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Collaborating Authors
Disposal/Injection
Deep-Water Floating Offshore Wind Turbine Concept for Subsea Water Injection
Simos, A. N. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Salles, M. B. (Laboratory of Advanced Electric Grids, University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Monaro, R. M. (Laboratory of Advanced Electric Grids, University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Martins, M. R. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Mas-Soler, J. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Gay, A. (Structural and Geotechnical Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Franzini, G. R. (Structural and Geotechnical Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Carmo, B. S. (Mechanical Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Pesce, C. P. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Morishita, H. M. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Carvalho, D. F. (CENPES/Petrobras, Rio de Janeiro, RJ, Brazil) | Amaral, G. A. (Structural and Geotechnical Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Lima, B. C. (Laboratory of Advanced Electric Grids, University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Terra, L. S. (Naval & Ocean Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil) | Harger, A. (Structural and Geotechnical Eng. Dept., University of Sรฃo Paulo, Sรฃo Paulo, SP, Brazil)
Abstract This article presents technical aspects concerning the design of a Floating Offshore Wind Turbine (FOWT) that is devised for supplying energy to a subsea water injection system (SWI) in a deep-water region. The main purpose of the project is to replace the conventional energy supply provided by gas turbines by wind energy, thus contributing to the decarbonization of offshore O&G production. The water injection scenario was defined by Petrobras and includes subsea pumps with power distribution and control system placed on- board the FOWT. The FOWT substructure and its mooring system were dimensioned by means of a coupled optimization procedure, which took into account the metocean characteristics of the site by means of long-term series of combined wind, waves and current data. A BESS (Battery Energy Storage System) was adopted to stabilize the off-grid electrical system and optimized to limit the subsea electrical motors stoppages. Aiming to provide realistic estimates of injected water volume, typical wind turbine efficiency factors and fault rates were considered in the analyses together with repair times calibrated according to the application scenario.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Renewable > Wind (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Campos Basin (0.94)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.94)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
Smart Water as a Sustainable Enhanced Oil Recovery Fluid: Covariant Saline Optimization
Quintella, C. M. (Federal University of Bahia) | Rodrigues, P. D. (Federal University of Bahia) | Silva, H. R. (Federal University of Bahia) | Carvalho, E. B. (Federal University of Bahia) | Souza, E. Ramos de (Mosaico Fluido Pesquisa e Inovaรงรฃo Ltda) | Santos, E. (Mosaico Fluido Pesquisa e Inovaรงรฃo Ltda) | Nicoleti, J. L. (Federal University of Bahia) | Hanna, S. A. (Federal University of Bahia)
Abstract Although the migration to renewable energies is accelerating, for several decades the fossil fuels will still be essential for mankind. More environment friendly EOR methods are a current challenge. Recently, injection of aqueous fluids with low salinity (Smart Waters) had good performance and reduced environmental impact. However, there still is no consensus on the best ion concentrations, which may be due to experimental designs being linear whilst EOR processes are covariantly synergistic. This work optimized the pre-salt oil recovery factor in limestone by injecting smart water with 30 formulations defined by covariant statistical experimental design, with Doehlert Matrix, for NaCl, CaCl2 and NaHCO3. Injected and produced fluids were characterized by rheology, pH, conductivity, molecular fluorescence spectroscopy and X-ray fluorescence. No direct univariate relationships between recovery factor and pH, TDS or ionic concentration were found. The recovery factor was maximized from 35.9% up to 52.5%. Two optimal regions were discovered, one with slightly lower salinity and the other with slightly higher salinity, which may explain the lack of convergence in the literature on linear concentration variation. NaHCO3 concentration presented the highest statistical significance, which is attributed to the maximization of the reduction in the oil/oil and oil/rock interface tension. Its presence synergistically favored lower concentrations of NaCl. Separately, NaCl CaCl2 showed opposite statistical significances. However, their synergy was evident in the high positive significance of their association, due to the association of monovalent and bivalent cations. In addition, molecular dynamics calculation revealed that monovalent ions improve the wettability of water on the carbonate rock. There was no preferential production of any type of asphaltenes. Total dissolved solids influenced the rheological profiles when at high concentrations. The dynamic evolution of the roles of Cl and Ca ions was identified as more porous volumes of smart water are injected, through variations in their concentration in the aqueous fraction produced, which was attributed to the fact that, as oil is produced and the intelligent injection of water continues, the interaction of the chlorine anions with the rock intensifies, leading to the gradual release of calcium cations until the surface saturation process occurs.
- South America > Brazil (0.46)
- Asia > Middle East > Saudi Arabia (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.49)
- Reservoir Description and Dynamics > Reserves Evaluation > Recovery factors (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.89)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.69)
WAG Optimization of Egg Model with Brazilian Pre-Salt Fluid Using PSO Algorithm
Freitas, V. R. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil) | Sรกnchez, William Humberto Cuรฉllar (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil) | Lima, G. S. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil) | Pastrana, M. A. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil) | Barroso, E. P. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil) | Muรฑoz, Daniel M. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil / Faculty of Gama, Electronics Engineering Undergraduate Program, University of Brasรญlia, Brasรญlia, DF, Brazil) | de Almeida, R. V. (Repsol Sinopec Brasil, Pesquisa e Desenvolvimento, Rio de Janeiro, RJ, Brazil) | Fortaleza, E. L. F. (Department of Mechanical Engineering, University of Brasรญlia, Brasilia, DF, Brazil)
Abstract Water Alternating Gas (WAG) is a consolidated enhanced oil recovery method that outperforms secondary recovery methods such as waterflooding or gas injection. Optimization of the WAG parameters can increase the cost function and improve revenues, but the algorithms usually implemented require high computational resources and time. In this context, a bio-inspired algorithm, Particle Swarm Optimization (PSO) is used to determine the best candidate for only two parameters, water and gas injection time, resulting in the determination of the WAG cycle and WAG ratio, thus drastically reducing the complexity of the problem. The proposed long-term optimization algorithm was applied in a modified version of a well-known reservoir benchmark Egg model, in which the fluid composition was adapted to resemble Brazilian pre-salt reservoir fluids and WAG injection. Moreover, it is shown that the best results obtained consider longer periods of water injection and improve the NPV by 5.5%.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- (2 more...)
Abstract Voidage replacement is a pre-requisite to optimize production and hydrocarbon recovery in oil fields. Sometimes, deep water production systems suffer from low water injection (WI) uptime and the natural declining reservoir pressure. The congested FPSO topside makes modifications and upgrades expensive with long shutdowns. Therefore, complementing existing WI with subsea water treatment and injection may be considered attractive. Moving process subsea allows for simplifying new developments and enables long tiebacks with โlocalโ and decentralized water treatment and injection. Subsea seawater treatment for water injection has several inherent advantages compared to topside treatment. One significant aspect is the increased flexibility afforded to reservoir engineers in improving effective reservoir management by providing the opportunity to implement any desired water injection capacity, anywhere and anytime. In addition, the ability to provide โtailor madeโ water for injection into oil reservoirs, that may be phased, is seen as a game changing opportunity for offshore oilfield production companies wishing to produce more, produce faster, and produce cheaper. The solution, qualified for water depths down to 3,000 m, enables weight reduction and simplification of the topside process equipment, with its associated maintenance requirements and HSE footprint and enables more active reservoir management. The short distance the water travels, and the unique approach to water treatment make the subsea solution attractive with reduced energy and chemical consumption. The modular approach and flexibility provide more freedom to manage the subsurface uncertainties, mitigating risks and pursuing upsides. The process advantages of the seawater treatment plant being on the seabed allows for a design that is simplified compared to a corresponding topside plant. The all-electric design also has the capabilities to be installed, moved, and reused on the seabed with minimum impact on topside infrastructure. There are several aspects of the design that reduce the HSE impact of water injection. This includes lower power consumption (reducing carbon footprint) and no (or significantly reduced) liquid chemical requirement; hence, lower handling exposure for operators, improving the operational safety.
- South America > Brazil (1.00)
- Europe (0.69)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
Abstract Drag Reducing Agents (DRAs) are commonly ultra-high molecular weight (UHMW) polymers used to reduce frictional pressure loss in a fluid flowing in a turbulent regime pipeline, thus, allowing to enhance its production capacity. The increasing oil fields development in challenging environments (such as, for example, deep water conditions) and the request to maximize their production have led to an Eni R&D project whose aim was to develop/find suitable DRAs for umbilical injection, since the conventional UHMW DRAs are not feasible for these tougher scenarios. Initially, a market screening of the major chemicals providers portfolio has been done with the purpose to find conventional DRAs whose employment in deep water injection systems does not lead to chemical umbilical plugging. Due to the failure of this scouting, the objective of the work reported in this paper was to carry on an experimental study of performance assessment, from one side, of chemicals with surfactant properties not specifically formulated as DRA and, on the other side, of the dilution of conventional polymeric DRAs in solvent. All the experimental evaluations carried out at lab scale were performed with a specific test apparatus able to estimate additives capability to reduce pressure drops under turbulent flow regime at different Reynolds numbers. Finally, a new commercial surfactant-based Flow Improver chemical, suitable for the injection in umbilical systems, was identified by experimental tests as promising in reducing pressure drops. Thus, in 2020 a sealine with multiphase fluid production, in a deep-water Eni field, was selected for a trial. A preliminary hydraulic sensitivity analysis was performed, by means of fluid dynamic simulations, which confirmed the suitability of this flowline for the scope and predicted a potential production gain.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
Abstract This paper presents and discusses data on the application of DNA tracers to a waterflood project in Edmisson Clearfork field in Permian Basin, Tx. The field is divided into two sections, West and East. The West section includes five injection wells, fifteen producers and the East section includes two injection wells and nine producers. To fully understand the flow path within both sections, seven unique DNA tracers were selected and injected. In addition, it was desirable to accurately determine water breakthrough through each production well and to evaluate heterogeneity of the formation between the injection and production wells. Furthermore, identification of high and low permeability zones within the reservoir was identified. Reservoir properties such as drainage area, porosity, water saturation, connate water saturation and water injection rate per well along with the minimum detection limit of DNA tracers were used to calculate the amount of DNA tracers needed to inject in each injection well. A robust sampling schedule was used to make sure an early detection of tracer(s) at each production well. A selected number of samples were used for analyses of tracers. Other samples were kept for future analyses as needed depending on tracer response curve between each injection well and producer.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Successful Application of Intelligent Completions in a Deepwater Gulf of Mexico Water Injector
Bolingbroke, H. F. (Oxy, Houston, TX, USA) | Saripally, I. (Oxy, Houston, TX, USA) | Webb, K. (Oxy, Houston, TX, USA) | Gandhi, N. (Oxy, Houston, TX, USA) | Askeroglu, I. (Oxy, Houston, TX, USA) | Beecher, R. (Oxy, Houston, TX, USA)
Abstract In complex reservoirs with challenging operating conditions, intelligent completions have proven to be instrumental in optimizing water injection and conducting reservoir surveillance. In this paper, we present a multi-disciplinary case study from deepwater Gulf of Mexico (GOM) highlighting the critical role played by an intelligent completion in a dual zone water injector. The GOM field in this study is a Pliocene-aged, high-density turbidite sand consisting of multiple stacked reservoirs. It is a mature field with more than 15 years of production and water injection. The hybrid wells are tied back to the offshore platform via individual marine risers, so well-bay slot availability is limited. Thus, a dual zone injector with downhole choking was planned to maximize wellbore/slot utility. The intelligent completion provided the ability to inject selectively at desired rates into each zone for waterflood optimization. This case study demonstrates an integrated framework of planning, drilling, completing, and operating a state-of-the-art intelligent well in an offshore environment, including: Wellbore planning: A dual-zone injector was chosen to make the best use of existing infrastructure and slot availability. Un-swept and pressure-depleted reservoir targets were identified through seismic and pressure data. Numerical models were built to aid with downhole choke design and to forecast the response seen in offset producers. Drilling and Completions: Factors such as wellbore availability, directional constraints, and collision avoidance were reviewed. Wellbore component selection included an intelligent completion with downhole choking and a triple downhole pressure/temperature gauge. Metallurgy specifications, jewelry positioning, perforation strategy, and frac design were considered. Operations: The ability to isolate either of the two completed zones allowed for high-confidence surveillance and waterflood optimization. Additionally, the intelligent completion greatly assisted with acidizing and adding waterflood tracers, as each zone could be treated or isolated individually.
- North America > United States > Texas (0.28)
- North America > United States > Louisiana (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.60)
Abstract Real Time Virtual Flowmeter (RTVFM) is a key digital technology for real time monitoring of well performances, for both production and injection wells. The main advantage of this tool is to provide estimations of well flow rates, based on wellbore pressure drop, using real-time (RT) pressure and temperature data measured by gauges installed in the well. This paper focuses on the effects of water properties on RTVFM application to water injection by evaluating their impact on the dynamic gradient and its implication in the rate estimation. Injected water can be a mix of different sources: sea water, fresh water, formation water and produced water. As a result of these different contributions, it is common to observe variations of salinity even on an hourly basis. A variation of water salinity impacts on density and viscosity, therefore changing the dynamic gradient. Salinity in injected water is commonly measured by sampling analysis, thus providing data with a much lower frequency than RT gauges. As a result, it is not usually possible to integrate salinity variation into the standard RTVFM workflow, leading to significant errors in the rate estimation. The innovative workflow presented in this paper, named Virtual Salinity, calculates water salinity in real time in wells equipped with reliable flowmeters. It regresses the dynamic gradient equation on salinity values. The results of this workflow improve the quality of RTVFM application to other wells injecting the same water mix. At each timestep, virtual salinity values are used to evaluate the correct pressure gradient for RTVFM calculation. The workflow has been successfully tested on a deepwater offshore asset, to prove its reliability. The Virtual Salinity has been applied on an offshore injection network: three wells injecting a mix of produced and sea water. The workflow, applied to all injectors, generated consistent salinity profiles. A reference virtual salinity profile has been used as an input for RTVFM simulations. For all of the injectors, RTVFM reproduced the independent flowmeter measurement with enough accuracy. The innovative methodology here presented provides a key tool to monitor salinity of injected water and can be used in field where injected salinity is not measured, providing a valuable information at minimal costs. Water salinity is one of the main inputs of production data analysis, that allows to maximize reservoir knowledge and consequently final recovery. Moreover, the greater accuracy of Virtual Meter rates significantly improves the injection monitoring, thus supporting an effective reservoir management.
- Europe (0.68)
- Asia > Middle East (0.47)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.72)
Investigation of the Oil-Soluble Particulate Temporary Plugging Agent-Assisted Water Huff โnโ Puff Enhanced Oil Recovery in Tight Oil Reservoirs
Kang, Shaofei (College of Petroleum Engineering, China University of Petroleum (East China)) | Pu, Chunsheng (College of Petroleum Engineering, China University of Petroleum (East China) (Corresponding author)) | Wang, Kai (College of Petroleum Engineering, China University of Petroleum (East China)) | Li, Xu (College of Petroleum Engineering, China University of Petroleum (East China)) | Zhang, Na (Department of Industrial Engineering, Shandong University of Science and Technology) | Yan, Dong (College of Petroleum Engineering, China University of Petroleum (East China)) | Huang, Feifei (College of Petroleum Engineering, Yanโan University)
Summary Water huff โnโ puff is an effective enhanced oil recovery (EOR) technology for tight oil reservoirs. However, the oil production of horizontal wells declines seriously after several huff โnโ puff cycles, and a large amount of oil is still trapped in the reservoir due to the heterogeneity of fracturing sections. The temporary plugging agent had been used for plugging high-permeability areas and thus diverting the following fluid into small permeability areas. It would improve the sweep efficiency of flooding fluid, enhancing oil recovery. However, the use of the oil-soluble particulate temporary plugging agent in the water huff โnโ puff application is barely reported. Therefore, the feasibility and influencing factors of oil-soluble particulate temporary plugging agent-assisted water huff โnโ puff (TAWHP) in enhancing oil recovery was investigated in this study. First, based on the evaluation of the performance of the oil-soluble particulate temporary plugging agent, the oil recovery of fractured core samples with different apertures for water huff โnโ puff and TAWHP was compared via the parallel-core experiment to verify the feasibility of TAWHP in enhancing oil recovery. The temporary plugging agent had good oil solubility, a low residual rate in the formation, and little damage to the formation. The oil recovery yielded by TAWHP was 5.17% higher than the traditional water huff โnโ puff process. More oil (i.e., about 1.71%) could be expelled from the fractured core samples with a small aperture. It indicated that the EOR performance yielded by water huff โnโ puff after several cycles could be enhanced by adding the oil-soluble particulate temporary plugging agent. After that, a mathematical model of TAWHP was established to investigate the effect of TAWHP parameters on EOR performance. The simulation results showed that the cumulative oil production increased with the increase in injection time of the temporary plugging agent solution, but the trend would level-off after 10 minutes. Moreover, as the diversion index increased, the effect of the injection rate on cumulative oil production gradually enhanced while the effect of the soaking time gradually weakened. Furthermore, the difference in cumulative oil production at different diversion indexes gradually increased as the huff โnโ puff cycle increased. This work could provide theoretical guidance for water huff โnโ puff enhancing oil recovery after several cycles.
- Asia > China (0.68)
- North America > United States > Texas (0.28)
- North America > United States > West Virginia (0.28)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.32)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (6 more...)
Abstract In the S-Field operations office, a daily battle ensues in the quest to increase production and maximize profits from waterflooding. One of the main control mechanisms applied to optimize the waterflooded reservoirs is by controlling the water injection and pumping rates of producers to balance patterns, maximize sweep, and maintain reservoir pressure. The reservoir surveillance team has been using a simple spreadsheet analytical approach that was quite limiting as the number of injection patterns increased, and the flood matured, leading to a water breakthrough. There was a need for a more sophisticated approach that could leverage artificial intelligence (AI) technology, especially since the entire asset was undergoing significant digitalization of its operations. This paper presents various innovations in bringing real applications of AI for waterflood management. This includes innovations in business processes, application of design thinking methodology, agile development, and AI. The AI waterflood management solution combines cloud technologies, big data processing, data analytics, machine learning algorithms, robotics, sensors and monitoring system, automation, edge gateways, and augmented and virtual reality (AR/VR). Design thinking principles and a human-centric approach within an agile innovation framework were utilized for rapid prototyping and deployment. A waterflood management framework that addressed the business's operational, tactical, and strategic aspects created the backdrop for designing the solution architecture. New injector-producer modeling techniques that leveraged AI and were fit-for-purpose for reservoir surveillance and production engineers were prototyped. An interactive pattern flood management tool, adapted from streamline simulation-based waterflood analysis methods, was developed for injection pattern analysis and intelligent optimization workflow. Field pilot testing for over a year proved that the prototype could reliably detect injector-production interactions and recommend operating set points in relevant time. Reduced time to decision, improved analysis efficiency and reliability of short-term forecasts, reduced field visits and health-safety-environment (HSE) exposure, and finally ease-of-use has been experienced. The learnings from this project are being leveraged to develop a deployable solution and move the needle toward autonomous waterflood operations.
- Asia > Middle East (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.49)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.46)
- Europe > Netherlands > German Basin (0.99)
- Europe > Germany > German Basin (0.99)
- Europe > Denmark > German Basin (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin > Huoshaoshan Field (0.99)