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Results
Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms
Aminzadeh, Behdad (Chevron CTC) | Chandrasekhar, Sriram (Chevron CTC) | Srivastava, Mayank (Chevron CTC) | Tang, Tom (Chevron CTC) | Inouye, Art (Chevron CTC) | Villegas, Mauricio (Chevron GOM) | Valjak, Monika (Chevron GOM) | Dwarakanath, Varadarajan (Chevron CTC)
Abstract Water floods are typically conducted using the least expensive, easily available, non-damaging brine. Very little attention is given to the possibility of changing brine composition to improve oil recovery. Over the last 20 years, there has been laboratory and field trial evidence that shows changing brine chemistry, especially to low salinity, can sometimes increase the recovery. The various mechanisms of additional oil recovery from changing brine chemistry are not entirely clear. We report here on the effect of using low salinity and divalent altered brines on oil recovery through a variety of laboratory methods and materials. More than twenty corefloods were conducted to evaluate the effect of brine chemistry and initial wettability on incremental oil recovery. We also performed phase behavior tests, contact angle measurements, and wettability index measurements to evaluate recovery mechanisms. Initial wettability of the core was altered by ageing it with different crude oil containing wide range of asphaltene content. The core flood with lowest wettability index (least water-wet) produced about 12% incremental recovery while the most water-wet core only produced ∼ 4% during the secondary low salinity waterflood.
- Asia (0.93)
- North America > United States > Texas (0.47)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.98)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.98)
- (2 more...)
Abstract Chemical Enhanced Oil Recovery (EOR) methods have been implemented in a West Texas fractured carbonate. Due to the partially oil-wet nature of Yates field and slightly viscous oil (5-7 cP), surfactant injection was implemented to alter wettability and polymer was injected in the waterflood area to improve displacement efficiency, respectively. Single well huff-n-puff (HnP) surfactant treatments (late 1980's-today) and well-to-well pilots (1990's-2000's) have increased incremental oil production relative to base decline. Optimum surfactant chemicals were chosen based on laboratory results, reservoir performance, and economic viability. Polymer injection was carried out over a 6 year span (1983-1989) in which 55+ million pounds of polymer was injected; however the interpretation and analysis was complicated due to concurrent drilling, workover activities, and no prior waterflood development. Design parameters key to the surfactant implementation included: surfactant type and concentration, Critical Micelle Concentration (CMC), fluid saturations, oil composition, formation water salinity, fracture intensity, and treatment soak timing. Laboratory experiments included interfacial tension, contact angle, adsorption, fluid phase stability, Amott tests, and coreflooding. Numerical models were developed to help understand the sensitivity of each parameter on EOR performance and guide the design of treatments. Field implementation of surfactant included different surfactant types: anionic, non-ionic, and cationic. HnP treatments were followed by a soak period before returning the well to production and conducting flow back water analysis. Overall, HnP treatments using cationic surfactant resulted in the highest efficiency in terms of barrels of oil per kilogram of surfactant. Well-to-well tests were only conducted with non-ionic surfactants and showed mixed results. Design parameters for polymer injection such as fluid viscosity, concentration, adsorption and molecular weight were determined through coreflooding and fluid viscosity experiments. Two polymer types, high and low molecular weight, were studied and manufactured in-field and used in 200 or more injectors either continuously or alternating with produced water. Polymer injection was not effective in improving displacement efficiency in the water flood area of Yates reservoir and was suspended in 1989. The scale of field implementation and analysis of the impact of chemical injection on oil production in a massive, densely fractured carbonate field has provided valuable insight and learnings for future development and will be discussed. Other chemical EOR methods currently under investigation such as foam and other wettability altering technologies will also be discussed.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- 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)
- (31 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (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)
Artificial Diagenesis of Carbonates: Temperature Dependent Inorganic and Organic Modifications in Reservoir Mimetic Fluids
Rao, Ashit (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Kumar, Saravana (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Annink, Carla (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Le-Anh, Duy (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | B. Alotaibi, Mohammed (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco) | C. Ayirala, Subhash (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco) | Siretanu, Igor (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Duits, Michel (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Mugele, Frieder (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | A. Yousef, Ali (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco)
Abstract Within reservoirs, spatial variations related to mineralogy and fluid chemistry determine the success of improved oil recovery (IOR) techniques. However, the composition and structure of mineral-adsorbent-fluid interfaces, which fundamentally determine the initial and IOR-altered wettability of reservoir rocks as well as the displacement of crude oil (CRO), are unclear. Replicating the diagenetic alterations of carbonates, this study addresses the temperature dependence of the inorganic and organic modifications of calcite by reservoir pertinent fluids as well as its consequences on mineral wettability and reactivity. We utilize a suite of characterization methods, such as confocal Raman, scanning electron and atomic force microscopy as well as Fourier-transform infrared spectroscopy, to investigate the modifications of carbonates on aging in formation water (FW), CRO-equilibrated FW and FW-equilibrated CRO. The microscopic modifications of carbonates present positive correlations with aging temperature and also are varied, encompassing topographical alterations, cation substitution of lattice Ca ions by Mg ions and the deposition of particles enriched with polyaromatic hydrocarbons (PAHs) as organic adlayers. Aging in the formation waters produce substantial reconstruction of calcite surfaces, with the formation of Mg-calcite layers at elevated temperatures. Subsequent aging in brine-equilibrated CRO produces an organic coating on calcite surfaces, which is composed of PAH-enriched particles. The organic adlayers, deposited at high temperature, produce a transition in the macroscopic contact angles towards a more ‘oil wet’ tendency. In addition, the organic adlayer presents limited permeability and serves as a diffusion barrier to the reactivity of the bound mineral, as evident from substantially reduced rates of calcite dissolution. The multilayer deposition of organic particles is attributed to an interplay between bulk and surface reactions for interfacially active constituents of CRO. With the enrichment of PAHs even observed for mineral grains within reservoir rocks, the permeability and stability of organic adlayers emerge as key factors determining the wettability of carbonates as well as the diffusion behavior of ionic and molecular species at mineral-fluid interfaces. Results of this study are relevant to multiple aspects of reservoir development and maintenance, encompassing laboratory scale wettability and core flooding experiments, in silico models as well as the advancement of IOR strategies. The observed nano- and microscopic surface alterations of carbonates within reservoir mimetic environments facilitate our understanding of the physicochemical relations between mineralogy and fluid chemistry as well as elucidate the organization of mineral-adsorbent-fluid interfaces within reservoirs.
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States (0.67)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- (4 more...)
Abstract The wettability of tight reservoir rock plays a critical role in affecting relative permeability and in turn oil recovery. However, the link between wettability and its effects on oil recovery remains poorly understood, and the potential to boost oil recovery by varying the wettability has not been fully explored. This work was an attempt to conduct a systematic experimental study to improve our understanding of wettability of tight oil reservoirs and the mechanisms of its alteration on oil recovery improvement. Contact angles of individual rock-forming minerals and reservoir rock samples were first measured in brines with different salinities. Then the minerals were aged separately with a medium crude oil with sufficient polar components to investigate their tendency for wettability alteration. As well, oil and water distributions inside tight core samples were scanned by a synchrotron-based computed tomography scanner. Contact angle measurements for all minerals and reservoir rocks showed initial water-wetting behavior. After aging with crude oil for over two months, polar components from the oil adsorbed onto the solid surfaces to alter their wettability to less water wet. Consequently, this wettability alteration contributed to oil and water redistribution and saturation change in reservoir cores. The experimental findings suggested that the wettability in tight reservoirs is a strong function of rock mineralogy, formation fluid properties, and saturation history. Preliminary numerical simulation revealed how rock wettability alteration could contribute to improved oil recovery through waterflooding.
- North America > Canada > Saskatchewan (0.95)
- North America > United States > North Dakota (0.94)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.54)
- 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 > Core analysis (1.00)
Abstract Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates. We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on Hirasaki (1991), we describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called "stability number," where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery. We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata et al. (2014) and Yousef et al. (2010). For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a).
- Asia > Middle East (0.67)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Abstract Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > California (0.28)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.56)
Effect of Low Salinity Waterflooding on the Chemistry of the Produced Crude Oil
Collins, I. R. (BP Exploration Operating Co. Ltd.) | Couves, J. W. (BP Exploration Operating Co. Ltd.) | Hodges, M.. (BP Exploration Operating Co. Ltd.) | McBride, E. K. (BP Exploration Operating Co. Ltd.) | Pedersen, C. S. (BP Exploration Operating Co. Ltd.) | Salino, P. A. (BP Exploration Operating Co. Ltd.) | Webb, K. J. (BP Exploration Operating Co. Ltd.) | Wicking, C.. (BP Oil UK) | Zeng, H.. (BP North America)
Abstract Injecting low salinity water into a petroleum reservoir to improve oil recovery has been studied extensively over recent years as a low cost enhanced oil recovery (EOR) process. Extensive chemical analyses have been performed on the effluent water from low salinity waterflood experiments which reveal the extent of interaction between the injected brine, the oil and the rock matrix. However, there has been little work reported on the impact of the injected fluid composition on the nature and composition of the oil recovered. This paper details an investigation on how the waterflood medium affects the chemistry of the produced oil, which is important for understanding the mechanism by which the additional oil is released. Produced oil samples were analyzed using High Resolution Mass Spectrometry (HRMS) which essentially measures the mass of individual molecular species very precisely, which makes it possible to assign a unique elemental composition (e.g. carbon, hydrogen, oxygen, nitrogen and sulfur content) to each mass. Additionally, by careful control of the ionization procedure, it was possible to identify acidic and basic polar species, as well as neutral aromatic hydrocarbons. The data indicates that the composition of the produced oil changes during the reduced salinity waterflood, with an increase in the CxHyO2 species occurring. These molecular species, compared to the secondary high salinity flood, are released as the tertiary low salinity injection water passes through the core; they then decline towards the end of the waterflood. In contrast, there appears to be little change in aromaticity, sulfur and nitrogen containing species during the flood. The fact that the produced oil is enriched predominantly with CxHyO2 species is consistent with the multiple ion exchange and local pH rise mechanisms proposed previously.
- North America > United States > Oklahoma (0.29)
- North America > United States > California (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (0.71)
- Geology > Geological Subdiscipline (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
Abstract The goal of this work is to develop surfactant systems that can improve oil flow from shale wells after fracturing or re-fracturing. Surfactants can reduce oil-water interfacial tension and wettability of the shale, which in turn can improve water imbibition, increase oil relative permeability and reduce water blockage at the matrix-fracture interface. Temperature in typical shale reservoirs are high and the surfactants need to be aqueous stable to be effective in these treatments. Mixing two surfactants often gives higher aqueous stability than those of the single surfactants. A large number of surfactants (anionic, non-ionic and cationic) and their blends were studied for aqueous stability, contact angle and spontaneous imbibition. Seven single surfactants and nine surfactant blends were found to be stable in both high and low salinity brines at 125 °C. All aqueous stable blends changed wettability of oil-wet shale to preferentially water-wet in both high and low salinity brines. Seven single surfactants and five surfactant blends were tested for imbibition. Surfactant solutions improved water imbibition to the extent of 20% PV. Surfactant blends improved imbibition more than the single surfactants. Imbibition in cores reached a plateau in about 3 days. Surfactant blends have the potential to be used in low salinity fracturing or refracturing fluids to stimulate shale wells.
The Onset of Spontaneous Imbibition: How Irregular Fronts Influence Imbibition Rate and Scaling Groups
Føyen, T. L. (Dept. of Physics and Technology, University of Bergen) | Fernø, M. A. (Dept. of Physics and Technology, University of Bergen) | Brattekås, B.. (The National IOR Centre of Norway, Dept. of Energy Resources, University of Stavanger)
Abstract Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior. The imbibition rate during early stages of spontaneous imbibition (the onset period) was sometimes observed to deviate from the square root of time behavior. The impact of the onset period on the imbibition process is, however, not well understood. In this work, the development of displacement fronts were visualized during the onset period, using twodimensional paperboard models and core plugs imaged using Positron Emission Tomography (PET-CT). The new experimental results provided insight on the dynamics during the initial spontaneous imbibition period. Controlled two-dimensional paperboard experiments demonstrated that restricted wetting phase flow through the surface exposed to water caused irregular saturation fronts and deviation from the square root of time behavior during the onset period. Local restriction of the wetting phase flow was observed during spontaneous imbibition in sandstone core plugs as a result of non-uniform wetting preference. The presence of nonuniform wetting resulted in unpredictable spontaneous imbibition behavior, with induction time (delayed imbibition start) and highly irregular fronts. Without imaging, the development of irregular saturation fronts cannot be observed locally; hence the effect cannot be accounted for, and the development of spontaneous imbibition in the core erroneously interpreted as a corescale wettability effect. This underlines the undeniable need for a homogenous wettability preference through the porous medium when performing laboratory spontaneous imbibition measurements. Our observations of non-uniform wetting preference will affect Darcy-scale wettability measurements, scaling and modeling. We argue that great care must be taken when preparing core plugs for spontaneous imbibition, to avoid experimental artifacts.
- North America > United States (0.46)
- Europe > Norway (0.29)
Abstract Wettability of the rock is an important parameter in determining oil recovery. It determines the fluid behavior and the fluid distribution in the reservoir. Aging of the rock changes the wettability of the rock and can affect the residual oil saturation. This paper investigates the effect of aging on the oil recovery during the Water-Alternating-CO2 injection (WACO2) process using 20 in. outcrop Grey Berea sandstone cores under immiscible conditions. In the present work, two coreflood experiments were performed. Both cores were aged for a period of 30 days at 149°F. This study is a continued research and compares the performance of WACO2 injection in aged cores to previously published work with unaged cores. All experiments were done at 500 psi and in the secondary recovery mode. The wettability of the Rock- Brine-CO2-Oil system for aged cores was determined by contact angle measurements using formation brine (174,156 ppm), seawater brine (54,680 ppm) and low-salinity brine (5,000 ppm NaCl). The interfacial tension (IFT) of the Brine-Oil-N2 and Brine-Oil-CO2 system was also measured using the axisymmetric drop shape analysis (ADSA) method. Computerized tomography (CT) scans were obtained for each core in its various states: dry state, 100% water-saturated state, oil saturated state with irreducible water saturation, and residual oil-saturated state. The CT scans were used to determine the porosity profile of the cores. The contact angle measurements of the Rock - Brine - CO2 - Oil system indicated an increase in contact angles after the aging of the cores. Low-salinity brine showed the most water-wet state (55°) and seawater brine showed the most oil-wet state (96°) of the rock. This may be because of the increased concentration of divalent ions on the surface of the rock during seawater brine injection. Ion binding is the dominant mechanism in the oil-wet nature of the rock. The previously published work stated that the coreflood experiments of the unaged cores resulted in an oil recovery of 61.7 and 64.6% OOIP during low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. In aged cores, the oil recovery increased to 97.7 and 76.1% OOIP during the low-salinity water-alternating-CO2 and seawater-alternating-CO2 injection, respectively. The improved oil recovery was attributed to the wettability alteration when the rock was aged. The interfacial tension measurements of brine/oil/nitrogen and brine/oil/CO2 systems showed that the salinity of the brine had an effect on the IFT. Low-salinity brine (5,000 ppm) yielded the highest IFT values and seawater brine produced the least. Monovalent ions had a weak effect on the interfacial activity between the oil and the brine. When multivalent ions were present, the IFT values were influenced by the salting effect of the brines. During the IFT measurements of brine/oil/CO2 system, the IFT values showed an increasing trend as a function of time and then stabilized. The increase in IFT was because of the initial mass transfer between the CO2, brine, and oil phases.
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Oklahoma (0.28)
- North America > United States > West Virginia (0.26)
- (3 more...)
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)