resource-potential of the Cornubian Batholith as a geothermal resource for power generation and direct heat use. Recent field work, laboratory measurements and petrophysical characterization provides a newly compiled dataset which is inclusive of subsurface samples taken from the production well of the United Downs Deep Geothermal Power Project. Deterministic and probabilistic calculations are undertaken to evaluate the: total heat in place, recoverable resource, technical potential and potential carbon savings. The Cornubian Batholith is considered a petrothermal system which may require stimulation as an enhanced geothermal system. This study shows the batholith has significant heat stored of 8988 EJ (P50), corresponding to 366 EJ recoverable and a technical potential of 556 GWth. When evaluating the potential for power generation (i.e., electricity) the P50 is 31 GWe. The total carbon savings when generating electricity (P50) equates to 106 Mt.

Impact of sediment provenance and depositional setting on chlorite content in Cretaceous turbiditic sandstones, Norway

AbstractChlorite minerals, mainly in the form of clay coats, play a critical role in determining the reservoir quality of siliciclastic rocks. They can positively influence reservoir quality by preserving porosity during deep burial, but they can also play a negative role by reducing permeability through pore filling. The main aim of this research is to determine the optimal conditions for chlorite growth in sedimentary basins. This study investigates the Lower Cretaceous turbidite sandstone of the Agat Formation in the North Sea. We used a source‐to‐sink approach to investigate the impact of sediment source composition, chemical weathering and depositional environment on chlorite formation. Understanding the interplay between these processes can help refine exploration and exploitation strategies, optimise hydrocarbon recovery, and reduce exploration risks. Representative samples from two hydrocarbon fields (the Duva and Agat fields) were investigated using petrography, geochemistry, heavy mineral identification and quantification, and U–Pb geochronology of detrital zircons. Our results show a strong heterogeneity in the sediment provenance between the two turbidite systems. In the Duva field, the sandstone is derived from a mixture of mafic and felsic sources, producing Fe‐rich sediments. Intense chemical weathering generates fine fraction materials rich in kaolinite, vermiculite, and hydroxy‐interlayered clays, which are transported into shallow marine settings. Subsequent interaction with seawater results in the formation of glauconitic materials, Fe‐illite, and phosphatic concretions. These Fe‐rich materials are remobilised into deep marine settings, providing precursors for the development of authigenic Fe‐clays such as berthierine and chlorite. Conversely, in the Agat field, the sandstone is predominantly sourced from felsic rocks that underwent low chemical weathering, producing sediment rich in quartz and feldspar with a low amount of clays. With few Fe‐rich materials transported into the basin, the development of chlorite in the Agat field was less pervasive. Basin configuration and depositional environment exerted additional control on chlorite distribution. In the confined turbidite system (e.g. Duva field), chlorite is typically found as coating, whereas in less confined turbidite systems (e.g. Agat field) chlorite shows complex distribution related to depositional environment and dewatering processes. Our findings demonstrate the importance of considering the entire sediment routing system, from source to sink, when predicting chlorite occurrence and its impact on reservoir quality in deep marine settings. This integrated approach can guide exploration and development efforts in deepwater clastic reservoirs.

Diagenesis and pressure evolution in Ediacaran carbonate rocks in the North Slope (Penglai area) of the central Sichuan Basin (SW China)

The Penglai area is an emerging giant gas field in the Sichuan Basin supporting the carbon neutrality goal. To accelerate the exploration, this study combines petrographic observations using optical and cold cathodoluminescence microscopy, fluid inclusion microthermometry, Raman spectroscopy, 1D basin modeling and fluid inclusion PVTX modeling techniques to reveal the paleo-fluid P-T evolution in the second member of the Dengying Formation (Ediacaran age). The results firstly showed a diagenetic sequence which includes three phases of dolomite (1–3), bitumen, quartz (core and overgrowth) and fluorite. Then, ten paleo-fluid episodes were identified based on microthermometric histograms of different mineral phases. Finally, by integrating the Raman results, the hydrostatic and lithostatic gradients calculated by the constructed 1D basin model, and the existing equation of states, the homogenization pressure of fluid inclusions from each fluid episode was determined. By assuming the system was saturated by CH4 as suggested by Raman results, the homogenization pressure equals to the trapping pressure. The P-T trajectory indicates that the second member of the Dengying Formation experienced two sever pressure accumulation stages. One is between fluid episode #3 and #4 recorded by dolomite 3, due to oil generation, and the other is from fluid episode #5 in dolomite 3 to episode #7 in quartz overgrowth to episode #8 in fluorite due to oil cracking to gas. Also, two pressure releasing periods were recorded by fluid episode #5 in dolomite 3 and #9 and #10 in fluorite, caused by both basin uplifting and fluid pressure reaching the lithostatic pressure. This study provides insights into fluid pressure evolution in deeply buried carbonate reservoirs. The understandings can support further geoenergy utilization and reduce exploration risks.

Dynamic re-sedimentation of lacustrine carbonates in the Búzios Field, pre-salt section of Santos Basin, Brazil

The huge oil accumulations in the South Atlantic Pre-Salt section have driven studies that seek a greater understanding of the origin and evolution of these important reservoirs. Lacustrine carbonate intraclastic deposits correspond to the main reservoirs in the Búzios Field, currently with the highest daily production wells in the world, and in other Santos Basin fields. However, few studies were dedicated to these deposits due to the great complexity of Pre-Salt deposits and the lack of analogs. These factors have generated intense controversies in the interpretation of their depositional models. A systematic petrographic characterization allowed detailed characterization of the textures and primary constituents in the rift and sag sections of a well in the Búzios Field. The bioclastic accumulations of the rift Itapema Formation, show features indicative of reworking, such as abrasion, fragmentation and disarticulation of the bivalve bioclasts. Moreover, the bioclasts occur mainly within intraclasts and as nuclei of ooids, characteristics of multicycle redeposition. The massive structure of these deposits, the lack of characteristic wave structures, their distribution in lows and conspicuous mixing with stevensitic grains indicate their gravitational redeposition, as result of the intense tectonic activity during the rift phase. The sag phase Barra Velha Formation deposits are composed of intraclasts eroded from the in situ spherulites and shrubs. These rocks are predominantly massive, lack subaerial exposure features, and display features that point to dynamic and multicyclic reworking. Furthermore, they occur intercalated with in situ deposits in high frequency, even at a thin section scale. These aspects, along with the consistency of isotope values, the widespread spatial distribution and preservation of stevensite across diverse Pre-Salt areas, suggest that gravitational, waves and currents redeposition models should be reevaluated. We propose that internal waves, generated by perturbations of the chemocline of a meromictic, stratified lacustrine system promoted recurrent reworking of the in situ deposits. This generated intraclastic levels with multicycle redeposition aspects, often interlayered with the characteristic in situ deposits. Understanding the processes that generated these deposits will contribute to reduce exploration risks and optimize hydrocarbon production from the intraclastic reservoirs.

Reviewing the advancements in offshore drilling technologies in the USA and their global impact

This study provides an overview of the significant advancements in offshore drilling technologies within the United States and their consequential global impact. As the world's leading innovator in the energy sector, the USA has played a pivotal role in shaping the future of offshore drilling, pushing the boundaries of technological capabilities and fostering sustainable practices. The review begins by highlighting the evolution of offshore drilling technologies in the USA over the past decade. Innovations such as advanced drilling rigs, smart sensors, and real-time data analytics have revolutionized the industry, enhancing operational efficiency, safety, and environmental sustainability. These technological breakthroughs have not only increased the depth and reach of offshore drilling but have also significantly reduced exploration risks and minimized the environmental footprint. The global impact of these advancements is explored, emphasizing the ripple effect on international energy markets, geopolitical dynamics, and environmental stewardship. The USA's expertise in developing cutting-edge technologies has been instrumental in influencing global industry standards and best practices. International collaborations, knowledge exchange, and technology transfer have facilitated the adoption of these advancements in offshore drilling practices across the globe. Furthermore, the study addresses the role of regulatory frameworks and industry collaborations in shaping the trajectory of offshore drilling technologies. The USA's commitment to stringent safety and environmental regulations has set a benchmark for responsible offshore exploration, influencing other nations to implement similar standards. The study concludes by highlighting the future prospects and challenges in offshore drilling technologies. As the energy landscape continues to evolve, the USA remains at the forefront of research and development, driving innovation towards cleaner, more efficient, and sustainable offshore drilling solutions. The ongoing collaboration between industry stakeholders, government bodies, and research institutions is crucial for addressing emerging challenges and ensuring the continued positive global impact of USA's advancements in offshore drilling technologies.

A new insight to access carbonate reservoir quality using quality factor and velocity deviation log

Estimating wave damping in carbonate rocks is complex due to their heterogeneous structure. For this reason, further research in this area is still necessary. Since the identification and evaluation of reservoir quality play an essential role in the optimal use of hydrocarbon resources, efforts are made to provide new solutions to achieve this goal by managing knowledge and accessing information from new tools such as the Vertical Seismic Profile (VSP). Seismic waves are deformed in frequency content and amplitude as they pass through the earth's layers. Part of the reduction in wavelength is related to the nature of the wave propagation and part to the geological properties, including porosity and fracture. Anisotropy and velocity model analysis, rather than the direct connection between reservoir parameters and seismic absorption coefficient, have received the majority of attention in earlier studies on the impact of reservoir parameters and fractures on changes in the quality factor. In this study, the correlation of the quality factor with parameters such as velocity deviation, fracture density, and permeability has been investigated, and an attempt has been made to define the quality factor as a tool to assess the quality of the reservoir. The statistical study using the multiple linear regression method found that fracture density is the most important parameter that follows the trend of the quality factor value. In the analysis, the quality factor showed a relatively good correlation with the permeability of the core data, so in the periods with maximum permeability, the quality factor had the lowest values. According to K-Means Clustering Analysis, 18% of the studied reservoir interval was evaluated as good quality, 33% as medium, 36% as poor, and 12% as hydrocarbon-free. This work provides insight into accessing reservoir quality using quality factor and velocity deviation logs and would be valuable for the development of reservoir quality prediction methods. Based on the study's results, it is recommended to apply this technique for modeling reservoir heterogeneity and assessing 2D and 3D seismic data to predict the reservoir quality of gas fields prior to drilling operations and reduce exploration risks.

Coquina depositional model, Buzios Field, Brazil

Increasingly relevant as petroleum reservoirs, the coquina deposits of the pre-salt section of the Santos and Campos Basin display a wide variety of sedimentary systems that reflect a complex storm-dominated depositional environment. This complexity resulted in the deposition of numerous sedimentary facies distributed among structural lows and highs, and their understanding is an essential aspect in order to reduce exploration risks. Therefore, the aims of this contribution are twofold: (a) to understand the depositional processes during the generation of the Itapema Formation coquina deposits in the offshore pre-salt Buzios Field, Santos Basin, and (b) to establish a depositional model and identify stacking patterns in the coquina section. The facies analysis was based on rock texture, structure, allochemical composition, taxonomic composition, and taphonomic characteristics of bivalve shells, such as fragmentation, abrasion, sorting, thickness, orientation, and articulation. We described 695 thin-sections and sidewall samples distributed among ten wells in the field area. The analysis resulted in sixteen facies grouped into eight facies associations: (1) bioclastic bars, (2) washover deposits, (3) backshore, (4) bioclastic beaches, (5) tempestites, (6) tempestites with articulated shells, (7) offshore and offshore transition deposits, and (8) offshore siliciclastic mudstones. These carbonate facies associations were deposited mainly under the influence of waves and currents in isolated ramp-shaped margined platforms with low continental input associated with active faults, characteristic of the rift phase of the basin evolution. The stacking of the facies associations indicates that the Itapema Formation coquinas were deposited in an environment that became progressively shallower towards the top contact with the overlying Barra Velha Formation. Siliciclastic mudstones mark the top of the Itapema Formation immediately below the Pre-Alagoas unconformity, indicating a significant lake deepening that drowned the coquina section. The depositional model is the first one about the Buzios Field and the first about the pre-salt fields coquinas based on field-scale information.

A novel approach for evaluating the transport capacity of sandstone carriers and determining effective hydrocarbon migration channels: Application to the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin

Preferential hydrocarbon migration pathways are of great significance to reveal and predict large-scale hydrocarbon accumulation. However, hydrocarbon migration within heterogeneous sandstone carriers is highly complex and involves geological and technical uncertainties. In this study, the hydrocarbon flow coefficient (Chf) considering the sandstone heterogeneity and fluid properties was first defined to quantify the seepage performance of sandstone carriers using experimental, geological and geophysical techniques. Through two-dimensional numerical simulation, the hydrocarbon convergence coefficient (Chc) was proposed to characterize the differential hydrocarbon convergence controlled by structural morphology. These two parameters were then integrated into the hydrocarbon transport coefficient (Cht) to comprehensively evaluate the hydrocarbon transport capacity of sandstone carrier, and finally combined with the charging conditions to determine the effective migration channels. The Pinghu Formation in the Pinghu slope belt of Xihu Depression, East China Sea Basin, characterized by large-scale lateral migration of hydrocarbons, is selected as a case study. The results demonstrate that only sandstone carriers with Cht values greater than 10 cm2/s and extensive contact with mature source rocks can serve as effective migration channels. In the effective channels with insufficient hydrocarbon supply, the migration intensity decreases rapidly and only small-scale hydrocarbon migration occurs, while the effective channels with sufficient hydrocarbon supply are accompanied by large-scale hydrocarbon occurrence and the migration intensity weakens slowly. Consequently, three effective channels conducive to hydrocarbon migration were determined in the sandstone carrier units of Pinghu Formation. The quantitative method in this study can be used to predict preferential hydrocarbon migration pathways and reduce exploration risks.

Controlling Factors of Organic-Rich Lacustrine Shale in the Jurassic Dongyuemiao Member of Sichuan Basin, SW China

Organic-rich continental shale, widespread in the Sichuan Basin during the deposition of the Jurassic Dongyuemiao Member (J1d), is considered the next shale hydrocarbon exploration target in southern China. To identify a shale gas sweetspot and reduce exploration risk, it is of great significance to determine the organic matter (OM) enrichment mechanism of J1d shale. In this study, based on sedimentological characteristics and organic matter content, high-resolution major and trace elements were systematically analyzed to demonstrate terrigenous influx, paleoredox, paleosalinity, paleoproductivity, and paleoclimate. The 1st section interval of the J1d 1st submember is dominated by shallow lake subfacies, while the other intervals have the characteristic of semideep to deep lake subfacies. The 1st submember interval of J1d lacustrine shale is characterized by the warmest-humid paleoclimate, strongest weathering degree, highest terrigenous input, moderate paleoproductivity, and paleoredox condition. Within the Dongyuemiao 1st submember, the 4th section interval has the highest paleoproductivity and the most oxygen-deficient condition in bottom water. During the deposition period of the 2nd submember, the sedimentary environment turned to a cold-dry paleoclimate, weak weathering degree, low terrigenous input, low paleosalinity, and high paleoproductivity. Under the background of semideep and deep lake, the terrigenous OM input plays the most critical role in controlling OM enrichment. Moreover, the high primary productivity of lake surface water and the suboxic condition of lake bottom water contribute to the formation of relatively higher TOC lacustrine shale interval in the 4th section of 1st submember.

The “Golden Zone” temperature distribution of oil and gas occurrence examined using a global empirical database

We present here a straightforward empirical correlation between petroleum occurrence in sedimentary basins and reservoir temperature that can be integrated with other methods of analysis to reduce exploration risk. Global amounts of recoverable oil, gas, and gas-condensate in 1175 well characterized reservoirs from 954 of the world's largest fields, constituting 54% of the world's documented recoverable conventional oil and 50% of gas, are examined in terms of present-day reservoir temperature. Most volumes (74%) occur within the range of 60–120 ± 2 °C (140–248 ±4 °F), corresponding with the isotherm-bounded depth interval in petroliferous basins previously defined as the “Golden Zone” for exploration. Only 6% of the global total occurs at higher temperatures and 20% at lower temperatures. The decrease <58 °C is gradual in most regions, whereas the drop-off of discovered volumes >122 °C is precipitous. The low-temperature limit is suggested to reflect both poor sealing capacity of diagenetically immature shales and biodegragation, but many low-temperature accumulations survive because of uplift from previous maximum burial. The high-temperature limit is interpreted as resulting mainly from diagenetically induced overpressure that causes seal failure and remigration. Similarity between the distributions of both oil and gas with temperature indicates that the controlling processes are unrelated to petroleum generation. The distributions are also similar for sandstone and carbonate reservoirs and for reservoirs with shale, evaporite, and carbonate seals, indicating little lithologic influence. Although the ultimate controls can be debated and are certainly in need of continuing study, the observed temperature dependence of petroleum volumes is entirely empirical and can be used as an independent exploration risk factor. Nevertheless, the proportions of total estimated ultimate recovery above and below the Golden Zone temperature limits vary significantly between major petroleum-producing regions, so local calibration is essential.

Improving data accessibility and application for underground climate re-search at the British Geological Survey

Improving data accessibility and application for underground climate re-search at the British Geological Survey

Fluid history of the lower Cambrian Longwangmiao Formation in the Anyue gas field (Sichuan Basin, SW China)

The Anyue gas field in China is an important source of natural gas supporting the country energy transition to the goal of carbon-neutrality. However, the fluid P–T history, which will provide a better insight into gas accumulation and probable leakage in the main reservoir (the Lower Cambrian Longwangmiao Formation) has still yet to be fully understood. This study combines detailed petrographic observations with transmitted light, ultraviolet light, reflected light and cold cathodoluminescence, fluid inclusion microthermometry, Raman spectrometry, 1D basin modeling and fluid P–T modeling techniques to reconstruct the fluid-involved basin evolution of the Longwangmiao Formation in the Anyue region. The results showed that the paragenesis of the Longwangmiao Formation includes dolomite matrix, dolomite 1, dolomite 2, dolomite 3 (saddle dolomite), dolomite 4, quartz and calcite. The first generation of bitumen occurs between dolomite 1 and dolomite 2, corresponding to the primary oil generation of the Lower Cambrian Qiongzhusi Formation at the burial maximal in the Silurian. The second generation of bitumen, corresponding to intense oil cracking into gas, has occurred between dolomite 4 and quartz at a geological period between the Middle Jurassic and Early Cretaceous (early Yanshanian movement). Fluid inclusions trapping pressure modeling explains that the trapping pressure increases from dolomite 4 to quartz due to burial and the oil cracking into gas, then stays constant from quartz to calcite due to the sealing of fractures. The open fractures formed after calcite partially reduced the overpressure condition of the Longwangmiao Formation. Collectively, this study will provide necessary information for a better understanding of deeply buried reservoirs to support more efficient development of such reservoirs in higher quality zones and reduce exploration risks and operational costs.

Novel Method for the Classification of Shale Oil Reservoirs Associated with Mobility: Inspiration from Gas Adsorption and Multiple Isothermal Stage Pyrolysis

The characterization and description of pores in shale oil reservoirs have long been based on the classification of micropores (<2 nm), mesopores (2–50 nm), and macropores (>50 nm) in shale gas reservoirs. However, the great difference between oil and gas molecules leads to its poor applicability, which further results in the relationship between oil properties and pores being rarely understood. To establish an individual pore division method for shale oil reservoirs, N2 adsorption, Soxhlet extraction, and programmed pyrolysis were performed on the Paleogene Xin’gouzui lacustrine shale in the Jianghan Basin. With the results, a new classification method, i.e., adsorption pores (pore diameter <20 nm), restricted pores (20–100 nm), and movable pores (>100 nm), was proposed. A fractal theory and scanning electron microscopy (SEM) images confirm the rationality of this method. Hydrocarbons in movable pores determine the initial productivity of a shale oil well, while those in restricted pores are closely related to the production time of a well to some extent. Compared to the previous division methods, this novel method reveals the correlation between shale oil attributes as well as movability and pore spaces for the first time. Our work can provide more accurate evaluation results for shale oil recoverable resource potential and is of great significance for optimizing favorable areas and reducing exploration risks.

HYDROCARBON EXPLORATION AND RESOURCE OPTIMIZATION THROUGH SEQUENCE STRATIGRAPHIC ANALYSIS AND DATA AUGMENTATION OF HIGH FIELD OFFSHORE WESTERN NIGER DELTA

Efficient hydrocarbon exploration and resource optimization are vital for sustainable oil reservoir development. This necessitates a profound grasp of source rocks and trapping systems, typically gleaned from subsurface seismic studies followed by drilling for resource extraction. Additionally, interpreting stratigraphic data is critical for identifying productive reservoirs, distinguishing low-yield from high-yield sands, and reducing exploration risks and costs. Our study aims to enhance subsurface structure and stratigraphic understanding, specifically identifying potential hydrocarbon reservoirs, source rock formations, sealing structures, stratigraphic traps, and depositional environments. In the Niger Delta region, we seek to reduce operational costs and exploration risks related to oil and gas exploration. In the “high field” offshore Niger Delta, our research combines well logs and seismic data to define hydrocarbon trapping potential, stratigraphic profiles, and depositional settings. The stratigraphic sequence is systematically divided into system tracts by five sequence boundaries, maximum flooding surfaces, and transgressive surfaces that reveal different depositional environments. This integrated approach pinpoints two prospective areas, P1 and P2, as potential hydrocarbon reservoirs. The analysis of seismic data and well logs is highly effective in identifying subsurface structures conducive to hydrocarbon accumulation within the stratigraphic framework. Furthermore, the alternation of lowstand, transgressive, and highstand system tracts suggests favorable conditions for source rocks, sealing formations, and reservoirs, improving the prospects for successful hydrocarbon exploration and resource optimization.

Identification of Volcanic Geothermal Systems Based on Integrated Study of Volcanostratigraphy, Structural Geology, and Fluid Geochemistry in Southern Ngada Field, Indonesia

Southern Ngada is one of the areas that shows occurrence of volcanic geothermal potential in East Nusa Tenggara. The spreading volcanoes in the study area raised a hypothesis that the Southern Ngada Geothermal Field consists of several geothermal systems. The spreading volcanoes showed the presence of at least three volcanoes and manifestation clusters, which are Nage, Keli-Bena, and Wolo Puti Clusters. This research aimed to identify the number, type, and characteristics of geothermal systems in Southern Ngada Geothermal Field. The identification is conducted through the integration of geomorphology, volcanostratigraphy, structural geology, and geochemistry of fluid manifestation. The determination of geothermal system in Southern Ngada Geothermal Field is important to identify the field characteristics and reduce exploration risks. The Southern Ngada Field constitutes of the pre-caldera, post-caldera, and recent volcanism products. The study area is intensively deformed through strike slip faults and resembled Riedel Shear patterns. Fluid manifestation geochemistry in the study area showed various type of waters, which consists of Cl-SO4, SO4, and SO4-HCO3 waters with meteoric water mixing. The solfatara is associated with active magmatic gases due to boiling of reservoir beneath cinder cones. The fluid mixing processes are explained furthermore in Schoeller diagram plot. The integration of analyses showed the presence of Nage, Keli-Bena, and Wolo Puti Geothermal Systems with each different volcanostratigraphy, structural setting, and fluid mixing processes. The Nage System is associated with inferred heat source beneath the Nage Caldera and eastern part master and antithetic fault. The Keli-Bena System is associated with inferred heat source beneath Bena Crater and western antithetic fault. The Wolo Puti System is associated with inferred heat source beneath cinder cone volcanoes and northern extensional structures.

A Joint Method Based on Geochemistry and Magnetotelluric Sounding for Exploring Geothermal Resources in Sedimentary Basins and Its Application

The precise exploration of the characteristics of geothermal fields in sedimentary basins, such as the temperature and burial depth of their deep geothermal reservoirs, is of great significance for improving the probability of penetration and reducing exploration risks and development costs. This study proposed a joint exploration method combining magnetotelluric (MT) sounding and geothermometers. Using this method, this study estimated the geothermal reservoirs’ temperature and the circulation depth of geothermal water in the Xianxian geothermal field, a typical geothermal field in a large sedimentary basin in northern China, and prepared the temperature and depth maps of the geothermal reservoirs. The main results are as follows. First, the bedrock’s geothermal reservoirs with karst fissures in the Xianxian geothermal field have great potential for development. Among them, geothermal reservoirs in the Jixianian Wumishan formation have a top depth of 1100–1500 m and a thickness of 700–1700 m, and the geothermal reservoirs in the Jixianian Gaoyuzhuang formation have a top depth of 3700–4000 m and a maximum drilled thickness of 400 m. The geothermal reservoirs of the Xianxian geothermal field mainly have medium and low temperatures of 138–160 °C and the circulation depth of the geothermal water is 5873 m.

Mass Balance-Based Method for Quantifying the Oil Moveable Threshold and Oil Content Evaluation of Lacustrine Shale in the Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin.

Substantial heterogeneity in lacustrine shale brings significant challenges to oil exploration. Therefore, a clear and effective resource evaluation standard can significantly reduce the exploration risk and cost, thus further guiding the prediction in productive areas. However, due to the lack of consideration of the thermal maturity and kerogen type, the present evaluation standards may result in the misjudgment of the resource quality of shale oil reservoirs. In this study, a method based on mass balance involving a hydrocarbon generation statistical model was proposed to calculate oil movable threshold (OMT) values. The OMT values for different types of kerogens are determined from simple and easily obtained pyrolysis parameters. Based on the OMT values, a three-dimensional resource quality evaluation model is constructed and applied to the source rocks in Member (Mbr) 1 of the Shahejie Formation (Fm) Nanpu Sag, Bohai Bay Basin, eastern China. The results show that the Mbr 1 of Shahejie Fm shale is a set of high-quality source rocks with high total organic matter (TOC) and S1c (calibrated free hydrocarbons) content. Meanwhile, the hydrocarbon generation potential of the studied lacustrine shales are in the order of type I > type II1 > type II2 > type III, whereas the OMT values show a similar order. From type I to type III, the hydrocarbon expulsion threshold (HET) values for the four types of shales correspond to pyrolysis peak temperatures (Tmax) at 438, 426, 428, and 432 °C with the maximum OMT values being 143, 128, 127, and 122 mg HC/g TOC, respectively. The movable and favorable shale oil accumulations are mainly associated with type II1 and II2 shales. Our work provides a novel method for distinguishing the resource quality and locating a favorable exploration target for lacustrine shale, improving efficiency and reducing exploration risks.

Geoscience Poster G1: Origins of hydrogen sulfide (H

Poster G1 The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic variation in the sulfur and oxygen of potential sources, coupled with petrological analyses to determine H2S gas generation. Data is used to predict the gas distribution within the reservoirs to reduce exploration risks. One initial study on the Triassic Montney Formation in western Canada produces H2S gas at concentrations up to 220 000 ppm. Isotopic analyses suggest that the H2S is generated from either Triassic sulfates or a mixture of Triassic and Devonian sources and not solely from Devonian rocks as first expected. To access the poster click the link on the right. To read the full paper click here