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Collaborating Authors
West Virginia
Optimal Treatment and Reuse of Flowback and Produced Water: Selective Removal of Problematic Cations for Stability of Friction Reducers
Zhang, Yanze (University of Alberta) | Ali, Wajid (University of Alberta) | Jiang, Chunqing (Natural Resources Canada Geological Survey of Canada, Calgary) | Dehghanpour, Hassan (University of Alberta)
Abstract The oil and gas industry has been considering treatment and reuse of produced water for hydraulic fracturing of unconventional reservoirs to reduce environmental footprints and economic costs. In this paper, we studied the compatibility of Duvernay flowback and produced water (FPW) with anionic polyacrylamide-based friction reducer (FR) sample. Shear viscosity, particle size distribution, and viscoelasticity measurements were conducted to assess the performance of FR in both untreated and treated PW using Na2CO. The experimental results indicate that Ca and Mg are removed by up to 92.89% and almost 100%, respectively, at pH value of 11.5±0.10 and temperature of 80°C. The measured viscosity profile of FR in treated and untreated FPW are similar, suggesting that removing Ca, Mg, and Fe from FPW does not significantly increase the viscosity of slickwater. The viscoelastic properties of slickwater are found to be significantly increased when Ca concentration is decreased to 933.10 mg/L, and the size distribution of FR molecules become more uniform when the Ca and Mg concentrations are reduced to 1670.7 mg/L and <0.01 mg/L, respectively. Overall, a minimum Ca concentration of 1670.7 mg/L and Mg concentration of <0.01 mg/L are needed to prepare stable slickwater with Duvernay FPW. Introduction The extraction of oil from low-permeability reservoirs, such as shale and tight sandstones, poses significant challenges due to the restricted flow of oil and gas through the formation. Hydraulic fracturing, commonly known as "fracking" is a widely accepted technique in the petroleum industry that is used to improve the permeability and productivity of such reservoirs (Guo et al., 2022). The hydraulic fracturing process entails injecting a mixture of fluids at high pressure into the wellbore, including water, proppants, and various additives such as friction reducers, surfactant, and biocides. The proppants help maintain the fractures’ aperture, while the friction reducers and surfactant additives mitigate friction and biocide prevents bacterial growth that may clog the fractures (Barati & Liang, 2014).
- North America > United States (1.00)
- North America > Canada > Alberta (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- 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)
- (3 more...)
Linking Flowback Recovery to Completion Efficiency: Niobrara-DJ Basin Case Study
Moussa, Tamer (University of Alberta) | Barhaug, Jessica (Great Western Operating Company LLC.) | Witt, Darby (Cordax Evaluation Technologies INC.) | Hawkes, Robert (Cordax Evaluation Technologies INC.) | Dehghanpour, Hassan (University of Alberta)
Abstract Near wellbore complexity is a current topic of discussion among geoscience and engineering disciplines across North America. Asset teams are constantly investing money and resources into the variety of near- and far-field wellbore diagnostic techniques to ascertain completion efficiency. These range from high-cost microseismic for far-field fracture placement to higher risk technologies such as fiber optics, cameras, and production logging tools. These techniques are generally used for parameter constraints for rate-transient-analysis (RTA) that requires months (and sometimes years) of production after post-frac flowback. Therefore, in this study we utilize flowback water-oil-ratio (WOR) as a diagnostic tool to provide early-time feedback for completion-efficiency evaluation. We analyze flowback, post-flowback and completion-design data of 19 multi-fractured horizontal wells (MFHWs) completed in Niobrara and Codell formations that are classified into parent and child groups. Child wells are then sub-clustered into Zipper-1 and -2 completed with more and less intense completion strategy, respectively. First, we analyze the flowback rate and pressure profiles of the 19 wells to estimate initial pressure in the stimulated area around wellbore and validate it against the outcomes of diagnostic fracture injection test (DFIT). Second, we apply rate-normalized-pressure (RNP) diagnostic analysis to a) investigate flow regimes during flowback and post-flowback periods; and b) assess interference between parent and child wells. Third, we use WOR diagnostic plots to estimate ultimate load recovery (ULR) and calculate initial effective fracture volume as two indicators for completion efficiency. We also cross-check the estimated effective fracture volume with microseismic dimensions. Finally, we apply rate-decline analysis on oil production data to predict ultimate oil recovery (UQo), assuming a critical oil rate of 1 stbd, and use it as a third performance indicator to evaluate the completion-design efficiency of each group. Child wells show 32% more load recovery compared with the parent wells. However, the parent wells show 38% and 50% more 9-months cumulative oil production (Qo) and UQo, respectively. For both the parent and child wells, more than 50% of the predicted ULR is produced back within the first three months of production. Although the intense completion-design strategy for Zipper-1 wells led to 35% larger effective fracture volume compared to Zipper-2 wells, both groups show similar oil recovery performance. Generally, Niobrara wells show less load recovery and effective fracture volume compared to Codell wells in each completion group.
- North America > United States > Colorado (1.00)
- North America > United States > Texas (0.93)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Codell Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (42 more...)
ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (0.67)
- Research Report > New Finding (0.71)
- Research Report > Experimental Study (0.55)
- 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 > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (38 more...)
Abstract Various chemical additives have been recently proposed to enhance imbibition oil recovery from tight formations during the shut-in periods after hydraulic fracturing operations. Although, soaking experiments under laboratory conditions usually confirm the performance of such additives, their effects on oil regained permeability during the flowback process are poorly understood. This is mainly because measuring effective permeability of such low-permeability rocks is extremely challenging. We develop and apply a laboratory protocol mimicking leak-off, shut-in, and flowback processes to evaluate the effects of fracturing fluid additives on oil regained permeability. We modify the conventional coreflooding apparatus to measure oil effective permeability (ko) before and after the surfactant-imbibition experiments. Adjusting the system total compressibility allows quickly achieving steady-state conditions at multiple ultra-low flowrates. We apply the proposed technique on two tight plugs with and without initial water saturation (Swi), and observe pressure humps during the flowback process that can be explained mathematically using the fractional-flow theory. Spontaneous imbibition of the surfactant solution into the two oil-saturated plugs results in recovery of around 20% of the initial oil. For the plug with Swi = 0, ko is reduced from around 3 µD to 1 µD, indicating the adverse effect of water trapping over the favorable effects of interfacial tension reduction and wettability alteration by the surfactant. For the plug with Swi = 0.21, ko increases from 0.85 µD to 1.08 µD that can be explained by the combined effects of Swi reduction and wettability alteration, favorably shifting the oil relative permeability curve.
- North America > Canada > Alberta (0.68)
- North America > Canada > British Columbia (0.68)
- North America > United States > Texas (0.46)
- Phanerozoic > Paleozoic (0.67)
- Phanerozoic > Mesozoic (0.46)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.30)
- 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)
- (37 more...)
Wettability of Calcareous Shales from the East Duvernay Basin: The Role of Natural Fractures, Thermal Maturity, and Organic-Pore Connectivity
Xu, Shiyu (University of Alberta) | Yassin, Mahmood Reza (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Kolbeck, Christen (Outlier Resources Ltd.)
Abstract In this study, we conducted rock/fluid experiments to investigate wettability of calcareous shale plugs from a well drilled in the early oil-window (EOW) of East Duvernay. The wettability of EOW plugs was compared with that of highly-mature and quartz-rich plugs in the oil and gas windows (OGW) of the Duvernay Formation to investigate the effects of kerogen maturity and mineralogy on pore morphology and wettability of shales. We investigated the effects of organic-pore connectivity and fractures on wettability of the EOW plugs. By using CT scan images, we divided EOW plugs into highly-fractured (HF), slightly-fractured (SF), and non-fractured (NF) plugs. We used reservoir oil and brine and conducted comparative imbibition tests on the core plugs to investigate effects of fracture intensity on imbibition profiles. The core plugs were characterized by analyzing the results of tight-rock analysis (TRA), x-ray diffraction (XRD), and rock-eval pyrolysis. Compared with the quartz-rich OGW plugs, the EOW plugs are categorized as calcite-rich shale (calcareous shale) with high average calcite content of 60%. The EOW plugs are rich in organic matter (average total organic carbon (TOC) of 7.3 wt%) with significantly high value of Hydrogen Index (HI > 500). Surprisingly, the results of wettability tests show higher normalized imbibed volume of brine compared with that of oil, suggesting that the EOW plugs are preferentially water-wet. This trend is opposite to what we previously observed for the oil-wet OGW plugs with significantly high organic porosity, positively correlated to TOC content. We did not observe well-developed organic pores within organic matter of less-mature EOW plugs. We also observed that the normalized imbibed volume of oil is much higher in the HF and SF plugs compared with that in the NF plugs. The results suggest that the fractures enhance accessibility of isolated pores, leading to more connected pore network for oil imbibition. This observation suggests that fracture porosity plays a significant role in wetting behavior of the EOW plugs. The results show that the porosity measured by Boyle’s law helium-porosimetry using crushed EOW samples is significantly higher than their effective porosity. This is because crushing the samples enhances accessibility of isolated pores considered as ineffective porosity under intact conditions. Combined analyses of imbibition profiles and core images of the fractured plugs show that oil rapidly imbibes into the fracture system, and then gradually imbibes from fractures into rock matrix.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (18 more...)
Abstract In this paper, we analyze and simulate the production data before and after an extended shut-in period from a horizontal well completed in the Montney Formation. After flowback and early post-flowback production, the well was shut-in for 7 months due to facility completion. When the well was reopened, the hydrocarbon production rates increased significantly compared to the values before the shut-in. To investigate the reasons behind this enhancement, we simulated three-phase production rates and bottom-hole pressure using the actual reservoir geological model. To match the production data before the shut-in period, we had to account for the reduction in oil and gas relative permeabilities due to water blockage. This was done by using multipliers of interblock fluid-flow transmissibility near the matrix-fracture interface. We used these transmissibility multipliers as matching parameters, to achieve the match between measured and simulated production data. However, the best history match was achieved, when the values of transmissibility multipliers are increased by 6.5 times after the shut-in. This suggests a significant increase in oil and gas relative permeabilities due to reduction in water blockage near fracture-matrix interface during the extended shut-in period. Since the simulation model was not able to capture the imbibition process controlled by different driving forces, we used transmissibility multipliers to mimic this phenomenon and its corresponding effects on production rates. In addition, we performed sensitivity analyses to investigate the effects of shut-in on the well productivity and economic profitability in terms of net present value (NPV). The results show that for this well, a 6-month shut-in period is optimal for maximizing NPV and hydrocarbon production.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- (12 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Recent wettability studies indicate the dual-wet behavior of unconventional rocks that have hydrophobic pores within the organic matter with low wetting affinity to brine. In contrast, the hydrophilic pores bordered by inorganic minerals such as quartz, feldspar, calcite, and clays have strong wetting affinity to brine. The total pore network composed of hydrophobic and hydrophilic pores exhibits a dual-wet behavior. Conventional methods such as mercury injection capillary pressure (MICP) and nitrogen/CO2 sorption tests give the total pore size distribution (PSDtot), regardless of pore wettability. Modeling two- phase transport mechanisms in such dual-wet media requires separate characterization of hydrophobic (PSDHB) and hydrophilic (PSDHL) pore size distributions. We proposed a two-step experimental procedure for estimating PSDHB and PSDHL. In Step 1, we used reservoir brine and conducted co-current spontaneous imbibition (SI) tests on dry shale plugs from the Duvernay Formation. We considered the pore network of shale plugs as an idealized bundle of tortuous capillary tubes, and estimated PSDHL using imbibition transient analysis (ITA) proposed in a previous study. The Lucas-Washburn equation was combined with a fractal model to develop ITA. In Step 2, we immersed partly brine-saturated plugs from SI test (Step 1) in brine and increased the pressure incrementally (forced imbibition or drainage process). We used incremental brine saturation at each pressure and estimated PSDHB by the Young-Laplace (Y-L) equation. The results show that cumulative pore space filled by brine in spontaneous- and forced-imbibition tests under maximum pressure of 9,500 psig is more that 90% of pore volume (PV), while mercury in MICP test can fill less than 40% of PV under maximum pressure of 55,110 psig. Therefore, pore size distribution estimated by brine-imbibition tests is expected to be more representative compared with that estimated by MICP tests. The peak-pore throat size of hydrophobic pores (Dpeak-HB) estimated by forced imbibition of brine is in the range of 5.8-14.6 nm, consistent with the two-dimensional visualization of organic pores using scanning electron microscopy (SEM) analysis. The minimum values of pore-throat diameters detected in mercury- and brine-injection tests are 3.8 nm and 1.2 nm, respectively. Therefore, smaller pore throats can be characterized by brine-injection test at a significantly lower pressure (9,500 psig) compared with that by mercury-injection test (55,110 psig). The results show that a part of the pore network with pore throats smaller than 3.8 nm is not accessible for mercury. However, brine can be injected into this part of the pore network.
- North America > United States (1.00)
- North America > Canada > Alberta (0.88)
- Research Report > New Finding (0.87)
- Research Report > Experimental Study (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (18 more...)
Summary The water recovered from hydraulic‐fracturing operations (i.e., flowback water) is highly saline, and can be analyzed for reservoir characterization. Past studies measured ion‐concentration data during imbibition experiments to explain the production of saline flowback water. However, the reported laboratory data of ion concentration are approximately three orders of magnitude lower than those reported in the field. It has been hypothesized that the significant surface area created by hydraulic‐fracturing operations is one of the primary reasons for the highly saline flowback water. In this study, we investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water‐imbibition experiments. We conduct two sets of imbibition experiments at low‐temperature/low‐pressure (LT/LP) and high‐temperature and high‐pressure (HT/HP) conditions. We study the effects of rock surface area (As), temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing As and temperature both increase TIP. We use the flowback‐chemical data and the laboratory data of ion concentration to estimate the fracture surface area (Af) for two wells completed in the Horn River Basin (HRB), Canada. For both wells, the estimated Af values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×10 m) compared with those calculated from production and flowback rate‐transient analysis (RTA) (approximately 10 m). The proposed scaleup procedure can be used as an alternative approach for a quick estimation of Af using early-flowback chemical data.
- Asia (1.00)
- North America > United States > West Virginia (0.68)
- North America > Canada > British Columbia (0.48)
- (4 more...)
- Geology > Mineral > Silicate (0.93)
- Geology > Geological Subdiscipline (0.93)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.39)
- 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 > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (20 more...)
Abstract This paper presents a series of rock-fluid experiments to investigate 1) wettability of several core plugs from the Montney Formation and its correlations with other petrophysical properties such as pore-throat-radius size distribution, and 2) effects of wettability, salinity and microemulsion (ME) additive on imbibition oil recovery. First, we evaluate wettability by conducting spontaneous imbibition experiments using reservoir oil and brine (with salinity of 141,000 ppm) on six twin core plugs from the Montney Formation. In addition, we investigate the correlations between wettability and other petrophysical properties obtained from MICP data and tight-rock analyses. Second, we inject oil into brine-saturated core plugs to arrive at residual water saturation. Third, we perform soaking experiments on oil-saturated core plugs using fresh water, reservoir brine and ME system, and measure the volume of produced oil with respect to time. We observe faster and higher oil imbibition into the core plugs compared with brine imbibition, suggesting the strong affinity of the samples to oil. The normalized imbibed volume of oil (Io) is positively correlated to the volume fraction of small pores, represented by the tail part of MICP pore-throat-radius size distribution profiles. This suggests that the tight parts of the pore network are preferentially oil-wet and host reservoir oil under in-situ conditions. The results of soaking experiments show that imbibition oil recovery is positively correlated to the water-wet porosity measured by spontaneous brine imbibition into the dry core plugs. Imbibition of fresh water results in around 3% (of initial oil volume in place) higher oil recovery compared with that of brine imbibition, possibly due to osmotic potential. Soaking the oil-saturated core plugs in ME solution after brine or fresh soaking results in 1-2% incremental oil recovery. Soaking the oil-saturated core plugs immediately in ME solution results in faster oil recovery compared with the case when the plugs are first soaked in water and then in ME solution.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (11 more...)
Fracture Network Characterization by Analyzing Flowback Salts: Scale-Up of Experimental Data
Zolfaghari, Ashkan (University of Alberta) | Tang, Yingzhe (University of Alberta) | He, Jia (University of Alberta) | Dehghanpour, Hassan (University of Alberta) | Bearinger, Doug (Nexen Energy ULC) | Virues, Claudio (Nexen Energy ULC)
Abstract As observed in many shale-gas plays, the produced flowback water is highly saline and the salt concentration increases with time. Several past studies investigated water-rock interactions to interpret flowback chemical data, evaluate reservoir performance, and investigate the environmental impacts of fracturing operations. In this study, we measure the total ion produced (TIP) during flowback process for two wells completed in the Horn River Basin. We also conduct two sets of imbibition experiments to investigate the effects of water-rock surface area (As) and rock volume (Vs) on the TIP in laboratory. Furthermore, we compare the experimental correlations between As - TIP and Vs - TIP with the TIP measured in the field flowback water to estimate fracture surface area (AFrac) and invaded reservoir volume (IRV). In order to investigate the effect of As on the TIP, we conduct a series of imbibition experiments using shale samples of different As but similar Vs at constant temperature. The experiments are performed at T = 23, 45, and 65°C to investigate the temperature effect on the TIP. The experimental correlation between TIP and As at constant temperature is applied to estimate AFrac using field data of TIP. We further utilize AFrac - T correlation to extrapolate AFrac at reservoir temperature. In order to evaluate the estimated AFrac values we also calculate AFrac by rate-transient-analysis (RTA). In order to investigate the effect of Vs on the TIP, we conduct a series of imbibition experiments using shale samples of different Vs but similar As at constant temperature. Experimental results indicate that the TIP increases with both As and temperature. The calculated AFrac value at reservoir temperature is approximately 10m for both target wells. These results are in agreement with RTA calculation of AFrac values for both target wells (≈ 10m). Our estimated values of AFrac are also in agreement with the field data of water recovery. The well with higher estimated value of AFrac has lower water recovery in the field as opposed to the well with lower estimated value of AFrac and higher water recovery in the field. Additionally, the estimated IRV is approximately 10 - 10m for both target wells. Our estimated values of IRV are also in agreement with the field data of water recovery and experimental results of water uptake. The well with higher estimated value of IRV has higher water uptake during imbibition experiments and also higher leak-off rate in the field. In contrast, the well with lower estimated value of IRV has lower water uptake during imbibition experiments and also lower leak-off rate in the field.
- North America > United States > West Virginia (0.68)
- North America > Canada > British Columbia (0.48)
- North America > Canada > Alberta (0.47)
- North America > United States > Pennsylvania (0.46)
- Geology > Geological Subdiscipline (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.67)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.34)
- 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 > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (8 more...)