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Collaborating Authors
Results
Integrating Fracture Mapping Technologies To Improve Stimulations in the Barnett Shale
Fisher, Marc Kevin (Pinnacle Technologies) | Wright, Christopher A. (Pinnacle Technologies) | Davidson, Brian Michael (Pinnacle Technologies) | Steinsberger, Nicholas P. (Republic Energy) | Buckler, William Stanley (Quicksilver Resources Inc.) | Goodwin, Alan (Devon Energy Group) | Fielder, Eugene O. (Devon Energy Production Co. LP)
Summary A large hydraulic-fracture diagnostic project was undertaken in the summer of 2001 that integrated fracture-diagnostic technologies, including tiltmeter (i.e., surface and downhole) and microseismic mapping. The extensive data gathered resulted in a much clearer understanding of the highly complex fracture behavior in the Barnett shale of north Texas. The detailed fracture-mapping results allowed construction of a calibrated 3D fracture simulator that better reflects the observed mechanics of fracturing in this fractured-shale reservoir. More than just simple calibration was required. Indeed, a whole new understanding of fracture growth was developed. The Barnett shale has seen a rebirth of drilling and refracturing activity in recent years because of the success of water fracture, or "light-sand," fracturing treatments. This extremely low-permeability reservoir benefits from fracture treatments that establish long and wide fracture "fairways," which result in connecting very large surface areas of the formation with an extremely complex fracture network. Understanding the created-fracture geometry is key to the effectiveness of any stimulation program or infill-drilling program, particularly in this area, with its nonclassical fracture networks. Integrated-fracture diagnostics have led to the identification of new fracturing techniques, as well as additional refracturing and infill-drilling candidates. A new method for evaluating large microseismic data sets was developed. Combining the microseismic analysis with surface- and downhole-tilt fracture mapping allowed characterization of the created-fracture networks. Correlations between production response and various fracture parameters will be presented along with a discussion of methods for calibrating a fracture model to the observed fracture behavior. Barnett Basics The Mississippian-age Barnett shale is a marine shelf deposit that unconformably lies on the Ordovician-age Viola limestone/Ellenburger group and is conformably overlain by the Pennsylvanian-age Marble Falls limestone. The Barnett shale within the Fort Worth basin ranges from 200 to 800 ft in thickness and is approximately 500 ft thick in the core area of the field. The productive formation is typically described as a black, organic-rich shale composed of fine-grained, nonsiliciclastic rocks with extremely low permeability, ranging from .00007 to .005 md. The formation is abnormally pressured, and hydraulic-fracture treatments are necessary for commercial production because of the low permeability. The first decade of Barnett shale stimulation treatments was dominated by massive hydraulic-fracture treatments (more than one million lbm of proppant carried by highly viscous gel systems). Production was variable, with wells producing up to 1 Bcf estimated ultimate recovery. In 1997, Devon Energy (formerly Mitchell Energy) began experimenting with waterfractures, or light-sand, fracturing treatments, which were at the time, being successfully applied in the Cotton Valley sandstone—a tight gas reservoir approximately 100+ miles to the east of the Fort Worth basin.1 The waterfractures were successfully reintroduced into the Cotton Valley because of the then-current lack of commercial viability for large, expensive cross-linked fracture treatments in that reservoir. Devon believed that similar success would be achieved in the Barnett shale with large-volume slickwater treatments and subsequently experimented with several versions of these treatments before evolving to the current design. Today, depending on the location within the Barnett, viability of limestone barriers surrounding the Barnett intervals, and net-pay thickness, a "typical" Barnett treatment may consist of 750,000 gal of slickwater and 80,000 lbm of proppant pumped at 60 bpm, with proppant concentrations averaging 0.1 to 0.5 ppg throughout the treatment. The lack of gel solids in the fracturing fluid is believed to contribute to longer, more complex fractures and additionally, leave no gel residue or filter cake behind that may damage the fracture conductivity in these treatments. Because of the low-permeability nature of the reservoir, it is imperative that extremely large fracture-surface areas are created by the fracture treatments. The use of light-sand, or waterfracture, treatments has considerably improved both the production performance and the economics in this reservoir. Because of its extremely low permeability, the drainage distance from the fracture face is very small. Introduction The classical description of a hydraulic fracture is a single biwing planar crack with the wellbore at the center of the two wings. However, almost all physical fracture verifications performed to date, from corethroughs to minebacks, have proved this description to be oversimplified. Therefore, fracture-mapping technologies can provide insight into reservoir-depletion dynamics and significantly help optimize reservoir management. Fractures can be categorized as simple (the classical description), complex, or very complex. An illustration of how these fractures may look is found in Fig. 1. Because of several factors, including the presence of natural fractures, a fracture treatment in the Barnett is more likely to look like the "very complex" fracture description than the "simple" case. This allows a fracture fairway to be created during a treatment with many fractures in multiple orientations, resulting in large surface areas potentially contributing to production. Numerous treatments have been mapped in the Barnett to gain a better understanding of how these fractures propagate.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Summary In recent years, there have been numerous advances in fracture mapping/diagnostic technologies. This paper details the state of the art technologies in applying both conventional and advanced methods to better understand hydraulic fracturing and improve treatment designs. The initial portion of the paper describes the application and limitations of various diagnostic tools and methods, including well testing, net pressure analysis (fracture modeling), techniques that employ open- and cased-hole logs, surface- and downhole-tilt fracture mapping, microseismic fracture mapping, and production-data analysis. The bulk of the paper is dedicated to case histories that illustrate the application of these fracture-diagnostic technologies. The case histories include examples of how several fracture diagnostics can be used in concert to provide more reliable estimates of fracture dimensions and allow better economic decisions. Introduction The process of hydraulic fracturing has always had a "black box" image. This has been partly because knowledge about fracture geometry is difficult to obtain, with fractures growing thousands of feet below the surface, and partly because fracturing is proving to be vastly more complex than initially thought. While hydraulic fracture treatments continue to be designed with the best tools and techniques available, geometry estimates from fracture models have been difficult to verify. Numerous fracture-diagnostic techniques have been developed to fill this knowledge gap, improving our understanding of hydraulic-fracture behavior. The main purpose of fracture diagnostics is to help the producer optimize field development and well economics. This can include optimizing individual fracture treatments to obtain the most economic design and optimum interval/height coverage or optimizing the entire field development in terms of well spacing and location. Fracture diagnostics can be beneficial in numerous stimulation settings. Settings range from propped-fracture stimulation of a new pay zone in a newly developed field to infill-drilling development, and from field development with hydraulically fractured horizontal wells to the evaluation of fracturing during steamflooding or waterflooding. When executing fracturing operations in one of these settings, several questions can be answered in the design/evaluation process using fracture diagnostics, including:Do fractures effectively cover the pay zone? Are fractures confined to the pay zone? Does the fracture grow into an unwanted gas- or waterbearing zone? What is the optimum number of fracture-treatment stages and the best treatment size to cover thick pay zones? How much more length/height/production is obtained if treatment size is increased? Is the final fracture conductivity sufficient to achieve the desired production? What is the optimum proppant? Is the hydraulic fracture oriented in the same direction as the primary set of natural fractures? What direction should a horizontal well be drilled to complete it with transverse (or longitudinal), multistage fracture treatments? Is the well pattern appropriate to maximize sweep efficiency in steam/waterflood areas? Do the injected waste and drill cuttings remain within the selected zone? Numerous fracture diagnostics are available (see Fig. 1), including techniques that directly image "big picture" far-field fracture growth, dimensions, and orientation; tools that provide a local measurement of the fracture at the wellbore; and lower-cost, indirect (model-dependent) diagnostic methods. There are three main groups of commercially available fracture-diagnostic techniques, each with its own set of capabilities and limitations. A summary of the techniques, limitations, and the parameters each technique measures is provided in Table 1. Group 1-Direct Far-Field Fracture Diagnostic Techniques. This group currently comprises two relatively new types of fracture diagnostics - tiltmeter and microseismic fracture mapping. These diagnostics are conducted from offset wellbores and/or from the Earth's surface during the fracture treatment and provide information about "big picture" far-field fracture growth. A limitation of these techniques is that they map the total extent of hydraulic- fracture growth but provide no information about the effective propped-fracture length or conductivity. The resolution of these techniques decreases with increasing distance from the fracture (see Table 1 for details). Surface- and Downhole-Tilt Fracture Mapping. The principle of tiltmeter fracture mapping is quite simple (see Fig. 2). A created hydraulic fracture results in a characteristic deformation pattern of the rock surrounding the fracture. By measuring the hydraulic-fracture-induced tilt (deformation) of the Earth at several locations (surface and/or downhole) with extremely accurate "carpenter's levels," the fracture orientation (with surface tiltmeters) and geometry (with downhole tiltmeters) can be obtained. Surface tiltmeters are deployed in shallow holes (20 to 40 ft deep) at radial distances from as close as a few hundred feet to as far as 1 mile around the injection well, depending on the depth of the treatment zone and the expected fracture dimensions. The array of surface tiltmeters measures the gradient of the displacement and provides a map of the deformation of the Earth's surface above the fracture. Analysis of this tilt field provides a measurement of the fracture azimuth, dip, depth-to-fracture center, and total fracture volume. Because surface tiltmeters are typically very far from the created fracture, they cannot precisely resolve fracture length and height. Downhole tiltmeter mapping is based on the same concept as surface tiltmeter mapping, but instead of being at the surface, the tiltmeters are positioned by wireline in one or more offset wellbores at the depth of the hydraulic fracture. Downhole tiltmeters provide a map of the deformation of the Earth adjacent to the hydraulic fracture. In most applications, downhole tiltmeters can be placed much closer to the fracture than surface tiltmeters and are, therefore, significantly more sensitive to fracture dimensions. The measured tilt is used to determine fracture height, length, and width vs. time.
- North America > United States > Texas (1.00)
- North America > United States > California (0.94)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- 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)
- (27 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- (2 more...)
Summary The most comprehensive hydraulic-fracturing data including the first objective measurements of fracture height, length, and width are acquired from the Gas Research Inst. (GRI)/Dept. of Energy (DOE) Multiwell Site (M-Site) tests. In spite of the availability of extensive and reliable fracturing data, significant deviation between predicted and microseismic-determined fracture geometry was reported. The purpose of this study is to provide a consistent analysis of B-sand experiments by applying a systematic methodology for fracture-treatment evaluation. For this analysis, fracture parameters are estimated initially from laboratory data, well logs, and calibration tests. These parameters are refined by matching simulated pressures to field-measured fracturing pressures recorded during the first linear gel injection. These fracture parameters then are used to compare predicted- and measured-fracture pressures on all subsequent injections. Although general agreement for the fracturing pressures was obtained, a discrepancy was noticed between zone stresses estimated by evaluation and their variation as indicated on published stress logs. Stress data were reinterpreted and an acceptable pressure match was established. Fracture parameters resulting from this study are in agreement with independently inferred estimates. In addition, an apparent difference between closure pressure and microfrac stress is resolved. Finally, good agreement between predicted fracture geometry and microseismic readings is observed for each injection test considered in this study. This study shows that fracture pressures and geometry can be predicted consistently with good accuracy using elementary analysis techniques, without a reliance on ad hoc physical explanations. Background Over the past decade, a series of hydraulic-fracturing experiments, jointly conducted by the GRI and DOE at the M-Site, has provided the most comprehensive data available for hydraulic-fracture treatments. The initial objective of these experiments was to establish the character of gas production from lenticular, low-permeability formations common in the western United States. Through the course of the experiments, the focus has evolved toward developing methodologies to increase the accuracy for measurement of field-scale hydraulic fractures. The primary effort in this direction has been the successful use of subsurface triaxial accelerometers to locate microseismic events along the extent of a propagating hydraulic fracture. This objective measure of fracture dimensions and other supporting fracturing data provide critical constraint for evaluating fracture models and thus provide an excellent example for comprehensive fracture evaluation. In spite of the availability of such exhaustive and reliable fracturing data, widely used fracture simulators failed to explain comprehensively the observed fracture response for this important data set. This discrepancy for B-sand experiments was reported when using both cell-based and lumped fracture simulators. Although net pressures were matched for calibration treatments, disagreement was noticed between the simulated fracture geometry and the geometry outlined by microseismic measurements. Disparity in fracture geometry was particularly pronounced on propped treatment for which not even a satisfactory net pressure match was achieved. An undesirable feature of this lenticular formation is the complex geological environment that is prone to inefficient hydraulic fracturing. Nolte discussed a comprehensive list of factors responsible for abnormal fracture behavior. A majority of these characteristics are applicable to the in-situ conditions at the M-Site, leading to its classification as the "worst-case scenario." Indeed, evaluation of prior tests at this site using both fracture simulations and far-field core samples refer to these complexities to explain differences between expected and observed behavior. The effect of such complexities can be assessed using a factor, Fc, defined asEquation 1 where ?pw=net pressure at the wellbore and seV=effective vertical stress. A low value of Fc is desirable for successful fracture placement. Applying Eq. 1 to the B-sand tests predicted an Fc value of 0.48. A reservoir pressure of 1,950 psi inferred on prior GRI experiments was used and an overburden stress based on a gradient of 1.07 psi/ft at 4,530 ft was assumed. The value of ?pw is based on bottomhole fracturing pressure of 4,800 psi recorded at the end of injection during propped treatment and closure pressure of 3,500 psi (estimated later in this paper). Although still higher than the suggested threshold value of Fc˜0.35 for the beginning of complex behavior in homogeneous reservoirs, this estimate is significantly lower than an Fc value of 1.02 encountered during fracture tests in the lower Paludal interval at this site. A lower Fc value suggests the likelihood of less complicated behavior that is amenable to routine fracture evaluation. This paper presents an evaluation study of the B-sand fracture experiments. Although these tests sought to address numerous other issues, such as proppant encapsulation and fracture conductivity, this analysis focuses on comparing simulator-predicted fracturing pressures and geometry with field measurements. Table 1 lists six injection tests performed during B-sand experiments. However, fluid was flowed back at the end of the first three KCl injections. Because shut-in pressures are essential for assessing fracture behavior, only pumping pressures are considered during these injections. Comprehensive evaluation, however, was performed for linear gel tests and propped treatment listed in Table 1. The fracture simulator used to evaluate these experiments is described in Appendix A. The first linear gel injection in the B-sand is analyzed initially using a systematic evaluation methodology to determine fracture parameters. Fracturing pressures predicted using these parameter estimates then are compared with field measurements on subsequent injections. Simulated geometries are compared with microseismic measurements in each case. The paper finally reconciles discrepancies between independent assessments of these experiments and results arrived at in this study. Primary results are provided in the main body of the paper and additional details are given in the appendices.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Summary Evidence suggests that certain vibrations, generated either by natural seismic events or by artificial explosions, have altered the production behavior of oil wells at distances as much as 200 km from the epicenter. These changes have affected the produced water/oil ratio: the water production rate increased from a formation that was at approximately the interstitial water saturation, while the oil rate increased in watered-out reservoirs that were near the residual oil saturation. Theoretical and field investigations of the phenomena suggest that vibrations may influence substantially the water or oil relative permeability that appears to be partially reconstituted at saturations that ordinarily would prohibit the flow of a particular phase. The key role is played by ultrasound oscillations, generated by seismic waves within the stratum, and it has been confirmed by in-situ measurements during the vibrostimulation of reservoirs. This paper provides an interpretation of the process and describes wave requirements, wave generation, and propagation in oil-bearing porous media supported by laboratory experiments and field cases of vibrostimulation of oil production from water-flooded reservoirs. Introduction Although stimulation, as practiced today, may increase well productivity, it has limited potential for enhanced oil recovery. The amount of oil reserves within the radius of influence, if anything, may decrease because of water intrusion from water-flooding or from water influx from adjoining aquifers. In particular, the latter would be the case for hydraulic fracturing, where undesirable fracture height migration may result in rapid water influx. Often, hydraulic fracturing is justified only by the acceleration of oil recovery (net present value, NPV). The ultimate oil recovery may be less than that from an unfractured well. Recently, the notion was introduced that vibrations can be used successfully in oil recovery. This paper describes this novel idea and how it can be applied to oil reservoirs. Particular emphasis will be given to water-flooded fields. Displacement of oil droplets in water-saturated porous media was studied in the laboratory under simultaneous gravitational and vibration action. These experiments were based on the idea that vibrations could accelerate oil and gas separation in developed reservoirs at the macroscale level. It was found that high amplitudes of vibrations were needed. However, generating such high amplitude vibrations in situ is quite unrealistic because they can occur only in the case of earthquakes or high-impact explosions and only for short periods of time. It has also been observed that during standard acoustic well logging, oil production increased in certain cases. In these occasions, ultrasound frequencies were used. It was evident that these treatments were cleaning the near-well zone. Near-wellbore ultrasound treatments using in-situ devices is a relatively well-known operation with several inventions already presented. However, ultrasound vibrations, generated at the well bottomhole, cannot penetrate porous rocks deeper than 1 m, and frequently, only a few centimeters. A possibility to generate vibrations at an oil-producing layer is to put a bell-shape generator in the well that uses the energy of fluid flow. The method was developed and used in Siberia. Even though the use of mechanically or electrically generated sound is possible, the energy level is limited by the size of the well cross section. Again, this restriction implies that vibrations at the bottom of a vertical borehole can change the fluid phases in the porous medium only in the near-well zone. Thus, such methods of generating vibrations for reservoir stimulation, although potentially useful, cannot influence a large radius in the reservoir. Studies of wave propagation in porous or fractured rocks revealed certain unusual features that cannot be explained by conventional linear elastic or viscoelastic theories. In field experiments, it has been shown that fluid-bearing sands can change the frequencies of seismic waves. The energy of seismic waves converts to the energy of dominant frequency waves. This dominant frequency depends on the size and the compactness of grains and the fluid saturation. The dominant frequency is independent of the source of energy and the spectrum of frequencies emanating at the source. In a series of experiments, sands were saturated with water from 0% to 100% of the pore space. These experiments were the key in understanding that the observed seismic waves under partial saturation of sands correspond to Frenkel-Biot longitudinal waves of the second type. Therefore, the dominant frequency wave characterizes the slow-moving wave, and the ultrasound waves characterize the fast-moving wave. For sands, the dominant frequency has been found to be 25 Hz, for clays 40 Hz, for gravels 10Hz, and for eroded granites 100 Hz. If this frequency coincides with the stratification resonance frequency, such oscillations last considerably longer. It is also clear that seismic noise can be generated in rock masses deformed by solid tides and other tectonic or technogenous events. In addition, vibrator signals can be observed definitely at very large distances. To ascertain the technology, special field experiments were conducted in which vibrators were placed at the ground surface above the reservoirs. Refs. 3, 15, 16, and 17 summarize the results and interpretation of these field tests. An abbreviated form of this interpretation follows. Early Field Experiments The first test was to study the influence of earthquakes on oil wells at distances of 70 to 200 km from the earthquake epicenters.Fig. 1 shows changes of oil and water production of two wells during the earthquake episodes. The top illustration shows clearly that an earthquake swarm can decrease the water/oil ratio (WOR) if the WOR had an initially large value. The bottom illustration shows that the WOR can increase if it was very small initially. These were limiting observations. In other wells with intermediate WOR values, the results were inconclusive. However, the changes in the WOR were unmistakable in the extreme cases of the WOR range, as shown in Fig. 1. The second test was a field vibration test. This test was conducted at the Abuzy reservoir in the Krasnodar region of the North Caucasus. The reservoir is a sandstone at 1400 m depth and has been developed since 1938, mostly under waterflood. A seismic vibrator was used with an active weight of 20 tons. The total well production from each well was 2 to 3 tons/d [16 to 24 bbl/D]. Producing WOR was high (Table 1). In this test, vibrations were continuous for 20 min/hr, and the interval of operations was 15 to 20 hr/D. The test lasted for 37 days, and the increased producing WOR was maintained for 17 days after the operation.
- Geophysics > Seismic Surveying > Passive Seismic Surveying (0.48)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract A hydraulic fracture stimulation conducted during 1983–1984 in non-marine, deltaic, Mesaverde strataat a depth of 7100 ft (2164 m) was cored in a deviated well in 1990. The observed fracture consists of two fracture intervals, both containing multiple fracture strands (30 and 8, respectively).while the core had separated across many of the fracture strands during coring, the rock remained intact across 20 of the strands, preserving materials within the fractures. Nine of the remaining intact strands were split open, revealing abundant gel residue on the surfaces of every fracture examined. Of 7 strands associated with major bedding planes, 4 displayed offsets of 1–3 mmat the planes and 3 strands had their growth terminated at the planes, showing the importance of bedding (petrophysical heterogeneities) on fracture propagation. Implications of all these findings for propagation. Implications of all these findings for hydraulic fracture design and analysis are also addressed. Introduction One of the principal hindrances to an accurate description of the hydraulic fracturing process has been the inaccessibility of the created fracture. As a result, the conventional view of a hydraulic fracture has been driven primarily by the idealized version developed by modelers to predict fracture geometry and behavior. Only a few mineback experiments, occasional TV logs, lab tests, and inferences from diagnostics have provided amore realistic view of the hydraulic fracturing process. process. Current fracture models assume that the fracture is a single plane with fluid frictional effects proportional to the fluid resistance in smooth proportional to the fluid resistance in smooth parallel plates or ellipses. Variable-width parallel plates or ellipses. Variable-width cross sections are typically handled by integrating one of the simple fluid resistance laws across the cross-sectional area. This procedure yields small pressure drops throughout the majority of the crack, particularly when large tip pressure drops are introduced. The effects of more complex fracture behavior, such as multiple strands, offsets, and waviness are seldom considered in the modeling process, although they have been used to interpret field results. One reason for ignoring complex fracturing is the difficulty in determining the size of the effect; a second reason is the lack of field data (other than shallow minebacks) to support such behavior. This simplistic, model-driven paradigm for hydraulic fracturing has biased our view of many other aspects of the process as well. Height growth, for example is treated as an elastic process, involving equilibrium models, time-constant approximations, or fully 3-D finite element models. Little attention has been given to the inefficiencies of fracture growth across bedding and non-elastic behavior, factors which may be as important as the easily analyzable elastic components. Fluid rheology, leakoff and damage are generally considered to be known quantities, based on laboratory data taken at conditions that seldomresemble the in situ state. Of particular significance is the neglect given to gel residues, which can cause conductivity damage to the hydraulic fracture and to the natural fractures which are intercepted. P. 597
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.34)
- Geophysics > Seismic Surveying > Passive Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.67)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > California > San Joaquin Basin > Lost Hills Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.89)
- (3 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (7 more...)