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Abstract The current oil business panorama demands for cost effective and efficient methods for well surveillance and production monitoring optimization. The integration between traditional technologies such as PLT and geochemistry fingerprint with innovative technologies such as tracers (both interwell and intrawell) and/or Fiber Optic (in both its temperature and acoustic deployments), is a requisite for fluid movement surveillance. This strategy is fundamental, especially if field developments are based on long horizontal drains, deep waters/extreme well paths, multilateral wells, ESPs and subsea clusters where the risk of tool stack is high, the borehole access is limited and the monitoring activities are very expensive. In Eni, the integration of intrawell tracers with permanent Fiber Optic system, wireline logs, inter-well tracers and geochemical fingerprint is considered a successful and comprehensive approach for field/well management and production optimization. The proposed 4 case studies prove, with their high quality data availability and interpretation, how the information collected in this way can be the turning point for a long-period reservoir monitoring during clean up, steady state and re-start stages leading to a more specific intervention and management at well and field levels. Introduction Reservoir surveillance is a critical part of reservoir management. It is aimed at risk minimization by proactively identifying and fixing problems encountered during completion and production by means of different technologies. Information derived from reservoir surveillance is a key factor in taking important decisions associated with optimizing total recovery from the field. Fluid movement monitoring is one of the purposes of reservoir surveillance to understand where oil comes from and how much and where water breakthrough occurs. The monitoring can be done through traditional technologies such as PLT and Geochemistry and innovative technologies such as Fiber Optic as Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS), Tracers and Advanced Logging (Spectral Noise Logging). Integration between different technologies could improve the reservoir knowledge. The aim of this paper is to show the possible benefits associated with the installation of downhole chemical tracers directly along the completion and integrated with the data coming from the other technologies. This can improve reservoir behavior monitoring, completion strategy verification and field management saving, at the same time, costs.
- North America > United States > Texas > Dawson County (0.24)
- Africa > Cameroon > Gulf of Guinea (0.24)
Abstract Scope of this paper is to show how the proper definition of reservoir rock types, based on core data and integrated with nuclear magnetic resonance (NMR) log results, is able to provide a reliable strategic estimation of permeability in un-cored wells where only conventional logs are available. The target is to optimize the perforated intervals by means of a robust discrimination between movable and un-movable fluids and consequent detection of the reservoir zones characterized by the best gas deliverability potential. Mercury injection capillary pressure measurements have been used to evaluate the core pore throat size distribution and to separate micro from macro porosity. The integration of these information with NMR, acquired on the same core, allows to calibrate the most efficient T2 cut-off, discriminating movable from the unmovable fluids. The final outcome is a robust link between reservoir properties (defined and directly measured on core data) and log classification, giving a key driver for the definition of a synthetic permeability profile, rock type dependent, and applied for perforated interval optimization in wells where no cores are available. The blind test was a comparison between estimated permeability from the well production performance and permeability derived from NMR logs, showing a good match. The work has greatly increased the value of NMR acquisition in Gas industry, showing how a proper T2 Cutoff core /log calibration is a vital factor to get the benefit of NMR in Gas reservoirs permeability prediction, providing a useful driver for perforated interval optimization. Introduction At present time, permeability estimation still remains a great challenge due to its not scalar nature: different correlations have been defined in literature to link this parameter to conventional downhole measurements and petrophysical properties, anyway none of the current available open hole logs can deliver directly an indication of the estimated permeability. Even the most advanced NMR tool will fails if applied in a standalone approach. The result is that the conventional log analysis approach, where core data are used mainly for outcome validation, still leave some uncertainties in the permeability profile definition and related reservoir effective deliverability.
- Africa > Middle East > Egypt > Nile Delta (1.00)
- Africa > Middle East > Egypt > Mediterranean Sea > Greater Nooros (0.30)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.30)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Delta Field (0.99)
- Africa > Middle East > Egypt > Western Desert > Bahariya Formation (0.99)
- Africa > Middle East > Egypt > Nile Delta > Nile Delta Basin > West Mediterranean Concession > Abu Qir Field (0.99)
- (9 more...)
Abstract The Oil & Gas subsea market requires innovative technologies to enable economically viable developments, in particular by maximizing the utilization of available assets, through new field tie backs to existing host facilities, and by enhancing the production of already producing fields. This poses a series of challenges, namely:Reducing the required topside space. Handling very long step-outs. Increasing the oil recovery factor. Ensuring flow assurance in critical conditions. This can be obtained with the aid of subsea processing technologies. Saipem has focused, over the last few years, on the development of subsea separators and, in partnership with Total and Veolia, of a subsea water treatment and injection process, composed of several modules and requiring a certain amount of new subsea technology (subsea barrier fluidless water injection pumps, filters, special water analyzers, etc.). One of these technologies is the all-electric subsea control system. The all-electric solution was selected as opposed to the electro-hydraulic for its inherent capability to:enable long step-out distances run logics such as sequences and fast closed control loops involving subsea proportional valves manage high frequency of simultaneous valve actuations implement safety functions even SIL certified, when required. Within the ongoing industrialization programme of the new technologies, Saipem has signed a Joint Development Agreement with Siemens for the qualification of the open framework platform for the control of subsea processes. The Saipem and Siemens JDA activity has already concluded the Q1 qualification tests of components according to API 17F. Q2 tests of assemblies are currently ongoing. The qualification will be completed by first half of 2019. Introduction The subsea control system to be installed on subsea processing plants shall be of improved performances with respect to the standard subsea production control system and an "All Electric" solution was deemed the best technology to achieve enhanced performances. After a deep market screening about all electric subsea control system solutions, the necessity of a new development arose due to specific subsea processing requirements.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Information Technology > Software Engineering (1.00)
- Information Technology > Software (1.00)
- Information Technology > Communications > Networks (1.00)
Abstract Operators in unconventional regions manifest corrosion and wear on their drilling equipment differently. A drilling fluid maintains contact with the drill string and its components, making it a key factor when considering the causes of corrosion and wear, fluid design that minimizes wear is paramount. The effects of abrasive formations on the drillstring, controlling oxidation, and minimizing wear are of primary concern. The fluids tested with different methodologies in the laboratory to best represent the field. Along with more well-known testing, a new means of testing tool wear and its implication to drill string and hard-banding technology was introduced. Each area-of-concern may be addressed with particular additives to the drilling fluid. Three different types of drilling fluid was tested and compared. When comparing lubricity coefficients, a high performing water-based fluid (HPWBF) and an oil-based fluid (OBM) outperformed a brine water based fluid by 60.5﹪ & 55.1﹪, respectively. Wear data was also assessed to reveal a similar trend. With knowledge of the different environments and products, a drilling fluid formulated with a high performing drilling enhancer (HPDE) and corrosion inhibitors so that oxidation was controlled. Using the additives, the operator ended up having to replace less of the drill-string when in comparison to other wells. In West Texas, proper viscosifying agents to suspend the solids along with mechanical solids control equipment needed to address recycling the drilling fluid, which was expected to build up abrasive solids. The HPDE would be added to reduce the coefficient of friction (CoF) of the fluid and minimize wear caused by interaction of the drillstring and abrasive formation. Experiences from a laboratory correlating the coefficient of friction to the wear rate have proved fruitful for field applications. The operator will have the option to use a more cost-effective environmentally friendly HPWBF. Using this information, the well planning allows for application and or dosing preventing drilling string/hard-band wear. By controlling the abrasivity of the environment, chemical additions to the drilling fluid can aid in improving the wear-rates on a known material.
- North America > United States > Texas > Permian Basin > Delaware Basin > Wolfcamp Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Bone Springs Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Wolfcamp Shale Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Bone Springs Formation (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (0.70)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.67)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (0.65)
- Management > Professionalism, Training, and Education > Communities of practice (0.51)
Use of Ultra-Low Fluid Invasion Additive to Improve Wellbore Stability, Strengthen Wellbore, and Eliminate Differential Sticking - Case Histories from Kuwait
Al-Ajmi, Abdullah (Kuwait Oil Company) | Al-Rushoud, Abdulaziz (Kuwait Oil Company) | Gohain, Ashis (Kuwait Oil Company) | Khatib, Faiz Ismail (Kuwait Oil Company) | Al-Naqa, Faisal (Kuwait Oil Company) | Al-Gharib, Majed (Kuwait Oil Company) | Al-Mutawa, Faisal (Kuwait Oil Company) | Al-Ajmi, Ali (Kuwait Oil Company) | Al-Mekhlef, Alanoud Mahdi (Kuwait Oil Company) | Chouhan, Manoj (Kuwait Oil Company) | Mago, Ankit (Kuwait Oil Company) | Rossi, Arnaldo (Newpark Drilling Fluids) | Samaan, Fady (Newpark Drilling Fluids) | Giuliano, Giuseppe (Newpark Drilling Fluids) | Uchytil, Rodney (Impact Fluid Solutions) | Mclellan, Justin (Impact Fluid Solutions) | Barsoum, Victor (Impact Fluid Solutions) | Abdelaziz, Rami (Impact Fluid Solutions)
Abstract Wellbore instability, differential sticking, and lost circulation are significant challenges while drilling build-up sections through stressed shale and formations with varying pore pressures. Conventional drilling fluid systems have not eliminated these drilling challenges, and thus it was necessary to identify a fluids solution which could enhance drilling performance and meet these challenges. Based on extensive laboratory tests, an ultra-low fluid invasion (ULFI) additive was selected. The ULFI technology is designed to form a very-low permeability seal that limits the transmission of destabilizing wellbore pressure into the geologic formations. This pressure barrier effectively minimizes formation breakdown and prevents fractures from propagating, creates a wellbore seal which effectively minimizes fluid invasion into micro-fractures, and thus stabilizes the weak shales. A customized drilling fluid system was designed using the ULFI additive in conjunction with sized CaCO3 and synthetic resilient graphite. These particles effectively plugged the pore throats and minimized the fluid invasion, which was confirmed by sand-bed tests as well as permeability plugging tests (PPT) under downhole conditions. The customized drilling fluid utilizing ULFI additive proved its success by providing:Achieved zero non-productive time (NPT) related to fluids Improved wellbore stability in stressed shale formations Eliminated the risk of differentially stuck pipe across low-pore-pressure formations Mitigated induced losses by utilizing customized bridging additives Enhanced hole cleaning at critical build angles All challenging build-up sections were successfully completed without any issues. There were no wellbore instability issues including differential sticking tendencies or drilling fluid losses reported. Wellbore instability was mitigated even when drilling in the minimum stress direction, which is typically more challenging compared to the maximum stress direction. This paper will present the success of the ultra-low fluid invasion (ULFI) additive in an invert-emulsion fluid (IEF) with case histories for reference. The molecular weights of the polymer components in the ULFI additive are low, which allowed for easy mixing and did not contribute negatively to rheological changes in the drilling fluid system.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > Middle East > Kuwait > Jahra Governorate > Rawdatain Basin > Lower Burgan Formation (0.99)
- Asia > Middle East > Iran > Thamama Group > Shu'aiba Formation (0.99)
- Asia > Middle East > Kuwait > Northwest Kuwait > Arabian Basin > Widyan Basin > Mutriba Field > Gotnia Formation (0.98)
- (17 more...)
Abstract The hydraulic communication among 16 offshore fields located in North Africa has been investigated by means of a 3D regional dynamic model, the first ever developed for this region by Eni. Since 1976, the area has been drilled with more than 150 wells and field pressures were found to be supported by a unique aquifer. Among these fields, two giant structures have already been put in production, the Alpha structure in 1988 and the Beta structure in 2005, whilst other minor accumulations have not yet been exploited. Starting from a detailed field data analysis, a common pressure trend in the aquifer zone was recognized, while for each mineralized structure different hydrocarbon contacts were identified. Moreover, appraisal wells drilled in the undeveloped fields, after the production start-up of the first producing reservoir, clearly showed that depletion was occurring also in the virgin structures, thus confirming the presence of hydraulic communication. A 90×90 km model is therefore developed in order to describe the overall fluids behaviour inside the region by taking into account 16 different mineralized culminations and the water bearing areas among them. Despite the complexity of the work, the model is developed and tested to be robust and to provide key information useful for determining the best possible exploitation strategies. Introduction Exploitation of oil & gas resources is strictly related to pressure regime in a reservoir. In particular, considering reservoirs with the same petrophysical characteristics, more the reservoir is depleted, more challenging is the exploitation of hydrocarbons. The application of IOR techniques or the presence of natural aquifers support, if any, may reduce the pressure drop. The size of these pressure-supporting aquifers and their strength can vary considerably worldwide and unique regional aquifers can simultaneously affect multiple reservoirs. Very few examples in literature are present [1, 2, 3] regarding the analyses of the impact of regional aquifer support on producing reservoirs and nearby accumulations. A regional 3D dynamic model was built by Eni to simulate the behaviour of undeveloped fields communicating with producing pools by a unique aquifer; this model allows to optimise the development plan and to mitigate the associated risk.
- Asia > Middle East (0.69)
- North America > United States > Louisiana (0.32)
- North America > United States > Louisiana > Iota Field (0.99)
- North America > United States > Louisiana > Alpha Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.98)
- (24 more...)
Landing and Geosteering in Single Drilling Phase in Complex Gulf of Suez Reservoir using Innovative Combination Resistivity Technologies with Multiple Depth of Investigation with Cost Effective Solutions, Petrobel (ENI).
Khalil, M. (Petrobel) | Alaa, M. (Petrobel) | Morad, Aly (Schlumberger) | Saher, Mohamed (Schlumberger) | Samir, E. (Schlumberger)
Abstract The changes of the recent years on the oil market motivated the collaboration between operators and service companies to find cost viable solutions to optimize production. This involved also an increase of horizontal wells in complex reservoir with advanced technology. This solution was employed by Petrobel to drill a challenging horizontal well in Belayim Area. This is a structural complex area, result of the interference of two main extensional faults systems related to the opening of the Gulf of Suez. The well area was interpreted from seismic to be an anticline structure elongated in NNW/SSE parallel to a regional fault dipping westward and limiting the field. The traditional approach to drill horizontal wells on this type of field would have been to assess the structure and target with a pilot hole. To eliminate the need for a pilot hole and improve financial sustainability, Petrobel and Schlumberger applied technologies that are utilized in real-time for pilot hole elimination and moreover to define the multiple boundaries inside or around the target. The objective was to map the structure far away from the borehole, opening the possibility of taking proactive decisions on wellbore trajectory to land and keep the wellbore within the desired oil bearing sand. The solution was introduced for the first time in Egypt by Petrobel. Different technologies were combined to provide multiple depths of investigation, from the reservoir scale to the proximal area around the wellbore. The set-up allowed to land the well using the reservoir mapping data despite a completely unexpected geological scenario. Once entered the target, a detailed description of the oil bearing sand was possible using the inversion based on the multilayer bed boundary detection service information. The innovative approach allowed geosteering the subject well within 100 m Measured depth of clean sand despite abrupt structural changes not visible on pre-drill seismic model. Inside the reservoir, the advanced high-resolution inversion (Periscope HD) was selected to be run, In order to optimize the position of the well in the target, the tool was able to map multiple bed boundaries in high resolution, in order to illuminate the reservoir structure in real time ahead of the bit. Thin layers, about 0.5m in thickness, were observed 25m MD ahead of the bit about 1.5m TVD below the well trajectory, which improve geosteering decisions to remain within the oil-bearing sand. Also, the PeriScopeHD was able to map the Water contact.
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt > Gulf of Suez (0.16)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.97)
- Geology > Structural Geology > Tectonics > Extensional Tectonics (0.90)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Belayim Land Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Belayim Formation (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Belayim Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Sidri Field (0.91)
Case Histories from Kuwait to Drill Commingle Zubair Shale Sand Sequences by using Customized High Performance Water Base Fluid
Al-Khaldy, Meshal Dawood (Kuwait Oil Company) | Dutta, Abhijit (Kuwait Oil Company) | Al-Failkawi, Khaled Ali (Kuwait Oil Company) | AL-Rashidi, Ali Hussain (Kuwait Oil Company) | Tickoo, Ashish (Kuwait Oil Company) | Hamed, Abdelrahman Abdelkader Mahmoud (Kuwait Oil Company) | Aldouseri, Ghanem Obaid Mohammed (Kuwait Oil Company) | Al-Suraie, Abdulkarim Faisal (Kuwait Oil Company) | Saleem, Abdullah Ahmed (Kuwait Oil Company) | Zakaria, Ali Essa (Kuwait Oil Company) | Rossi, Arnaldo (Newpark Drilling Fluids Kuwait Operations) | Spagnoli, Nazareno (Newpark Drilling Fluids Kuwait Operations) | Samaan, Fady (Newpark Drilling Fluids Kuwait Operations)
Abstract Hole stability and differential sticking are main challenges while drilling through commingle shale & sand sequences. Conventional mud systems cannot ensure wellbore stability and sustain high overbalance, which led to the need of use ‘customized fluids’. Traditionally, Oil-Based Mud (OBM) have been used while drilling these formations to avoid high NPT hours. It was necessary to identify an alternative fluid's solution to replace Oil-Based Mud with Water Based Mud capable to provide good borehole stability. Using High Performance Water Base Mud (HPWBM) to drill Zubair Formation was the first ever application in KOC. A customized drilling fluid system was designed using a blend of Synthetic Copolymer, and Organic Clay inhibitors combined with sized particles. This effectively stabilizes hydratable and dispersible shale, plug pore throats and minimizes fluid invasion, as confirmed by particle / permeability plugging tests and Linear Swell Meter tests under hole conditions, overcoming below challenges.Perform sampling in Zubair formation successfully for 1 time in KOC with WBM Improve hole stability through stressed shale formations Hole stable under extended conditions (total loss condition and multiple trips on elevator) Sustain high overbalance and mitigate differential sticking tendency Drilling, logging, running and liner run and cementing was successfully completed in the commingle section without any incident. There was no NPT related to well-bore instability or differential sticking tendency reported. MDT sampling was at an advantage due to faster cleanup time in WBM, sample quality was very good with >95% oil in sample recovered. This paper will present the success of the HPWBM utilized to comingle Zubair shale with case histories for reference. Introduction Most operators in the world are more keen in use of non-aqueous fluid (NAF) over water based mud systems to drill challenging wells. NAF system has been considered technically superior over conventional water based muds in the areas of well-bore stability, inhibition, lubricity, rate of penetration, cuttings condition and differential sticking tendency. As the industry strives to achieve improved environmental solutions, the introduction of HPWBM creates the possibility of same performance where OBM's is typically used.
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.98)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.98)
Abstract The assessment of geological uncertainties in the petrophysical characterisation of reservoirs should be a common and standard approach, but a unique robust methodology is not yet available "off-the-shelf". Moreover, it is not granted that a unique approach may prove equally robust in all environments. It is therefore mandatory to develop a specific, sound methodology for the correct evaluation of the petrophysical uncertainty according to the reservoir characteristics, in order to propagate the correct results through the following reservoir modelling processes. A fit-for-purpose approach was developed in the scope of the non-conventional petrophysical interpretation [7] of a thin-layered reservoir, in order to evaluate the uncertainty associated to the most critical petrophysical properties, i.e. porosity and water saturation. The results proved that the approach was both robust and flexible enough to be applied to a specific interpretation process, in a complex geological and petrophysical environment. The quantitative evaluation of the uncertainty associated to the petrophysical properties provided a significant improvement in the knowledge of the true uncertainty finally fed into the reservoir model and risk analysis. Introduction This paper describes the fit-for-purpose approach developed to evaluate the petrophysical uncertainty in a critical formation, characterised by the presence of thin and very thin sand/shale alternations, where a conventional methodology could not provide robust estimates of the petrophysical properties and their uncertainty and, consequently, of HOIP. The workflow includes three main steps:First, the definition of the high-resolution petrophysical model of the reservoir, by means of e-tlac, the proprietary methodology developed by Eni to provide the quantitative characterisation of the petrophysical properties and the evaluation of Net Pay and NTG in thin-layered reservoirs Then, the analysis of the uncertainty. The specific environment required a fit-for-purpose adaptation of a step-by-step approach, that was eventually integrated into the e-tlac methodology Finally, an accurate sensitivity analysis of the results (including porosity, water saturation and NTG) was done to provide consistent estimates to the risk analysis process
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.50)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.46)
Abstract Petroleum biomarkers are complex carbon-based molecules derived from formerly living organisms and found in crude oils. These molecules are used by geochemists to get information on the source rocks responsible for the oils generation, such as lithology, depositional environment, organic matter, maturity and age. So they are of paramount importance for Petroleum System Modelling and more generally for exploration de-risking and sedimentary basin characterization purposes. Very often, biomarkers datasets are very large and interpretation process by geochemists can take several months to complete. For this reason, we developed an innovative Machine Learning-based support tool to facilitate and speed-up the whole process of biomarkers examination and interpretation. The core of tool is an advanced clustering method that allows expressing biomarkers data as a combination (mixing) of underlying components, directly ascribable to different source rocks. Non-negative constraint is a key aspect: the objective is to express each data sample, i.e. a vector with mainly non-negative values such as biomarkers concentrations and/or concentration ratios, as an additive combination of some of the underlying components, whereas subtracting components would not have any physical interpretation. A sparsity constraint is added to find solutions that allow to represent data as an additive combination of few source rock components. Both constraints greatly reduce non-uniqueness of the solution, greatly enhancing interpretability of the results. The tool then groups data in clusters, each one having a specific geochemical signature given by a set of scores for each of the different biomarkers' parameters. Each sample is assigned to a specific cluster with a "purity" percentage indicator. Geochemists can then easily use the high-purity samples to label the relevant samples as belonging to different source rocks. Moreover, the tool is able to distinguish the amount of mixing between different source rocks, through accurate deconvolution algorithms. Two applications of the tool are here presented, borrowed by real exploration case studies. In both cases the tool was able to separate samples into clusters that geochemists successfully recognized as lacustrine, marine and in some cases, transitional, with less than 10% of misclassifications, isolating also strongly biodegraded samples. This tool opens the doors also to the insertion and integration of other types of data (light hydrocarbons, diamondoids, etc.) for the whole ‘Big Data’ geochemical characterization of a sedimentary basin.
- Asia (0.47)
- North America > United States > Alaska (0.28)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- North America > United States > California > San Joaquin Basin (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)