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Results
Impact of Trapping of Residual Oil by Mobile Water on Recovery Performance in Miscible Enhanced Oil Recovery Processes
Rampersad, P.R. (New Mexico Institute of Mining & Technology, Socorro) | Ogbe, D.O. (University of Alaska Fairbanks) | Kamath, V.A. (University of Alaska Fairbanks) | Islam, R. (South Dakota School of Mines & Technology, Rapid City, U.S.A.)
Abstract In this paper we examine how residual oil trapping by mobile water affects the recovery performance of miscible EOR processes. The objectives of the study are (1) to develop a multiphase, numerical model to investigate factors affecting water-blocking and the release of oil from dendritic states; (2) to evaluate performance of miscible processes and forecast displacement efficiency and recovery under a variety of operating conditions, and (3) to determine the "optimum" water-solvent ratio to be used in a miscible Water-Alternate-Gas (WAG) process. Using the multiphase flow model, we considered the oleic phase as two parts, a mobile phase and a trapped phase, and studied the effects of capillary forces, solvent viscosity, fraction of trapped oil, dispersion and mass transfer coefficients on recovery performance. Guidelines for determining the optimum water-solvent ratio to be used in a miscible WAG process are discussed. Introduction Miscible flooding is the injection of a quantity of solvent to contact and displace the reservoir oil. The two fluids mix together in all proportions and remain as a single phase. Miscible processes have been widely used to enhance oil recovery. The major drawback of miscible processes is viscous instability. These instabilities are the result of highly adverse mobility ratios between the oil-in-place and the displacing solvent. Water-Alternate-Solvent injection (and/or Water-Solvent co-injection) has been advocated as one way to reduce the mobility of injected solvents in miscible displacement processes. It is known that water-solvent injection reduces the severity of viscous fingering and increases sweep efficiency. However, any benefits associated with water-solvent injection must be weighed against possible detrimental effects, which arise as a result of high water saturations. The presence of heterogeneity in the porous media has microscopic and macroscopic influences on recovery performance of water-solvent process. Microscopic influences include, increased mixing effects due to the tortuosity of the pore structure, longitudinal and transverse dispersion of solvent, mass transfer of solvent, and mass transfer of oil from dendritic pore spaces. Macroscopic influences include channeling and crossflow caused by permeability variations, and wettability effects. Residual oil exists in the porous media as a trapped, disconnected phase surrounded by water. The mobile water in the reservoir can shield the in-place oil from being contacted by the injected solvent, resulting in poor solvent displacement and recovery efficiency. P. 203
Abstract Earlier numerical models for coal seam gas reservoirs assume that at initial reservoir conditions coal is either on or above the sorption isotherm, i.e., either equilibrium or saturated conditions prevail. Therefore, when undersaturated conditions exist, implementation of these models does not capture the physics of the problem accurately. In this paper, simple algorithmic procedures are proposed which allow the model to cross the isotherm between saturated and undersaturated regions during computations. Several examples which demonstrate the successful application of the proposed algorithms are presented. Implementation of the switching mechanisms to existing coalbed simulators is straightforward and should significantly enhance their applications. Introduction Coal seam gas, gas from devonian shales, geopressured aquifers and other unconventional gas reservoirs account for between 250 TCF to several thousands of TCF under a given set of economic conditions. Depending on gas prices, demand, tax incentives, or other circumstances, the actual figure can change. If demand is sufficient, interest in unconventional reservoir development will become even more widespread than it is today. The majority of gas stored in coal exists in an adsorbed rather than free state. When the system is in equilibrium, the amount of gas adsorbed on the coal is governed by the sorption isotherm. A pressure drop in the cleat system (natural fracture network) causes gas to desorb from the micropore surfaces and to diffuse into the macropores. However, if the coal bed reservoir is undersaturated, substantial pressure drops must be achieved before any significant gas production is noticed. Figure 1-A is an example of gas production, and Figure 1-B represents water production from coal bed reservoirs which are initially at equilibrium and undersaturated conditions. Figure 1-C shows corresponding well block pressures for the two cases considered. While Figures 1-A, 1-B, and 1-C focus on the early time behavior, inserts in the figures show the responses of the reservoir over a much longer period of time. The primary purpose of this paper is to present formulations that will capture the different behaviors exhibited by the coal bed reservoirs which are situated at equilibrium or saturated conditions and undersaturated conditions as displayed in Figure 1. There are two situations that need to be considered. First, the reservoir is initially in the undersaturated state, and as pressure decreases over the course of time, it enters the saturated condition. In this case, at the beginning of the simulation, the reservoir flow dynamics is described as single-phase flow of water with no gas desorption or diffusion. When pressures become sufficiently low, certain regions (starting within the immediate vicinity of the wellbore) cross the sorption isotherm. The second situation involves a saturated reservoir which undergoes either a water or gas injection test. In either case, injection rates and coal properties will result in high pressures (especially near the wellbore), so that any existing free gas disappears. Consequently, the system crosses the equilibrium isotherm in the opposite direction, i.e., from saturated to undersaturated state. P. 341
- North America > United States (0.93)
- North America > Canada > Alberta (0.28)
Abstract Development of a retrograde condensate reservoir required accurate well productivity predictions for a capital commitment to gas processing facilities. Historically, Fussell identified that liquids condensing in the reservoir will result in a substantial productivity impairment. A single well model, which included a hydraulic fracture as part of the grid system, was developed to perform sensitivities for well test interpretation and to predict long term performance. Interesting results were obtained. The productivity of fractured wells was not impaired to the degree expected. Radial modelling confirmed the results obtained by Fussell. Current simulation technique allows for direct modelling of a hydraulic fracture instead of using an equivalent well bore radius. The distribution of pressure drawdown and condensate dropout around a hydraulic fracture results in limited productivity impairment. The methodology used and the results obtained are described. Introduction This work was originally completed to forecast production from wells in a new field, which was being developed in the Deep Basin area of Alberta, Canada. The original study was comprised of geological characterization, PVT characterization, numerous well test sensitivities, as well as simulating the effects of condensate dropout on well productivity. The ultimate objective of this work was to make a nomination for a sour gas plant. Abbreviation Due to space limitations, this paper represents an abbreviation of only the most important technical point: that for wells that are hydraulically fractured productivity is not as adversely affected by condensate precipitation as previously reported. This is with some regret on behalf of the authors who, as practising engineers, find the approach (or story) to be of as much interest as the actual result. In particular, about two thirds of the real work in this study was confirming formation permeability and fracture properties. To do this, interpretations from various disciplines of petroleum engineering, such as hydraulic fracture treatment monitoring, well test interpretation and core analysis, had to resolved. Justifying, explaining and communicating this input was a significant portion of the work on this project. Organization The paper has still been organized, as much as possible, to follow the historical development of the technical work. Material is presented under the following headings: Geological Description, PVT Characterization, Model Construction, Well Test Modelling, Effects of Condensate Dropout, and Conclusions. Originally this work was completed for a single well, which was later expanded to include other wells in other pools. Only the work done on the first well analyzed is presented, which does not apply universally to the area. P. 177
ABSTRACT: The Alkaline-Surfactant-Polymer, ASP, process can significantly enhance waterfloods for appropriate reservoirs using carefully designed, reservoir specific, chemical injection strategies. This ASP technology recovers waterflood residual oil by reducing the capillary forces trapping the oil and improving the overall contact efficiency. The Minnelusa formation in the Powder River Basin was the location of the first field-wide application of this process in the U.S. An assessment of this early project nearing the end of its economic life and of other ongoing ASP projects provides an estimate of the potential of the ASP process to add reserves in other Minnelusa fields. Analysis of approximately 120 Minnelusa oil fields in the Powder River Basin indicates that the total original stock tank oil in place exceeds one billion barrels. The potential incremental oil recovery of the ASP process to these fields approaches 130 million barrels. This process can be applied at an incremental cost of $1.60 - $3.50/bbl. Introduction An Alkaline-Surfactant-Polymer, ASP, design was developed and applied to the West Kiehl Minnelusa Field beginning in 1987. This was the first field-wide application of the ASP process in the U.S., but was applied as a secondary recovery method following primary production. This made the interpretation of the waterflood incremental oil somewhat more speculative, as there was no bases for establishing waterflood recovery by decline analysis. A complication was the field size, configuration and number of wells meant that a significant fraction of the pore volume could not be swept by flooding processes. The first published analysis in 1992 showed an incremental recovery of 0.11 pore volume (340.5 Mbbl) based on project performance and laboratory data. A much more detailed evaluation was performed relying on new laboratory data, numerical simulation, and much more field performance data to assess the effectiveness of the ASP process, and to compare the West Kiehl performance with that of other Minnelusa fields. This paper is a summary of the findings of the detailed evaluation. P. 231
- North America > United States > Wyoming (1.00)
- North America > United States > Montana (0.90)
- Geology > Geological Subdiscipline > Stratigraphy (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Kiehl Field (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Kansas > State Field (0.98)
Abstract In modern reservoir characterization, detailed heterogeneous models of reservoir properties are routinely scaled-up for flow simulation. In addition to single-phase flow properties, two-phase flow properties, relative permeability and capillary pressure functions must also be scaled up. Here techniques for determination and assignment of effective relative permeability and capillary pressure on different scales of heterogeneities are presented and discussed. Many authors have considered scales of heterogeneities, their influence on fluid flow, and calculation of effective properties at a particular scale. In this paper, however, we present a unified approach to this problem; we consider effective relative permeability and capillary pressure on multiple scales of heterogeneities, and discuss a procedure for considering these heterogeneities at each level so that the overall influence is represented in the flow simulation model, results of which are used for economic decisions. A simulation technique and an analytical method for calculation of effective relative permeability and capillary pressure are presented. Scale-up of relative permeabilities results in a set of effective relative permeability curves and an effective capillary pressure curve for each larger-scale simulation grid block. We show how these relative permeabilities, and the corresponding effective capillary pressure curves, can be grouped together to yield a manageable number of effective relative permeability and capillary pressure curves for flow simulation. The application of these techniques is demonstrated through 2D and 3D scale-up and flow simulation examples. Introduction In modern reservoir characterization, detailed heterogeneous models of the reservoir are generated, and are routinely used in reservoir simulation for performance predictions. In this process, several scales of heterogeneities are encountered, and appropriate scaling procedures are needed so that data measured or derived from modeling on one scale can be used at a larger scale. This scale-up must preserve the effects of smaller-scale heterogeneities on the overall flow in the larger scale model. Reservoir geologic models with 106 to 109 or more cells must be scaled-up to reservoir models with 104 to 105 grid blocks. Therefore, the scale-up from the geologic model to reservoir simulation model may involve 100 to 10,000 grid blocks for each simulation grid block, with length scale changing from 1 to 100 ft in the geologic model to between 100 to 1000 ft in the reservoir simulation model. P. 451
- Geology > Rock Type (0.71)
- Geology > Sedimentary Geology (0.68)
Abstract This paper discusses the analyses of transient pressure data that has been measured during single well test and multi-well interference tests performed in wells producing gas and water from coal seams of the Fruitland Formation of the San Juan Basin of Colorado. The test procedures included open hole drill stem tests, cased hole water injection tests, open hole production tests, multi-well interference tests, and post-cavitation production and shut-in tests. Proper evaluation of the pressure behavior measured during each type of test resulted in similar estimates of the absolute permeability of the coal gas reservoir natural fracture system. Evaluation of post-cavitation well test data has not been presented in the literature prior to this paper. The analysis results are shown to be accurate by agreement with reservoir simulation and multi-phase interference test analysis results. Introduction The Gas Research Institute (GRI) has funded significant research efforts in the San Juan Basin of Colorado and New Mexico to increase knowledge of commercial Upper Cretaceous Fruitland Formation coal natural gas reservoir behavior. The recent emphasis of the project is to evaluate the productivity of open hole cavity completion techniques relative to the productivity of cased hole, hydraulically fractured completion techniques. Two major research efforts have been performed at sites located in Colorado on the Southern Ute Indian Reservation with Amoco Production Company and Arco Oil and Gas Company. Amoco, GRI, and Resource Enterprises, Inc. (REI), created the Completion Optimization and Assessment Laboratory (COAL) Site to evaluate and compare the completions. The COAL project was designed to evaluate the areal variation of reservoir properties upon the fluid production performance of a cavity well. The project performed in conjunction with Arco, GRI, and REI has been termed the Vertical COAL Site and was designed to evaluate the effect of the vertical distribution of reservoir properties upon cavity well performances The COAL Site included efforts performed on one producing cavity well and two observation wells. The Site was located in Section 17 of Township 32 North, Range 10 West of La Plata County, southwestern Colorado as illustrated in Figure 1. The primary well was a newly drilled open hole cavity well, Southern Ute Tribal I PLA 9 #2 (I #2). This well was logged and tested before and after installing the cavity completion. A newly drilled pressure observation well (GRI #1) was located 178 feet [54.3 m] to the northwest of the I #2 well in the orientation of the butt cleats of the natural fracture system of the coal reservoir. A second newly drilled observation well (GRI #2) was located 1,069 feet [325.8 m] to the southwest of the I #2 well in the orientation of the face cleats. The well bore geometry and gamma ray log measured in the I #2 is illustrated in Figure 2. Single well tests of each of the three wells were performed to evaluate the natural fracture (cleat) system properties prior to cavitation. P. 205^
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
Abstract A nuclear tracer imaging technique is evaluated for use in core analysis in studies of oil recovery from chalk reservoirs. In-situ fluid saturation data in long-core flood experiments in chalk, enhance the interpretations of the data; especially in mapping the local recovery efficiencies. In various long core flood displacements, including both drainages and waterfloods, emphasis has been on recording local in-situ saturation development, obtaining recovery efficiencies and studying effects on the saturation profiles from displacement pressure drops, flow rates and initial and final water saturations. The benefits of having access to local in-situ saturation information, the importance of being able to identify rock heterogeneities and tests of repeatability have been stressed. Introduction Over the past 20 years extensive efforts have been put on research on improving hydrocarbon recovery from chalk reservoirs. The challenge to understand and predict oil production from tight chalk reservoirs fully came in focus when the enormous potential for oil and gas production from chalk reservoirs in the southern part of the North Sea was discovered. The chalk reservoirs in this region are heavily fractured and the interwell fluid transport is thus conducted through the fracture network. The production mechanism is based on spontaneous water imbibition into the low permeable rock matrix, expelling the in-situ hydrocarbons into the surrounding fractures; and by continuous waterflooding of the fractures transporting the expelled oil to the producing wells. The imbibition rate and the sweep efficiency due to the spontaneous water imbibition are both crucial factors for the economics of the oil production. Deterministic for these processes are the wettability conditions and the relationships between the interacting forces: the capillary hold up, the viscous forces and the gravity. Extensive work have been reported on the challenge to understand and describe the production mechanisms, both regarding the interaction between fluid transport in the fractures and the matrix imbibition/reimbibition, and the oil displacement mechanism governed by wettability induced spontaneous water imbibition (ref. 1-8). The major problems related to the latter are to determine endpoint saturations, production rates and may be most important how to convert such laboratory data to results valid for the in-situ reservoir conditions. With regard to the fracture/rock matrix interactions, the dual porosity approach for modelling purposes has frequently been used (ref. 9), however, the important effects induced by gravity; fluid segregation, reimbibition and gravity assisted drainage in matrix block systems in capillary contact, have yet not been adequately addressed. A thorough investigation of these problems requires access to in-situ saturation information during an experimentally simulated production situation. For core analysis various imaging techniques (ref. 10-16) are applicable, including NMR-imaging and CAT-scanning, in order to obtain detailed information of the saturation development during the oil displacement. However, these techniques are not well suited in larger scale experiments using long cores to minimize disturbance from the end-effects experienced in small core plugs and when studying gravity drainage. P. 571^
- Europe > Norway > North Sea (0.34)
- North America > United States > Oklahoma (0.28)
- Europe > United Kingdom > North Sea (0.25)
- (2 more...)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract The effects of rock structural properties on porosity and permeability may be considered as generally well known, being permeability may be considered as generally well known, being particularly critical when modeling tight sands and limestones. particularly critical when modeling tight sands and limestones. Nevertheless, such effects have been slow to find their way into reservoir simulators. These effects are frequently even more important for fractured horizons where 10โ20 porosity per cent changes, and/or several orders of magnitude change in permeability, can be observed under changing reservoir stress permeability, can be observed under changing reservoir stress conditions. Rocks with weak tensile properties are particularly vulnerable to stress change. These include diatomite, chalks, and overpressured Gulf Coast shales. Less well known is the dependence of relative permeability on stress. Moreover, the effects of relative permeability and capillary pressure in the fractures themselves need to be accounted for. Production in naturally fractured reservoirs is limited by the Production in naturally fractured reservoirs is limited by the exchange rates of oil and gas between matrix blocks and fractures. Naturally fractured simulators which use the conventional dual porosity formulation fail to resolve gradients in the matrix blocks porosity formulation fail to resolve gradients in the matrix blocks unless some type of sub-gridding (subdomains) is used. This lack of resolution at the matrix/fracture interface leads to significant errors in production rates when modeling oil recovery from fractured reservoirs. Introduction Issues crucial to the management of naturally fractured reservoirs are discussed here. We analyze mechanisms which tend to dominate reservoir performance. In a companion paper a new algorithm for determining fluid and pressure gradients in the matrix is presented. Hydrocarbon production from a naturally fractured reservoir usually relics on two principle displacement forces gravity and capillary pressure. Fluid transport due to gradients of these forces is pressure. Fluid transport due to gradients of these forces is enhanced or retarded by rock and fracture permeabilities. Permeability evolves with reservoir development. Production Permeability evolves with reservoir development. Production increases reservoir stress by decreasing pressure, reducing permeability. Injection decreases stress, increasing permeability. permeability. Injection decreases stress, increasing permeability. In tight zones (the usual case when fractures contribute significantly to production/injection) evolving stress patterns can significantly alter both matrix and fracture permeability. Thus we cannot simply use laboratory determined permeability at initial reservoir conditions. Instead we must use reservoir simulators which employ a range of laboratory data to compute permeability and porosity dynamically as a function of reservoir pressure. pressure. Relative permeability also varies with pressure. In fractures the effects of pressure change on relative permeability must be accounted for. In many tight reservoir rocks relative permeability will also have to be modified by the simulator to account for pressure changes. Fluid exchange between rock matrix and fracture is extremely complicated. Detailed distributions for both pressure and saturation near the matrix/fracture interfaces are required to estimate rates at which oil and gas will migrate from matrix to fracture. Flow within a fracture cannot be compared with flow in an open channel. Fracture apertures of a few tens of microns are common at reservoir conditions. Relative permeability and capillary pressure are essential when modelling fracture flow. ABSOLUTE PERMEABILITY IS PRESSURE DEPENDENT Discussion It is well known that permeability depends on reservoir pressure. In tight strata permeability often declines exponentially with decreasing pressure (see Figure 1). P. 117
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.46)
Effects of Drying on Absolute and Relative Permeabilities of Low-Permeability Gas Sands
Morrow, N.R. (New Mexico Petroleum Recovery Research Center) | Cather, M.E. (New Mexico Petroleum Recovery Research Center) | Buckley, J.S. (New Mexico Petroleum Recovery Research Center) | Dandge, V. (Lockhead Engineering and Sciences)
Abstract Water adsorption/desorption (sorption) isotherms, surface-area measurements, and electron and optical microscopy all demonstrate the presence of significant microporosity in low permeability gas sands as exemplified by cores taken during the course of the Multiwell Field Experiment (MWX). Pore space in these sandstones occurs primarily as solution pores that are often partially filled primarily as solution pores that are often partially filled by fine-structured clay minerals such as illite and smectite. Quantitative information on pore size and volume of microporosity can be obtained from sorption isotherms. A hygroscopic index for rocks based on desorption behavior is proposed. To delineate changes in pore structure that can arise proposed. To delineate changes in pore structure that can arise during drying, water desorption isotherms, absolute permeabilities to brine, and effective permeabilities to gas permeabilities to brine, and effective permeabilities to gas were compared for preserved (undried) and dried cores. Permeabilities of cores which had been allowed to dry tended Permeabilities of cores which had been allowed to dry tended to be higher than those of the flesh cores. Changes in effective permeabilities and sorption isotherms were consistent with observed decrees in absolute permeabilities. Low water content in preserved MWX cores demonstrated that the technique used to protect them from drying was sometimes inadequate. Introduction Detailed analysis has been performed on core obtained from the U.S. Department of Energy's Multiwell Experimental Site (MWX) near Rangeley, Colorado, as part of a wide-ranging study of low permeability (tight) sandstones. Ranges of porosity, permeability, and surface area encountered in the MWX sandstones are given in Table 1. This paper focuses on the petrophysical properties of preserved (undried) vs conventional cores. Special attention is given to the microporosity and associated hygroscopic properties of tight sands. The sandstones cored for the MWX experiment consist of fluvial, deltaic, and marine rocks from a progradational sequence within the Mesaverde Group. Permeabilities and porosities are low, and permeabilities are generally very porosities are low, and permeabilities are generally very sensitive to overburden pressure. Petrographic examination of the Mesaverde sandstones using fluorescence microscopy of surface-stained thin sections shows clearly a porosity network made up of high-aspect-ratio sheet pores at grain boundaries and dissolution pores of about the same size as individual grains. This pores of about the same size as individual grains. This technique also reveals the widespread existence of microporosity within altered feldspars and lithic fragments, authigenic clays that partially fill most of the dissolution pores, and microporous grains such as chert and shale fragments. pores, and microporous grains such as chert and shale fragments. Much of this microporosity is only marginally resolvable, indicating that it is of submicron size. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) analyses indicate the presence of illite, mixed layer clay, chlorite, and kaolinite in varying amounts and proportions. Core-analysis procedures usually involve drastic alteration of the micro-environment surrounding pore-filling clays from that existing in the reservoir. Cores are routinely oven-dried prior to measurement of porosity and permeability. Solvent extraction may be used to remove organic material and methanol is commonly used to remove inorganic salts. Subsequently, cores may be resaturated with brine for measurement of transport properties such as permeability and electrical resistivity. Change in permeability with respect to a given fluid provides a general indication of permanent changes in pore provides a general indication of permanent changes in pore structure. Permeabilities to brine of resaturated cores have sometimes been found to be much higher than formation values calculated from injectivity tests. This discrepancy has been ascribed to capillary forces which develop during drying and cause permanent collapse of fibrous illite within pore spaces. Electron micrographs of samples prepared by critical-point-drying (drying without phase change and, hence, fluid interfaces) showed that delicate clay structures remained intact. Also, gas permeabilities for the critical-point-dried samples were low compared to those of conventionally dried samples. P. 727
- North America > United States > Colorado (0.34)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.44)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.54)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- North America > United States > Louisiana > Travis Peak Formation (0.99)
- (5 more...)