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- analytical solution (4)
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**Country**

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**Technology**

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Abstract Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). In this study, we present a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, we show that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements.

bottom-hole pressure, cartesian plot, convolution time, Drillstem Testing, drillstem/well testing, formation linear-flow, pore pressure, power-law behavior, pressure transient analysis, pressure transient testing, production rate, production stage 1, rate transient analysis, reservoir, shut-in data, square root, straight line, superposition plot, surface pressure, time plot, Upstream Oil & Gas, uta superposition plot

Oilfield Places:

- North America > United States > Texas > Permian Basin (0.98)
- North America > United States > New Mexico > Permian Basin (0.98)

SPE Disciplines:

Summary We propose an explicit analytical solution for 1D cocurrent (COC) spontaneous imbibition (SI) in which a core is exposed to water (inlet) and oil (outlet). The system is described using an advection-capillary diffusion transport equation combined with a pressure equation. By ignoring the capillary diffusion term in the transport equation, the analytical solution follows in terms of Buckley-Leverett (BL) saturation profiles. The capillary force appears in the pressure equation and determines the advective term of the transport equation. The time when the front reaches the outlet (critical time) is calculated and used for scaling. The solution is extended to after critical time (late time) by maintaining the BL profile inside the system, thus preserving continuity in recovery and spatial profiles. The solution is characterized by an effective total mobility and capillary pressure (incorporating the entire saturation functions), both constant at early time (before critical time). At late times, they change dynamically. The model states that the imbibition rate can increase, decrease, and stay constant with time based on a new mobility ratio being less than, more than, or equal to unity, respectively. The ratio also indicates effectiveness of oil displacement. The square root of time recovery is a special case only seen for a (very) favorable mobility ratio. The model predicts that COC imbibition scales with the square of length both at early and late times and that the solution can scale saturation functions. The analytical solution was compared against numerical simulations of the full system. The new mobility ratio reflected the evolution in COC recovery better than total recovery. The analytical solution showed a too-high imbibition rate at a favorable mobility ratio. The diffusion term is important then due to strong saturation gradients, and the resulting smoothened profile yields a lower imbibition rate from the pressure equation. The analytical solution showed a too-low imbibition rate at early times for unfavorable mobility ratio due to not accounting for rapid early countercurrent (COUC) production. The analytical solution predicted a too-high imbibition rate at late times because the BL profile does not capture the oil mobility restriction at the outlet at late times. The time of water reaching the outlet was underestimated by a factor ∼ 2 for strongly water-wet (SWW) simulations and ∼ 10 for mixed-wet (MW) simulations. Scaling recovery with length squared was exact for all times. Scaling recovery until water reaching the outlet demonstrated consistency across saturation functions and viscosities. The analytical solution could match literature experimental data and produce corresponding saturation functions. To our knowledge, previous analytical solutions have only considered infinite-acting systems (early time), assumed piston-like displacement (PLD) (uniform saturations on both sides of a saturation shock front) or are implicit, thus not providing more insight than numerical simulations.

analytical solution, boundary condition, capillary pressure, chemical flooding methods, couc production, enhanced recovery, february 2021, flow in porous media, Fluid Dynamics, imbibition rate, mobility ratio, numerical solution, Oil Viscosity, saturation, saturation function, Saturation profile, spontaneous imbibition, square root, Upstream Oil & Gas, viscosity, waterflooding

Country:

- Europe (1.00)
- North America > United States > Pennsylvania (0.45)

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)

Summary The objective of this study is to develop a new method that leads to diagnostic charts that quantify the pressure response between two interfering wells. Analytical linear flow models for single hydraulic fracture are used to develop a fracture hit model, which is next verified with a numerical model for validity. An analytical two‐fracture model is then developed to simulate flowing bottomhole pressure (BHP) of a shut‐in well, which interferes with the other well through a fracture hit, during well‐testing for a short‐term period. From the insight of two‐fracture analytical model, a dimensionless pressure scalar, which is proportional to square root of time, is proposed to summarize the interference level between two wells. Utilizing such proportionality between the defined dimensionless pressure scalar and square root of time, a diagnostic chart for quick assessment of the production interference level between wells is developed. Such diagnostic chart is also applied to interference caused by multifracture hits that a multistage fractured horizontal well with history match performed from the Eagle Ford formation is considered as a parent well for production interference quantification. A new identical horizontal well, which is just fractured but is not in production, is assumed parallel to the pre‐existing well. The result shows that when the percentage of fracture connection increases, the slope of dimensionless pressure scalar vs. square root of time increases proportionally to the percentage of fracture connection. Because the slope of dimensionless pressure scalar vs. square root of time is between 0 and 1, it can be used to quantify the well production interference level under different situations.

analytical model, BHP, complex reservoir, conductivity, december 2020, dimensionless pressure scalar, Drillstem Testing, drillstem/well testing, equation, flow in porous media, Fluid Dynamics, fracture, fracture half-length, fracture tip, hydraulic fracture conductivity, hydraulic fracturing, interference, linear trend line, Modeling & Simulation, multistage fracturing, numerical model, oil shale, production interference, reservoir permeability, shale gas, shale oil, square root, two-fracture model, Upstream Oil & Gas

Oilfield Places:

- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale (0.99)
- (10 more...)

SPE Disciplines:

Summary We propose an explicit analytical solution for 1D cocurrent (COC) spontaneous imbibition (SI) in which a core is exposed to water (inlet) and oil (outlet). The system is described using an advection-capillary diffusion transport equation combined with a pressure equation. By ignoring the capillary diffusion term in the transport equation, the analytical solution follows in terms of Buckley-Leverett (BL) saturation profiles. The capillary force appears in the pressure equation and determines the advective term of the transport equation. The time when the front reaches the outlet (critical time) is calculated and used for scaling. The solution is extended to after critical time (late time) by maintaining the BL profile inside the system, thus preserving continuity in recovery and spatial profiles. The solution is characterized by an effective total mobility and capillary pressure (incorporating the entire saturation functions), both constant at early time (before critical time). At late times, they change dynamically. The model states that the imbibition rate can increase, decrease, and stay constant with time based on a new mobility ratio being less than, more than, or equal to unity, respectively. The ratio also indicates effectiveness of oil displacement. The square root of time recovery is a special case only seen for a (very) favorable mobility ratio. The model predicts that COC imbibition scales with the square of length both at early and late times and that the solution can scale saturation functions. The analytical solution was compared against numerical simulations of the full system. The new mobility ratio reflected the evolution in COC recovery better than total recovery. The analytical solution showed a too-high imbibition rate at a favorable mobility ratio. The diffusion term is important then due to strong saturation gradients, and the resulting smoothened profile yields a lower imbibition rate from the pressure equation. The analytical solution showed a too-low imbibition rate at early times for unfavorable mobility ratio due to not accounting for rapid early countercurrent (COUC) production. The analytical solution predicted a too-high imbibition rate at late times because the BL profile does not capture the oil mobility restriction at the outlet at late times. The time of water reaching the outlet was underestimated by a factor ~2 for strongly water-wet (SWW) simulations and ~10 for mixed-wet (MW) simulations. Scaling recovery with length squared was exact for all times. Scaling recovery until water reaching the outlet demonstrated consistency across saturation functions and viscosities. The analytical solution could match literature experimental data and produce corresponding saturation functions. To our knowledge, previous analytical solutions have only considered infinite-acting systems (early time), assumed piston-like displacement (PLD) (uniform saturations on both sides of a saturation shock front) or are implicit, thus not providing more insight than numerical simulations.

analytical solution, boundary condition, capillary pressure, chemical flooding methods, coc si, couc production, enhanced recovery, flow in porous media, Fluid Dynamics, imbibition rate, mobility ratio, numerical solution, Oil Viscosity, saturation, saturation function, Saturation profile, spontaneous imbibition, square root, Upstream Oil & Gas, viscosity, waterflooding

Country:

- Europe (1.00)
- North America > United States > Pennsylvania (0.45)

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)

Wu, Lin (Shell China Exploration and Production Co. Ltd.) | Fair, Phillip S. (Shell International Exploration and Production) | Deinum, Geurt (Shell Kuwait Exploration And Production B.V) | Wu, Lei (Shell China Exploration and Production Co. Ltd.) | Wu, Min (PetroChina Southwest oil and gasfield company) | Wang, Xiaopeng (Shell China Exploration and Production Co. Ltd.) | Bai, Ge (Shell China Exploration and Production Co. Ltd.)

Like most ultra-tight unconventional gas fields, the shale field appraisal in Sichuan basin in China used production analysis and decline estimates for determining the Expected Ultimate Recovery (EUR) for the initial wells; However, the performance of some wells was significantly different from the behavior of North American plays where the production typically is dominated by square root of time behavior due to the large surface area of the fractures in the multiple-fractured horizontal wells (MFHW). Even the best well in the field, well A, appeared to be controlled by the boundary dominated flow (BDF) when industry accepted rate transient analysis was applied. Although this well was not drilled close to other MFHW, the time to reach the boundaries indicated higher than expected permeability near the well with poorer reservoir beyond these boundaries. Microseismic data indicated that the hydraulic fractures were not strong linear features; rather they appeared to be more complex and distributed in the area typically thought to be the stimulated reservoir volume (SRV). While core data indicated the presence of natural fractures, most were cemented up and initially thought not to be important. To reduce the uncertainty of the reservoir parameters, an integrated study employing Pressure Transient Analysis (PTA) and Rate Transient Analysis (RTA) was done. The premise of this method is that the time scales for these are not reductant; ergo, they are testing different portions of the reservoir. RTA will use long-term production data, and data are reliable after cleanup and stabilization >1000 hrs. PTA analysis uses shorter term transient data < 1000hrs and is vital to understanding completion parameters. Multiple pressure buildups were done, which not only constrained the fracture conductivity and skin, but also provided insight into how they evolve with production. A long pressure buildup (PBU) of approximately one month with bottom hole pressure gauges was done to understand the well performance. This data provided insight into why well A did not exhibit the dominant square root of time behavior that everyone expected. The PTA diagnostic plot for the buildup test in shows the transient response was dominated by pseudo-steady state inter-porosity flow (i.e. Warren and Root) from a double porosity model. By matching the buildup test response first with a MFHW including double porosity in the PTA model, the production data could be matched along with the buildup data in an infinite reservoir. The apparent boundary dominated flow is a result from the intrafracture interference through the high permeability portion of the double porosity system. The success from having a coherent model matching both PTA and RTA led to a new approach for estimating a range of EUR values incorporating uncertainties in the reservoir and completion parameters and the performance data. This approach is adapted for well spacing design as well. The workflow for estimating the range of uncertainty started with a spreadsheet containing the uncertainty on well, completion, and reservoir parameters. For a given set of parameters, the buildup data and the production data were matched with unconstrained parameters and then a production forecast was made for that scenario. For example, one might start the match assuming the fracture height is fully penetrating the reservoir; however, another scenario may assume the heights of the fractures are limited to a smaller fraction of the reservoir. Utilizing this methodology, the smaller fracture height provides a match with longer fracture half-length. The estimated double porosity parameters change as can the interpreted permeability. Other parameters looked at include reservoir properties (e.g. effective permeability, porosity, thickness, kv/kh), fracture half length, effective number of stages, reservoir model types (single layer, multiple layers), permeability degradation, etc. A nice outcome of this process is the comparison of how well each scenario matched the production and pressure transient data. Those that match reasonably well are certainly more plausible than those that cannot match at all.

boundary, buildup test, complex reservoir, diagnostic plot, Drillstem Testing, drillstem/well testing, flow in porous media, Fluid Dynamics, fracture, hydraulic fracture, hydraulic fracturing, information, Modeling & Simulation, natural fracture, pressure transient analysis, pressure transient testing, production data, production forecasting, reservoir, reservoir model, reservoir parameter, reservoir property, RTA Model, Scenario, shale gas, square root, structural complexity, time behavior, Upstream Oil & Gas, workflow

Country:

- North America > United States (0.94)
- Asia > China > Sichuan (0.71)

SPE Disciplines:

Summary Spontaneous imbibition is a capillary-dominated displacement process in which a nonwetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Decades of core-scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front with a rate that scales with the square root of time. The imbibition rate during early stages of spontaneous imbibition (the onset period) has been reported to deviate from the square-root-of-time behavior, although its effect on the imbibition process is not well-understood. Controlled-imbibition tests, presented in this paper, demonstrate that restricted wetting-phase flow during the onset period gives irregular saturation fronts and deviation from the square-root-of-time behavior. The deviation was caused by local variation in porosity and permeability or by a nonuniform wettability distribution, and was directly visualized or imaged by positron-emission tomography (PET). Without knowledge of local flow patterns, the development of irregular saturation fronts cannot be observed; hence, the effect cannot be accounted for, and the development of spontaneous imbibition might be erroneously interpreted as a core-scale wettability effect. Restricted wetting-phase flow at the inlet affects Darcy-scale wettability measurements, scaling, and modeling; our observations underline the need for a homogeneous wettability preference through the porous medium when performing laboratory spontaneous-imbibition measurements. Introduction Spontaneous imbibition is a process in which a nonwetting fluid is displaced from a porous material by the inflow of a more-wetting fluid, as a result of the pressure difference across the interface between two immiscible fluids (Morrow and Mason 2001). Spontaneous imbibition strongly affects waterflood oil recovery in fractured reservoirs and is widely studied. Correlation of laboratory core-scale production data to recovery on the reservoir scale has been investigated for several decades.

boundary condition, core plug, end face, enhanced recovery, experiment, f-lwpr, flow in porous media, Fluid Dynamics, nonuniform wettability, onset period, paperboard model, reservoir simulation, saturation front, scaling method, spontaneous imbibition, square root, Upstream Oil & Gas, viscous resistance, Washburn, waterflooding, wettability

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (0.88)

Abstract Estimating reservoir flow capacity is crucial for production estimation, hydraulic fracturing design and field development. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent and this can cast significant uncertainties in interpreting DFIT data. In addition, the established methods for analyzing DFIT data make two oversimplified assumptions: (1) Carter's leak-off and, (2) Constant fracture compliance (or stiffness) during fracture closure. However, both assumptions are violated during fracture closure and this is why G-function based models and subsequent related works can lead to an incorrect interpretation and are not capable of consistently fitting both before and after closure data coherently (Wang and Sharma 2017). Moreover, current after-closure analysis relies on classic well-test solutions with constant injection rate. In reality, a "constant injection rate" does not equal "constant leak-off rate into the formation", because over 90% of the injected fluid stays inside the fracture at the end of pumping, instead of leaking into formation. The variable leak-off rate clearly violates the constant rate boundary condition used in existing well-test solutions. In this study, we extend our previous work and derive time-convolution solutions to pressure transient behavior of a closing fracture with infinite and finite fracture conductivity. We show that G-function and the square root of time models are only special cases of our general solutions. In addition, we found that after-closure linear flow and bilinear flow analysis can only be used to infer pore pressure reliably, but fail to estimate other parameters correctly. Most importantly, we present a new approach to history match the entire duration of DFIT data to estimate formation flow capacity, even without knowing closure stress and the roughness properties of the fracture surface. Our approach adds tremendous value to DFIT interpretation and uncertainty analysis, especially in unconventional reservoirs where the absence of after-closure radial flow is the norm. Two representative field cases are also presented and discussed.

assumption, closure stress, compressibility, decline response, dfit data, Drillstem Testing, drillstem/well testing, flow in porous media, Fluid Dynamics, Formation Permeability, fracture, fracture stiffness, fracture-wellbore system stiffness, History Match, hydraulic fracturing, leak-off rate, normalized system stiffness, pore pressure, pressure drop, pressure transient analysis, pressure transient testing, Reservoir Characterization, reservoir geomechanics, square root, stiffness, system stiffness, time-convolution solution, Upstream Oil & Gas

SPE Disciplines:

The separation of scales in FWI/RFWI, is a separation in wavenumbers between "propagative velocity" (low wavenumbers) and "reflectivity" (high wavenumbers). It is a separation between a migration mode/scattering regime, and tomographic modes/propagative regimes. The kernels of the tomographic modes (diving-wave and reflectedwave tomography) and of the migration mode are all present in the sensitivity kernel of FWI/RFWI as "bananas", "rabbit-ears" and "swings", respectively. Nevertheless the corresponding wavenumbers obey to different laws: first Fresnel zone for the tomographic modes, instantaneous scattering wavenumbers for the migration mode. Thus, there is a gap in wavenumbers between propagative and scattering regimes, for a given central frequency of the seismic data. This gap can be exploited in a carefully tuned RFWI through a velocity/impedance (Vp/Ip) parameterization and proper smoothing/filtering of the Vp gradient.

Presentation Date: Tuesday, October 16, 2018

Start Time: 1:50:00 PM

Location: Poster Station 8

Presentation Type: Poster

annual meeting, central frequency, frequency, Fresnel zone, geophysics, instantaneous wavenumber, inversion, kernel, migration mode, regime, Reservoir Characterization, RFWI, seg international exposition, sensitivity kernel, separation, square root, tomography, Upstream Oil & Gas, Waveform Inversion, wavelength, wavenumber

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Abstract The objective of this work is to present an integrated methodology/workflow for optimizing lateral well spacing and fracture spacing for unconventional reservoirs based on multiple experience in Marcellus shale gas development. Optimal well plans and completion designs, based on geology and reservoir characterization, are key elements in developing economic projects. Well performance and reserves at a pad level can be improved thought coordinated efforts from multi-functional disciplines. Workflow incorporates data integration and main analysis to be performed from all involved disciplines. Main disciplines are geology, reservoir and production engineering, drilling and completions teams, decision and economic evaluation and cost assurance process. A full set of reservoir modeling, economic analysis tools are described in the document. Workflow is optimized with a loop, where main routine and non-routine surveillance is used mainly for interference analysis and further optimization on both spacing for the factory-style development. Reservoir simulation fed into two separate workflows. One is a single pad economic model and or DOE which incorporates decision analysis techniques. The other is a portfolio analysis with pads scheduled to fill a midstream capacity constraint through time. Both cases balance the increased capital costs against accelerated and increased production. The portfolio analysis tool is useful in understanding impacts of tighter well lateral and cluster spacing, particularly how they influenced capital costs over time. Additionally, results are compared with analog data and competitor analysis. Methodology was field tested. Workflow application demonstrates that optimum lateral well spacing and cluster spacing in dry gas core area would have a positive impact on EUR (estimated ultimate recovery) at a pad level. Also, pad drilling and Completion optimizations provide increased NPV (net present value) and incremental DPI (discount profit investment) ratio. The experience in lateral well and perf cluster spacing for shale dry gas for geometric completions is an example of how to manage uncertainty through cross-functional collaboration. Workflow can be used as inputs in pilot test for well spacing and as a process to justify surveillance needs using value of information techniques.

Artificial Intelligence, asset and portfolio management, completion design, complex reservoir, Directional Drilling, drilling operation, information technique, lateral well, main uncertainty, Modeling & Simulation, non-routine surveillance, numerical simulator, optimization, perf cluster spacing, Petroleum Engineer, portfolio analysis tool, production forecast, Reservoir Characterization, shale gas, square root, surveillance, Upstream Oil & Gas, value driver, water injection rate, well spacing, workflow

Country:

- North America > United States > West Virginia (0.34)
- North America > United States > Virginia (0.34)
- North America > United States > Pennsylvania (0.34)
- (3 more...)

Oilfield Places:

- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (4 more...)

SPE Disciplines:

Technology:

Abstract Reserve estimation is a subject of continuous importance in the petroleum industry; controlling field development related decisions and providing valuation of corporations. For unconventional reservoirs completed with multistage fracture stimulation treatments in horizontal wellbores, these completion treatments are apt to be complex in terms of fracture lengths and distances between fractures creating a composite flow regime characterized by a continuous change in the proportional contribution from the reservoir experiencing of infinite acting linear flow and boundary dominated flow. A unified approach is presented that integrates well performance analysis of the linear flow and combination of linear and boundary dominated flow, dubbed complex fracture depletion. The approach relies on the linear flow derivative. Linear flow exhibits a straight line when cumulative production is plotted versus the square root of produced time and the derivative, the change in cumulative production with respect to the square root of produced time, is a constant. At the onset of partial boundary flow the linear derivative decreases and can be fitted with an exponential straight line. The time that identifies this juncture becomes the only variable of regression analysis. A consequence of utilizing an exponential fit of the linear flow derivative is a continuous reduction in the Arps' "b" exponent at the onset of partial boundary flow from a "b" value of two during linear flow. Other decline curve analysis methods that result in declining "b" exponents and constant "b" values are discussed. Well production performance from the Bone Springs formation located in Lea and Eddy counties, New Mexico, concentrating on completions between 2010 and 2015 are selected for presentation in this study. The applicability of the approach is further validated with examples from other major shale/tight reservoirs. Linear Flow and its Derivative Shown in Fig. 1 are the cumulative oil production, Np, on the primary y axis and the linear flow derivative, dNp/dt, on the secondary y axis with a logarithmic scale. Early on, the derivative displays a horizontal line (which is the straight line portion of the cumulative production versus the square root of produced time - linear flow) and then becomes an exponential straight line displayed on Fig. 1 leading to rate and cumulative production equations 1 & 2 for the Complex Fracture Depletion model. (equation)(1) (equation)(2)

Arp, Artificial Intelligence, boundary, complex fracture depletion, complex fracture depletion model, complex reservoir, Drillstem Testing, drillstem/well testing, exponent, exponential straight line, fracture depletion, hydraulic fracturing, linear flow, partial boundary flow, production control, production monitoring, Reserve Estimation, reserves evaluation, Reservoir Surveillance, selection, square root, stretch exponential, unified production analysis, Upstream Oil & Gas

Country:

- North America > United States > Texas (1.00)
- North America > United States > New Mexico > Eddy County (0.34)

Oilfield Places:

- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Bone Spring Formation (0.99)
- (5 more...)

SPE Disciplines:

Thank you!