Fault Seal Research Articles

Normal Fault Transmissibility Characteristics Under the Transition Condition of Fault Conduction and Sealing Observed in Simulation Experiments

Normal Fault Transmissibility Characteristics Under the Transition Condition of Fault Conduction and Sealing Observed in Simulation Experiments

A Quantitative Method for Evaluating Fault Vertical Opening and Sealing Properties during Hydrocarbon‐Charging Periods

A Quantitative Method for Evaluating Fault Vertical Opening and Sealing Properties during Hydrocarbon‐Charging Periods

Improved method for quantitative evaluation of fault vertical sealing: A case study from the eastern Pinghu Slope Belt of the Xihu Depression, East China Sea Shelf Basin

Fault vertical sealing evaluation is significantly important for revealing hydrocarbon migration and accumulation processes and reducing exploration risks. Based on the analysis of the stress normal to the fault plane, the pore-fluid pressure and the compressive strength of fault rock, a new parameter, namely, the fault vertical sealing index (FVSI), is proposed for improved quantitative evaluation. In this article, static faults distributed in the eastern Pinghu Slope Belt (EPSB) of the Xihu Depression are selected as examples. The vertical sealing properties of four major fault systems that control hydrocarbon distribution are analyzed and evaluated. The FVSI value is positively correlated with the vertical sealing capacity of the fault zone, and the heterogeneous spatial distribution of the FVSI along the fault planes indicates that a fault cannot be uniformly regarded as a conduit or a barrier. According to the relation between the FVSI and the corresponding natural gas and oil shows, a fault zone with an FVSI value less than 0.4 commonly acts as a vertical conduit and cannot accumulate hydrocarbons, while a fault zone with an FVSI value greater than 0.4 has the ability to seal hydrocarbons. However, whether hydrocarbons can continue to migrate vertically depends on the maximum hydrocarbon column height that the corresponding FVSI can seal. In this case study, fault zones with FVSI values greater than 1 completely act as barriers to vertical hydrocarbon migration and no longer transport hydrocarbons. The changing FVSI of the fault zone controls the process of hydrocarbon migration and accumulation, thereby affecting the distribution of hydrocarbons. In the structurally lower position of the EPSB with sufficient hydrocarbon sources, the weak vertically sealed fault zone commonly causes a vertical multilayered distribution of hydrocarbons. Conversely, in the structurally higher position of the EPSB with insufficient hydrocarbon charging, the strong vertically sealed fault zone results in a more concentrated hydrocarbon distribution in the lower strata. However, there are no natural gas and oil shows in the fault zone that completely act as vertical conduits. Therefore, the FVSI can be an effective quantitative method to analyze vertical hydrocarbon migration pathways and accumulation locations controlled by faults and has great application potential in reducing the risks in petroleum exploration projects.

Paleoclimate Signals and Groundwater Age Distributions From 39 Public Water Works in the Netherlands; Insights From Noble Gases and Carbon, Hydrogen and Oxygen Isotope Tracers

AbstractKnowing the age distribution of water abstracted from public water supply wells helps to ensure customer trust in drinking water sources and underpin predictions of water quality evolution. We sampled the mixed water of 39 large public supply well fields for major ion chemistry, 3H, 3He, 18O, 2H, 14CDIC, 13CDIC and noble gases and determined the Noble Gas Temperature (NGT). We used a discrete travel time distribution model to quantify the age distributions using 3H, 4He, 14C apparent age and NGT as the 4 distinctive tracers. Helium‐4 and NGT provided information on the older part of the age distributions and showed that the 14C apparent ages are often the result of mixing of waters ranging between 2,000 and 35,000 years old, instead of being discrete ages with a limited variance as previously assumed. The results reveal a large range of age distributions, comprising vulnerable well fields with >60% young water (<100 years) and well fields with >30% paleo groundwater (>25,000 years) and all forms of intermediate distributions. The age distributions match the hydrogeological setting; well fields with age distributions skewed towards older ages appear in the Roer Valley Graben structure, where fluvial and marine aquitards and sealed faults provide protection from recent recharge. Waters from this graben exhibit paleoclimate signals, with a clear relation between NGT (range 3.2–9.3 °C), 4He (up to 3.3 × 10−6 ccSTP/g) and δ18O (range −8.5‰ to −5.9‰VSMOW). Moreover, 3He/4He ratios of these graben waters suggest a certain influx of He from mantle origin.

Fault interpretation uncertainties using seismic data, and the effects on fault seal analysis: a case study from the Horda Platform, with implications for CO<sub>2</sub> storage

Abstract. Significant uncertainties occur through varying methodologies when interpreting faults using seismic data. These uncertainties are carried through to the interpretation of how faults may act as baffles or barriers, or increase fluid flow. How fault segments are picked when interpreting structures, i.e. which seismic line orientation, bin spacing and line spacing are specified, as well as what surface generation algorithm is used, will dictate how rugose the surface is and hence will impact any further interpretation such as fault seal or fault growth models. We can observe that an optimum spacing for fault interpretation for this case study is set at approximately 100 m, both for accuracy of analysis but also for considering time invested. It appears that any additional detail through interpretation with a line spacing of ≤ 50 m adds complexity associated with sensitivities by the individual interpreter. Further, the locations of all seismic-scale fault segmentation identified on throw–distance plots using the finest line spacing are also observed when 100 m line spacing is used. Hence, interpreting at a finer scale may not necessarily improve the subsurface model and any related analysis but in fact lead to the production of very rough surfaces, which impacts any further fault analysis. Interpreting on spacing greater than 100 m often leads to overly smoothed fault surfaces that miss details that could be crucial, both for fault seal as well as for fault growth models. Uncertainty in seismic interpretation methodology will follow through to fault seal analysis, specifically for analysis of whether in situ stresses combined with increased pressure through CO2 injection will act to reactivate the faults, leading to up-fault fluid flow. We have shown that changing picking strategies alter the interpreted stability of the fault, where picking with an increased line spacing has shown to increase the overall fault stability. Picking strategy has shown to have a minor, although potentially crucial, impact on the predicted shale gouge ratio.

Migration and accumulation of crude oils in the Qionghai Uplift, Pearl River Mouth Basin, Offshore South China Sea

The crude oils migration and accumulation of the Qionghai (QH) Uplift in the Zhu Ⅲ Super-depression was investigated from the perspective of oil source and migration conduit using gas chromatography-mass spectrometry (GC-MS), stable carbon isotope, quantitative grain fluorescence (QGF) analysis and basin simulation methods. The results on the oil-source correlation showed that oil origins of the five typical reservoirs were very complicated. Crude oils of the eastern and western parts of the QH Uplift were from the Wenchang A sag and the Wenchang B sag, respectively, whereas oil sources of the central part of the QH Uplift were from both the Wenchang A and B sags. The research on the migration conduit showed that structure ridge, fault and connectivity sand body jointly controlled crude oil migration and accumulation in the study area. Under the control of structure ridges and well-connected sand bodies, crude oils accumulated at a low-magnitude folding structure forming the WC13-1, WC13-2 and QH18-1 reservoirs, whereas the sealed fault played an important role in forming the WC8-3 and WC13-6 reservoirs. Combing the differences in oil origins and crude oils migration conduits, we finally identified two types of crude oils migration and accumulation modes from the Wenchang Sag to the QH Uplift. One was a gentle-slope long-distance migration and accumulation model, which was developed from the Wenchang A sag to the QH Uplift. The other was a steep-slope short-distance migration and accumulation model, which was developed from the Wenchang B sag to the QH Uplift. This study could provide guidance for exploring the petroleum potential and prospecting promising zones in the South China Sea.

Significance of fault seal in assessing CO 2 storage capacity and containment risks – an example from the Horda Platform, northern North Sea

An understanding of fault seal is crucial for assessing the storage capacity and containment risks of CO 2 storage sites, as it can significantly affect the projects on across-fault and along-fault migration/leakage risk, as well as reservoir pressure predictions. We present a study from the Smeaheia area in the northern Horda Platform offshore Norway, focusing on two fault-bounded structural closures, namely the Alpha and Beta structures. We aim to use this study to improve the geological understanding of the northern Horda Platform for CO 2 storage scale-up potentials and illustrate the importance of fault seal analysis in containment risk assessment and storage capacity evaluation of a CO 2 storage project. Our containment risk assessment shows that the Alpha structure has low fault-related containment risks; thus, it has a potential value to be an additional storage target. The Beta structure shows larger fault-related containment risks due to juxtaposition of the prospective storage aquifer with the basement across the Øygarden Fault System. The storage capacity of Smeaheia will be determined by the long-term dynamic interplay between pressure depletion and recharging. Our study shows that across-fault pressure communication between Smeaheia and the depleting Troll reservoir is likely to be through several relay ramps of the Vette Fault System. However, Smeaheia also shows pressure-recharging potentials, such as through the subcropping areas at the Base Nordland Unconformity. The depletion observed in the newly drilled well 32/4-3S gives a good validation point for our fault seal predictions and provides valuable insights for future dynamic simulations. Thematic collection: This article is part of the Geoscience for CO 2 storage collection available at: https://www.lyellcollection.org/cc/geoscience-for-co2-storage

Fault Sealing Evaluation of a Strike-Slip Fault Based on Normal Stress: A Case Study from Eastern Junggar Basin, NW China

The sealing of a fault zone has been a focus for geological studies in the past decades. The majority of previous studies have focused on the extensional regimes, where the displacement pressure difference between fault rock and reservoir was used to evaluate the fault-sealing property from the basic principle of fault sealing. When considering the displacement pressure difference, the impact of gravity on the fault rock was considered, whereas the impact of horizontal stress was ignored. In this study, we utilize the displacement pressure difference as an index to evaluate the sealing capacity of strike-slip faults, in which both the impacts of gravity and horizontal stress on the fault rocks are all integrated. By calculating the values of σH/σV and σh/σV in the vicinity of fault planes, the coefficient K of compaction impacts on fault rocks between normal stress to fault planes and gravity was then determined. By revealing the quantitative relationship between the displacement pressure of rocks, burial depth and clay content, the displacement pressure difference between fault rocks and reservoirs were calculated. The results suggest that the sealing capacity of a strike-slip fault is not only related to the magnitude of normal stress to the fault plane, but also to the stress regime. The clay content is also an important factor controlling the sealing capacity of strike-slip faults.

Structural containment in the Port Campbell Embayment and on the Mussel Platform, Otway Basin, Victoria

As part of the Victorian Gas Program, new geological modelling of the Cretaceous to recent deposits in the Port Campbell Embayment and the Mussel Platform was carried out to investigate fault seal and trap integrity. Structural characterisation of the Late Cretaceous to present-day sedimentary sequence highlights cross-cutting fault trends defining potential structural traps containing Waarre Formation reservoirs. The fault trends are primarily controlled by Cretaceous-Paleogene extension and are reactivated during the Paleogene. Seismic facies in the top seal suggest an N-S environmental shift from open-marine to proximal nearshore marine. The quantification of fault membrane seals suggests that while reservoir-on-reservoir juxtapositions may enable some degree of lateral flow, efficient trapping relying on juxtaposition seal against the Belfast or Skull Creek mudstones is widespread. Fault geomechanics suggests that NW-SE and E-W faults accommodated most of the extensional strain and could have been associated with increased vertical structural permeability; however, there are no leakage indicators to support widespread vertical migration. These results do not support previous assumptions that fault seal integrity and top seal bypass represent a critical and widespread issue within the nearshore Otway Basin.

The Effects of Fault-Zone Cementation on Groundwater Flow at the Field Scale.

Fault zones are an important control on fluid flow, affecting groundwater supply, contaminant migration, and carbon storage. However, most models of fault seal do not consider fault zone cementation, despite the recognition that it is common and can dramatically reduce permeability. In order to study the field-scale hydrogeologic effects of fault zone cementation, we conducted a series of aquifer pumping tests in wells installed within tens of meters of the variably cemented Loma Blanca Fault, a normal fault in the Rio Grande Rift. In the southern half of the study area, the fault zone is cemented by calcite; the cemented zone is 2-8 m wide. In the center of the study area, the cemented fault zone is truncated at a buttress unconformity that laterally separates hydrostratigraphic units with a ∼40X difference in permeability. The fault zone north of the unconformity is not cemented. Constant rate pumping tests indicate that where the fault is cemented, it is a barrier to groundwater flow. This is an important demonstration that a fault with no clay in its core and similar sediment on both sides can be a barrier to groundwater flow by virtue of its cementation; most conceptual models for the hydrogeology of faults would predict that it would not be a barrier to groundwater flow. Additionally, the lateral permeability heterogeneity across the unconformity imposes another important control on the local flow field. This permeability discontinuity acts as either a no-flow boundary or a constant head boundary, depending on the location of pumping.

Attenuating gradient of residual stratigraphic pressure and its controls on hydrocarbon migration and accumulation

Abnormal stratigraphic pressure is highly significant for hydrocarbon migration and accumulation for the exploration and exploitation of exploratory fields. However, the relationship between abnormal pressure and hydrocarbon migration processes is difficult to characterize quantitatively. In this paper, a new parameter, the attenuating gradient of residual pressure (AGRP), which is defined as the variation in residual stratigraphic pressure over a unit distance in a certain direction, is introduced to characterize hydrocarbon migration forced by residual pressure and hydrocarbon accumulation influenced by fault seals in the Huimin Depression, Bohai Bay Basin. The AGRP against the geological background can be calculated by the formation pressure of the source region by equivalent depth method using well log data (sonic travel time/velocity and resistivity) formation pressure of hydrocarbon reservoirs by drill stem tests of 32 exploration wells. For the Huimin Depression, the calculation results of the third member of the Paleogene Shahejie Formation (Es3) reservoir interval show that the northern tectonic uplift belt (NTUB) and parts of the central deep sag zone (CDSZ) and southern slope belt (SSB) are characterized by stepped distributions of high AGRP values ranging from 1.2 to 2.5 MPa/km with developed faults. The other parts of the Huimin Depression are characterized by continuously distributed low AGRP values from 0.5 to 1.0 MPa/km. The AGRP is effective for characterizing and evaluating hydrocarbon migration and accumulation in structural hydrocarbon traps with AGRP values higher than 1.0 MPa/km, which indicates that these reservoirs are dominated by residual pressure as the main driving force. For these traps, oil and gas tend to migrate to the high-AGRP areas, which indicates a large driving force by residual pressure. Furthermore, the stepped distribution of the AGRP suggests a well-sealed fault and hence good preservation conditions for hydrocarbon accumulation. This study shows that the AGRP can characterize hydrocarbon migration and accumulation more precisely and hence provide guidance for petroleum exploration and exploitation, especially in rift petroliferous basins with abnormal pressure and developed faults.

Influence of host rock composition on permeability reduction in shallow fault zones – implications for fault seal analysis (Vienna Basin, Austria)

In order to calibrate equations for fault seal capacities to a specific basin, faults were analysed using core material from several Neogene hydrocarbon fields in the Vienna Basin, Austria. All studied specimens are siliciclastic rocks that were sampled from a depth interval of <2000 m, and share a similar depth at time of faulting, diagenetic conditions and maximum burial depth. Laboratory results showed a permeability reduction in all fault rocks compared to the host rocks. Both the highest and the lowest fault seal capacities were observed in the same fault rock type with a low phyllosilicate and clay content, and classifying as cataclastic deformation bands. Investigating the strong permeability variations within these fault rocks, microscopic analyses revealed that the fault seal potential is strongly linked to the detrital dolomite content in the host rock. Grain-size reduction processes occur preferably in the dolomite grains, accompanied by cementation. Our study suggests that – in addition to using standard fault seal analysis algorithms – accounting for host rock composition and grain-size reduction therein might help to further constrain fault seal behaviour in shallow depths. Fault seal mechanisms need to be understood on field, formation and micro scales before drawing conclusions for a full basin calibration. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

3-D Seismic Interpretation and Fault Sealing Assessment of X-Field, Deep Offshore Niger Delta

3-D Seismic Interpretation and Fault Sealing Assessment of X-Field, Deep Offshore Niger Delta

Sealing capacity evolution of trap-bounding faults in sand-clay sequences: Insights from present and paleo-oil entrapment in fault-bounded traps in the Qinan area, Bohai Bay Basin, China

Fault seals have been proven to be a significant risk to exploration success, and methods of evaluating the sealing capacity have been developed in recent decades. However, less attention has been paid to the dynamic change characteristics of the sealing capacity during fault growth. In this paper, the relationship between Shale Gouge Ratio (SGR) and across-fault pressure difference (AFPD) is calibrated to define the seal failure envelope in the Qinan area, thus providing a method for estimating the fault sealing capacity. The sealing capacity of the YEZ fault is evaluated by the SGR-AFPD relationship, which shows that the oil column heights sealable by the YEZ fault (Hseal) are greater than the actual accumulated oil column heights (Hactual). The existence of paleo-oil column is consistent with upfault oil leakage during the reactivation phase, which explains why Hseal > Hactual. As faults undergo multiphase reactivation, the throw accumulates gradually, the minimum SGR of the fault increases and eventually converges to the average Vsh of the entire sequence, which increases the fault sealing capacity during the stable phase and Hseal. In the initial fault formation stage, the minimum SGR and Hseal is small because the reservoir is self-juxtaposed. After fault reactivation, the minimum SGR and Hseal increase compared with that of the initial formation stage because the reservoir slides against more layers of shale. However, if the fault reactivates after hydrocarbon charging, although the minimum SGR and Hseal may increase or remain stable, the Hactual value decreases because of post-charge reactivation-induced leakage. In this case, Hactual may be smaller than Hseal. Thus, although calibrating the SGR-AFPD relationship is effective for predicting the fault sealing capacity, the fault activation phases and hydrocarbon charging history should be clarified first to identify hydrocarbon reservoirs damaged by bounding fault reactivation to avoid overestimating the hydrocarbon column heights.

Research on the Dynamic Characteristics of Mechanical Seal under Different Extrusion Fault Degrees

In order to explore the dynamic characteristics of the mechanical seal under different fault degrees, this paper selected the upstream pumping mechanical seal as the object of study. The research established the rotating ring-fluid film-stationary ring 3D model, which was built to analyze the fault mechanism. To study extrusion fault mechanism and characteristics, different dynamic parameters were used in the analysis process. Theoretical analysis, numerical simulation, and comparison were conducted to study the relationship between the fault degree and dynamic characteristics. It is the first time to research the dynamic characteristics of mechanical seals in the specific extrusion fault. This paper proved feasibility and effectiveness of the new analysis method. The fluid film thickness and dynamic characteristics could reflect the degree of the extrusion fault. Results show that the fluid film pressure fluctuation tends to be more intensive under the serious extrusion fault condition. The extrusion fault is more likely to occur when the fluid film thickness is too large or too small. Results illustrate the opening force is affected with the fluid film lubrication status and seal extrusion fault degrees. The fluid film stiffness would not always increase with the rotating speed growth. The seal fault would occur with the increasing of rotating speeds, and the leakage growth fluctuations could reflect the fault degree.

Reply to Discussion on ‘Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems’, Petroleum Geoscience , 2020, https://doi.org/10.1144/petgeo2019-126

Reply to Discussion on ‘Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO ₂ systems’, <i>Petroleum Geoscience</i> , 2020, https://doi.org/10.1144/petgeo2019-126

Discussion on ‘Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems’, Petroleum Geoscience , 2020, https://doi.org/10.1144/petgeo2019-126

Discussion on ‘Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO ₂ systems’, <i>Petroleum Geoscience</i> , 2020, https://doi.org/10.1144/petgeo2019-126

Stratigraphic and structural trapping frameworks in the central Ceduna Sub-basin

Despite a recent renewal in exploration, the Ceduna Sub-basin is underexplored and, as is typical with frontier basins, there is considerable uncertainty regarding lithofacies distribution. As such, there is limited understanding of reservoir and seal coupling as well as structural trapping and thus fluid migration pathways within the prospective Late Cretaceous marine and deltaic intervals from the Tiger and Hammerhead supersequences.To address these uncertainties, a stratigraphic forward model using multiple sediment source points and constrained by recent marine survey data was developed to simulate the deposition and preservation of potential stratigraphic successions across the sub-basin. Pseudo-wells have been extracted from the stratigraphic forward modelling output to forecast vertical and lateral stratigraphic trends. These trends were analysed to predict fault seal and structural trapping likelihood using the Shale Gouge Ratio methodology and triangle juxtaposition diagrams.Over the study area, the modelled facies distributions and geometries are consistent with sequence stratigraphy, seismic stratigraphy and well data. The stratigraphic model shows an overall NW to SE trend of decreasing sand volume and sand interval thickness for the Tiger and Hammerhead supersequences. Although this highlights the general trend of a higher likelihood of reservoir presence to the NW of the study area, and more seal presence to the SE, the model predicts enough vertical variability within the supersequences to create ranges of stacked reservoir-seal couplets.The stratigraphic model and fault seal assessment suggest that, in the marine-influenced Tiger and lower Hammerhead supersequences, the best reservoir and top/fault seal couplets are located along a WSW-NE trend to the NW of the study area where faults with throw≥150 m are expected to yield membrane fault seal. The NW corner of the study area is predicted to have high net-to-gross ratio for the upper Tiger, too high to yield any efficient membrane fault seal. In the deltaic upper Hammerhead supersequence, the best reservoir and top/fault seal couplets are expected along an E-W trend in the central part of the study area. Along this trend faults with throw≥100 m are expected to yield membrane fault seal able to impede lateral hydrocarbon flow in modelled mid Campanian reservoirs and a nearshore interval.These inferred Late Cretaceous structural traps could have been charged by hydrocarbons expelled from local Late Cretaceous source rocks between the Cenomanian to the present-day.

Using Monte Carlo models to predict hydrocarbon column heights and to illustrate how faults influence buoyant fluid entrapment

Faults are often assumed to play a significant role in the migration and entrapment of hydrocarbons, either offering conduits for, or barriers to, fluid flow. They may also affect fluid-phase trapping and influence phase fractionation in the subsurface. A Monte Carlo modelling approach is used to model these effects for trap analysis. The aim is to show how varying fault seal capacity, the fault orientation, the regional stress tensor and the trap geometry can all affect how both oil and gas are retained within a trap. The model reduces the problem to a 1D analysis with a structural description depth-referenced to the crest of a prospect. Both juxtaposition and membrane fault seal are modelled, together with hydrodynamic effects and fault reactivation risk. The potential of a prospect to trap hydrocarbons is evaluated in a roll-up of results with the outputs including a predicted hydrocarbon column height distribution and column height control statistics. The technique also offers an insight into the potential fluid-phase partitioning that may occur dependent on the interplay between the active leakage mechanisms and spill control, enabling gas v. oil columns to be predicted. Thematic collection: This article is part of the Fault and top seals collection available at: https://www.lyellcollection.org/cc/fault-and-top-seals-2019

Fault seal modelling – the influence of fluid properties on fault sealing capacity in hydrocarbon and CO 2 systems

Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO 2 –brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO 2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO 2 –methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO 2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO 2 –brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters. Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO 2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049 This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series