Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
From Petroleum System Evaluation to Geomodeling, Production Forecasting and Reserves Determination in Unconventional Reservoirs
Silva, Cristhian F. Aranguren (Schulich School of Engineering-University of Calgary) | Gomes, Antonio Ch. S. (Schulich School of Engineering-University of Calgary) | Aguilera, Roberto (Schulich School of Engineering-University of Calgary)
Abstract The objective of this research is to examine the link between total petroleum systems (TPS), geomodeling and reserves determination with a view to improve production forecasting, and to increase petroleum rates and recoveries while keeping an eye on economics and externalities. Petroleum as used in this paper includes oil, dry gas, and natural gas liquids. The proposed method links geoscience and engineering through a multi-disciplinary team. Proper understanding of the petroleum system is the foundation for rigorous geomodeling and for increasing economically petroleum rates and recoveries. The idea is not to convert geoscience into engineering or vice versa. Rather the idea is to make sure that members of the team understand properly the data that the other participants need, and that they communicate each other precisely what they need and the form in which the data it must be supplied. The anticipated outcome is that the interaction will lead to a better understanding of the reservoir(s) and consequently improved forecasting of petroleum rates and recoveries. Results of the study indicate that engineering deals properly with three essential elements of TPS: reservoir, seal, and overburden rock. However, there is a lack of proper understanding of the first essential element: source rock. Similarly, engineering has a good handle on the fourth essential process of the petroleum system: the accumulation. But there is a lack of proper understanding of the first three processes: trap formation, generation, and migration of hydrocarbons. This paper looks at filling the gap in this lack of understanding. Having clear knowledge of the type of data needed by engineering from the beginning is important, for instance, when building variograms and performing geomodeling. For example, geoscience can generate 3D geological grids using hundreds or thousands of millions of cells. But engineering can only use in practice a fraction of those cells for simulating multiphase fluid flow. Thus, upscaling and downscaling of the geologic grid is necessary in some cases. The novelty of this paper is the linking of the TPS, geomodeling, forecasting and reserves determination of unconventional reservoirs. This type of linking leads geoscience and engineering to talk the same language with a view to improve communication. The result is better, faster, and more accurate studies that improve production forecasting, economic rates, and recoveries of petroleum reservoirs.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Asia > Middle East (0.93)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- South America > Colombia > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Wind River Basin > Madison Formation (0.99)
- (36 more...)
Abstract Physical and numerical models of Middle Bakken (MB) / Three Forks (TF) field development often assume that the Upper Bakken shale (UBS) and Lower Bakken shale (LBS), while intersected by hydraulic fractures, do not contribute hydrocarbons to production. As the basin matures and more data are collected, tangential evidence suggest that the shales contribute hydrocarbons. Little work has been done to understand Bakken shale-hosted hydrocarbons. This study aims to determine the producible hydrocarbon volume stored in the UBS and LBS across the US Williston basin. This study analyzed 296 core samples of the UBS and LBS from 14 wells across the Williston basin, spanning the full maturity range of the North Dakota portion of the basin and a variety of lithofacies. For bulk source rock geochemical properties, pre- and post-solvent extracted aliquots of all samples were analyzed to determine TOC (total organic carbon) and bulk composition with the HAWK-PAM (hydrocarbon analyzer with kinetics โ petroleum assessment method) instrument. A subset of samples from each location was solvent extracted, extracts were group-type separated to yield (saturates, aromatics, resins, asphaltenes), and each of these fractions were analyzed by HAWK-PAM for calibration. These data were integrated with MB and TF reservoired and produced oil geochemistry to calculate the volume of producible hydrocarbons stored in the shales. These data were incorporated into three semi-independent workflows to determine shale STOOIP (stock tank oil originally in place) across the basin based on: 1) geochemical quantification, 2) source rock expulsion/retention, and 3) petrophysical mapping. Produced oils from MB and TF wells are ubiquitously comprised of >95wt% S+A (saturates + aromatics). For the purpose of this study, 'producible' is therefore defined by the S+A fraction while resins and asphaltenes are considered not producible. Geochemical data indicate that petroleum stored in the pores of the shales have variable SARA composition, ranging from 50% S+A in low thermal maturity portions of the basin, to 97% S+A in higher maturity areas. The three approaches used in this study estimate that between 20% and 90% of the combined shale STOOIP (UBS + LBS) is producible. This shale-hosted oil represents significant volumes of oil that may not currently be considered in volumetric estimates of the BPS. Since each of the three methods carry unique assumptions there is variability in values between the three methods.
- North America > United States > Montana (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > North Dakota > Mountrail County (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.95)
- North America > United States > North Dakota > Parshall Field (0.99)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- (38 more...)
Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.98)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.90)
- (23 more...)
Oil and gas producers in the Permian Basin are revealing the extent of their losses from a historic winter storm that caused widespread power outages and wellhead freeze-offs across much of Texas and in other parts of the southern US last week. The figures come as companies begin to issue their fourth-quarter earnings and capital plans for the rest of the year. Analysts are struggling to pin down the exact toll of the storm on US oil production but suggest that between 2 and 4 million B/D were curtailed by the biggest weather-induced disruption to Permian oil fields. Occidental Petroleum, the Permian's second-largest oil producer, informed investors this week that about 25,000 BOE/D of production was shut in during the winter storm. After accounting for the lost production, the operator expects first quarter output in the Permian to be between 450,000 and 460,000 BOE/D.
- 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)
- (21 more...)
BHP Billiton lost billions during its foray into US shale, but that doesn't mean it has soured on oil and gas. Since the Melbourne-based firm announced in July the sales of its assets in the Permian Basin, Eagle Ford Shale, and Haynesville Shale, many have wondered if it would leave oil and gas altogether. But Skip York, BHP head of strategy and market intelligence, petroleum, assures that "BHP is still very bullish on the petroleum story as a natural resources company." That's because there will continue to be value in conventional assets driven by natural declines and the oil supply-demand imbalance, he explained. While demand may peak, its decline will be much slower than that of supply, which tends to take steep dives.
- North America > United States > Texas (0.90)
- Oceania > Australia > Western Australia > North West Shelf (0.15)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > Mexico Government (0.49)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > North West Shelf > North West Shelf Project (0.99)
- North America > Mexico > Gulf of Mexico > West Gulf Coast Tertiary Basin > Perdido Basin > Block AE-0093 > Triรณn Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 654 > Shenzi Field (0.94)
- (38 more...)
The latest move to consolidate the US shale sector came on 26 August as PDC Energy said it would acquire SRC Energy in an all-stock transaction valued at just over $1.7 billion in assets and assumed debt. The cash value of the deal is about $971 million and indicates that the offer is pegged at a 3.9% discount on SRC's last closing share price. The two Denver-based companies will form the second-largest oil and gas producer in Colorado's DJ Basin and adds to PDC's position in the Permian Basin. Land holdings in the DJ Basin will include about 182,000 "core" acres, with the newly acquired SRC share adding an estimated 10 years of inventory. PDC is taking on close to $685 million of SRC's debt.
- 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)
- (25 more...)
Abstract There is a very extensive amount of information and learnings from naturally fractured reservoirs (NFRs) around the world collected throughout several decades. This paper demonstrates how the information and learnings can be linked with tight and shale reservoirs (TSRs) with the objective of maximizing hydrocarbon recovery from TSRs. A classic definition indicates that a natural fracture is a macroscopic planar discontinuity that results from stresses that exceed the rupture strength of the rock (Stearns, 1982). Stearns' definition has been applied successfully for several decades. In this paper, the definition is extended to include not only macroscopic planar discontinuities but also planar and sinuous discontinuities that extend throughout different scales including micro and nano fractures. The paper demonstrates that, as in the case of the continuum that exists in process speed (the ratio of permeability and porosity, Aguilera, 2014), there is also a continuum of pore throat apertures of different sizes, natural fractures with different apertures, and Biot coefficients for different rocks. All of these directly or indirectly which affect reservoir performance. Actual observations in TSRs indicate that micro and nano natural fractures do not flow significant volumes of oil or gas toward horizontal wells. Thus, the wells must be hydraulically fractured in multiple stages to achieve commercial production. Once the wells are hydraulically fractured, the area exposed to the shale reservoir is enlarged and the natural micro and nano fractures flow hydrocarbons toward the hydraulic fracture, which in turn based on the values of hydraulic fracture permeability, feeds those hydrocarbons to the wellbore. In TSRs there are also completely cemented macroscopic fractures that are breakable by hydraulic fracturing and can become very effective conduits of hydrocarbons toward the wellbore. The link that exists between natural fractures at significantly different scales established in this paper is a valuable observation. This is so because the larger tectonic, regional and contractional (diagenetic) fractures that exist in NFRs have been studied extensively for several decades, for example in carbonates, sandstones, and basement rocks. Those learnings from NFRs have not been used to full potential in TSRs for maximizing oil and gas recoveries. This paper provides the necessary tools for remediating that situation. The established link between NFRs and TSRs permits determining how to drill and complete wells in TSRs. It is concluded that this link will lead to (1) improvements in gas production performance, and (2) maximizing economic oil rates and recoveries under primary, improved oil recovery (IOR) and enhanced oil recovery (EOR) production schemes.
- North America > United States > Texas (1.00)
- North America > United States > Oklahoma (1.00)
- North America > United States > Kansas (1.00)
- (9 more...)
- Research Report (0.45)
- Overview (0.45)
- Phanerozoic > Mesozoic (0.68)
- Phanerozoic > Paleozoic > Devonian (0.45)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- South America > Colombia > Middle Magdalena Basin > La Luna Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- (111 more...)
E&P Notes BP To Sell Alaska Business to Hilcorp BP has agreed to sell its entire business in Alaska to Hilcorp Alaska, based in Anchorage. Under the terms of the agreement, Hilcorp will purchase all of BPโs interests in the state for a total consideration of $5.6 billion. The sale will include BPโs entire upstream and midstream business in the state, including BP Exploration (Alaska) Inc., that owns all of BPโs upstream oil and gas interests in Alaska, and BP Pipelines (Alaska) Inc.โs interest in the Trans Alaska Pipeline System (TAPS). Bob Dudley, BP group chief executive, said in a press release, โAlaska has been instrumental in BPโs growth and success for well over half a century and our work there has helped shape the careers of many throughout the company. We are extraordinarily proud of the world-class business we have built, working along-side our partners and the state of Alaska, and the significant contributions it has made to Alaskaโs economy and Americaโs energy security. โข BHP, Anadarko Among Leaders in Latest US Gulf Lease Sale Australiaโs BHP Billiton and the recently acquired Anadarko Petroleum submitted the largest dollar totals of high bids in USโขGulf of Mexico Lease Sale 253. The yearโs second US gulf auction received 165 bids on 151 blocks from 27โขfirms, with high bids totaling $159.4โขmillion, the US Bureau of Ocean Energy Management (BOEM) announced in New Orleans on 21โขAugust. Those totals were mostly down from the last two gulf lease sales: Lease Sale 252 in March andโขLease Sale 251 in August 2018. โWhile we saw companies pick up acreage near remote areas, the infrastructure-rich Mississippi Canyon was the bid engine of the sale, capturing roughly 25% of total bids,โ said Michael Murphy, research analyst at consultancy Wood Mackenzie, in comments following the auction. โInfrastructure-led exploration continues to be a themeโ in US gulf lease sales, he noted. โข Eni Makes Big Gas, Condensate Discovery in Nigeria Eni reported a large gas and condensate discovery in the deep sequences of the Obiafu-Obrikom fields on the OML61 block onshore the Niger Delta. The Obiafu-41 Deep well reached a TD of 4374 m and encountered 130โขm of high-quality hydrocarbon-bearing sands within the deltaic sequence of Oligocene age. The find amounts to 1 Tcf of gas and 60 million bbl of associated condensate in the deep drilled sequences. Eni said the discovery has further potential that will be assessed in the next appraisal campaign. The well will immediately be brought on production and is expected to flow more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, theโขcompany said. โข The Shale Bankruptcies Continue The US upstream space may be more than 3 years removed from the apparent bottom of a generational oil-price slump, but the number of shale operators filing for Chapter 11 bankruptcy protection continues to grow. The latest two are Sanchez Energy and Halcรณn Resources, both based in Houston. For Halcรณn, it is the companyโs second time in 3 years.โข Sanchezโs voluntary filing on 11 August โfollows an extensive review of strategic alternatives to align its capital structure with the continued low-commodity-price environment,โ the company said in a news release. The Eagle Ford Shale producer will continue to operate as usual with an additional $175 million in newly committed financing, of which $25 million will be used to repay borrowings and replace a letter of credit. โข Equinor, YPF To Explore Block Offshore Argentina Equinor and Argentinaโs state-owned YPF will team to explore the 15000-sq-km CAN 100 offshore block in the North Argentina Basin. Under the agreement, YPF will transfer 50% of its interest in the block to Equinor, giving the companies an equal share. YPF acquired 100% of the block in May, at which point a 4-year exploratory period began. Equinor and YPF are already partners on the CAN 102 and CAN 114 blocks, also in the North Argentina Basin, awarded in April as part of Argentinaโs first open bid round for offshore acreage in more than 2 decades. Equinor gained seven blocks in the auction, including five asโขoperator.โข โข PDC Energy and SRC Energy Merge in Latest Shale Deal The latest move to consolidate the US shale sector came on 26 August as PDC Energy said it would acquire SRC Energy in an all-stock transaction valued at just over $1.7 billion in assets and assumed debt. The cash value of the deal is about $971โขmillion and indicates that the offer is pegged at a 3.9% discount on SRCโs lastโขclosing share price. The two Denver-based companies will form the second-largest oil and gas producer in Coloradoโs DJ Basin and adds to PDCโs position in the Permian Basin. Land holdings in the DJ Basin will include about 182,000 โcoreโ acres, with the newly acquired SRC share adding an estimated 10 years of inventory. PDC is taking on close to $685 million of SRCโs debt.
- North America > United States > Alaska (1.00)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Rivers State (0.88)
- Press Release (1.00)
- Financial News (1.00)
- Phanerozoic > Paleozoic > Permian (0.54)
- Phanerozoic > Cenozoic > Paleogene (0.34)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- (2 more...)
Saturation Isnโt What It Used to Be: Towards More Realistic Petroleum Fluid Saturations and Produced Fluid Compositions in Organic-Rich Unconventional Reservoirs
Pepper, Andrew (This is Petroleum Systems LLC) | Perry, Stephanie (Anadarko Petroleum Corporation) | Heister, Lara (Anadarko Petroleum Corporation)
Abstract Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production? Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations. Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume. Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place โ representing only the potentially mobile fluid phase petroleum โ means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US โ and global โ oil supply projections. Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- North America > United States > North Dakota (0.93)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.68)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.51)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
Abstract Petroleum produced from low permeability shales is different to the dispersed in-situ fluids from which it is derived. Whereas in-situ fluids consist of hydrocarbons, resins and asphaltenes in proportions governed by organic matter type, maturity and retention behaviour, the produced fluids are highly enriched in hydrocarbons and low polarity non-hydrocarbons, and show an enhanced GOR. Here, we study the effects of fractionation during production from Permian and Cretaceous shales using laboratory experiments, PVT-modeling and a regional PVT database. Our goal was to develop methodologies for predicting yields and compositions of produced fluids ahead of drilling. Target wells with known fluid properties were used for calibration. Shales from neighbouring wells of slightly lower maturity were mildly matured to that of the calibration well using MSSV pyrolysis, and a PhaseSnapShot of the resultant fluid made using PVTsim. The first example, from the late oil window Eagle Ford, demonstrates that both kerogen and bitumen are important petroleum precursors, and that in-situ compositions are largely determined by the most recently generated charge, rather than by cumulative addition during maturation. The PVT model, calibrated to the engineering report of the target well and its environs, reveals that a high proportion of the in-place C7+ fluids remain in the rock matrix relative to gas during production. The second example, taken from a gas and condensate fairway in the Permian Basin, shows that the predicted bulk composition of recently generated petroleum is facies dependent. PVT fluid calibrations have low Psat and low cricondentherms. These characteristics are reproduced by experiment, but only for those zones containing low contents of high molecular weight liquids. Any contributions to produced fluids from other zones is associated with massive retention of high molecular weight organics. The third example concerns volatile oil production from wells in the Permian Basin. The MSSV products generated by adjacent lower maturity shales exhibited phase envelopes with higher cricondentherms than that of the calibration, this being attributable to a molecular weight difference in heavy components. Adjusting the MW from 249 (measured) to 222 (produced oil PVT value) in the PVTsim model aligned the cricondentherms. This tuning step corresponds to the preferential retention of heavy polar compounds in the rock matrix during production. In a second step, 20% of the tuned MSSV-generated liquids are considered to be retained in the rock, thereby raising Psat. The result is an excellent match between the doubly tuned predicted phase envelope and that of the produced fluid. The preferential retention of polar compounds is also in line with this tuning step. In summary, fractionation is part and parcel of production from shales. Up to 80% liquids retention relative to gas has been demonstrated. Production efficiency assessments are readily inferred from these data. The extent to which fractionation occurs varies a lot, and has here been assessed by combining experimental rock geochemistry with PVT modeling (PhaseSnapShots), and using PVT reports on produced fluids for calibration.
- North America > United States > Texas (1.00)
- Europe > Norway > North Sea (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (51 more...)