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Results
Saturation Modeling in a Multilayered Carbonate Reservoir Using Log-Derived Saturation-Height Function
Kumar, Rajesh (Oil & Natural Gas Corporation Ltd.) | Cherukupalli, P.K. (Oil & Natural Gas Corporation Ltd.) | Lohar, B.L. (Oil & Natural Gas Corporation Ltd.) | Chandra, Dinesh (Oil & Natural Gas Corporation Ltd.)
Abstract The conventional and widely used way of distributing saturation arrays inreservoir simulation models is through porosity-weighted water saturationvalues. In this way, each grid cell has an assigned porosity and initial watersaturation. The porosity and water saturation are estimated with the help ofwell logs using established procedures. However, for producing reservoirs, logderived saturations may not represent initial saturations due to variousreasons like depletion due to production and effect of water injection etc. Oneof the ways to estimate the initial water saturation is by the use ofrelationship between depth and bulk volume of water (BVW). Such relationship, known as Saturation-Height function is used to estimate saturation values awayfrom the well locations and to calculate the hydrocarbons in placevolumetrically. This approach has been used in a multi layered carbonatereservoir of an Indian offshore field. Layer-wise saturation height functions are developed by establishingrelationships between height above the free water level and bulk volume ofwater derived from the wells drilled in the initial phase of field development. The scatter in the BVW plot has been reduced by further classifying the datafor different porosity facies. These porosity intervals are treated as rocktypes for that layer. Since each layer has a particular range of porosity, different porosity based rock types are identified. Height above the free waterlevel versus water saturation plots are then generated for different rock typesusing the relationship developed for each geological layer. These equations wereused to assign initial water saturation in the reservoir simulation model. Introduction The distribution of water saturation within a 3-D reservoir model is a keytask of an integrated reservoir description. Possible ways of distributingwater saturation values to the various layers in a reservoir simulation modelare,By mapping, so each grid cell has an assigned initial water saturation, calculated by integrating porosity-weighted water saturation values over themapped zone for each well. This entails the use of "pseudo capillary pressures"at each grid cell to maintain initial equilibrium. By the use of relationship such as bulk volume of water (BVW) versus depthcurve. BVW has the added advantage of compensating to a certain extent fordifferent average porosity levels within comparable zones. Initially, efforts were made to establish different rock types using coreanalysis based capillary pressure data. Fig. 1 shows the layer wisecapillary pressure versus water saturation plot. It is evident that it would bedifficult to identify different rock types for different layers as in eachlayer irreducible water saturation values cover a wide range and overlap withother layers. Therefore, In order to calculate saturation-height functionswithout using core measurements, an alternative method was adopted. A significant amount of work to generate saturation height functions isavailable in the literature. These functions calculates watersaturation based on one or more of the parameters like, porosity, oil watercontact, gas water contact, irreducible water saturation, height above contactetc. But, all these functions have their own merits and demerits. Saturationheight function based on bulk volume of water and height above the free waterlevel has also been reported in the literature. A methodology foridentifying different rock types based on the variation of porosity in eachlayer in a multi-layered carbonate reservoir using saturation height functionconcept is discussed in the present paper.
- North America > United States (0.69)
- Europe (0.48)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.62)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.51)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.47)
Abstract The complex interplay between depositional facies and diagenesis in dolostones presents numerous challenges for calculating petrophysical properties from wireline logs. Complex pore geometries and mineralogies control rock petrophysical properties, and equations for calculating porosities and saturations must therefore be tailored to specific pore geometry-mineralogy combinations. The complex mineralogy of some dolostone reservoirs, moreover, has profound effects on wireline log measurements. If dolostone reservoirs are divided into petrophysical-mineralogical facies of similar depositional and diagenetic textures and, thus, similar pore geometries and mineralogy, empirical equations that apply specifically to that geologically identified petrophysical-mineralogical facies can be developed so that porosity and water saturation can be calculated accurately. We present some examples from Permian shallow-water dolostone reservoirs of the Permian Basin, southwestern United States, that demonstrate analytical approaches for calculating petrophysical properties in these complex rock types. The four general petrophysical-mineralogical facies that characterize Permian shallow-water dolostone reservoirs are (1) subtidal, muddominated dolostone; (2) subtidal, grain-dominated dolostone; (3) dolomitic and siliciclastic peritidal rocks; and (4) diagenetically altered, subtidal dolostone. Introduction The multiple pore types and associated pore-throat geometries and variations in siliciclastic and calcium-sulfate content, which are characteristic of complex dolostone reservoirs and a consequence of both depositional and diagenetic processes, require that petrophysical calculations from wireline logs be tailored to specific rock types. Simply put, "standard" rock equations generally yield unreliable calculations of porosity and saturation. It is well established that pore types and pore geometries in carbonate reservoir rocks control petrophysical properties such as porosity, permeability, and saturation. It is also well established that the complex mineralogies in some dolostone reservoirs can have a tremendous influence on wireline tool response. Therefore, petrophysical characterization, and, more specifically, accurate wireline log analysis of dolostone reservoirs, require an understanding of both complex pore geometry and mineralogy. We describe methods of determining petrophysical properties in complex dolostone reservoirs by considering the key rock properties of mineralogy, depositional and diagenetic textures, and pore and pore-throat geometry. We incorporate all of these rock properties into calculations by grouping parts of the reservoir into petrophysical-mineralogical facies. In this paper we draw on examples from Permian (Guadalupian and Leonardian) reservoirs of the Permian Basin in the southwestern United States, although the principles and procedures presented herein have application to dolostone reservoirs throughout the world. Influence of Pore Geometry on Petrophysical Properties Petrophysical properties in complex carbonate rocks are mutually interdependent. Porosity-permeability cross-plots and the Archie equation, which expresses formation resistivity factor (FRF) as a function of porosity, are two of the most commonly recognized examples of this interdependency. It follows that if permeability and FRF vary with porosity, then FRF must be recognized as varying with both porosity and permeability. Similarly, capillarypressure characteristics are dependent on both porosity and permeability as seen in the Leverett j-function. The mutualinterdependence of petrophysical properties is an important consideration for making accurate models of porosities and saturations in complex dolostone reservoirs.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (1.00)
- Geology > Geological Subdiscipline (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)
- (32 more...)
Abstract Petrophysical properties of mudstones, clay-rich silts and other fine grained sediments loosely referred to as shales can provide numerous geologic characteristics to improve sand reservoir maps. Useful water salinities and rock properties caused by sedimentation may be derived from impermeable zones. Those properties often relate to and reveal depositional patterns and processes. Well log responses to shales can help to delineate reservoir components, determine depositional environments, and improve production. Introduction Substantial, significant, and subtle changes are usually made to sandstone reservoir maps as more information becomes available during field development. Even maps based on numerous wells can still raise questions and contradict actual production results. Much more information is almost always needed from existing data. Geologic maps often have large uncertainties because there are usually far too few well logs available to supply sufficient sand characteristics. In addition, fluid movements altered original depositional properties of many sands. Sand and fluid modifications cause difficulties in reconstructing the processes that distributed sands and created permeability barriers. Increased knowledge about a depositional system can reduce map uncertainties, avoid lower quality rocks, reveal inadequate or unlikely drainage, and help to locate additional drilling sites. Shale log responses are usually available and another source of low cost information. Impermeable zone properties immediately above, below, and within sands have been used to make models of sedimentation patterns. Theory Relationships often exist between shale water salinities and depositional environments. Some of the original fluids have been squeezed out of most shales. However, the remaining waters frequently retain enough salinity contrasts to indicate depositional processes or locations within sediments. River channels, fluvial drained marshes, and lakes often have fresh waters. Bays typically have higher average salinities with sometimes rapid and cyclic variations in sediments with fresh, brackish, and marine fluids. Marine deposits are usually more salty, but the proximity of large rivers can be a complication. Sabkas or salt lakes and some marshes can have very saline conditions. Rates of change in salinities can also be tied to changes in geology. Salinities may be low and consistent for miles along the path of a river channel. In contrast, changes may be rapid at angles to the river flow. Bay salinities detected near river salinities may indicate a narrow reservoir made by a protruded stream dominated system. Slower salinity rates of change have been associated with gradual variations in sea levels and with widespread muds. Contour shapes help to solve gradual ambiguities. A shape resembling a reworked sandy shoreline in a position likely to have been exposed to waves may be distinguished from a sheltered mud flat. Only a few brief and basic salinity analysis concepts can be presented here. Impermeable sediments within ancient counterparts to the above systems often retain adequately distinct present day water properties to alter well log responses. The log curve RWA based on calculated porosities and resistivities usually relates to water salinities. Consequently, map contours based on RWA curves from impermeable zones offer more information to reveal original sedimentation conditions.
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
Assessing the Potential Redevelopment of a 1960's Vintage Oil Field
Weiss, W.W. (NM Petroleum Recovery Research Center) | Wo, S. (NM Petroleum Recovery Research Center) | Balch, R.S. (NM Petroleum Recovery Research Center) | Scott, L. (Lynx Petroleum Consultants, Inc.) | Kendall, R.P. (Los Alamos National Laboratory)
Abstract This paper presents the practical use of a public domain black oil simulator (BOAST) to formulate a reservoir redevelopment plan. The subject reservoir is the 3750-ft Penrose sand in the Eumont Pool located on the north western edge of the Central Basin Platform. A small operator acquired the 22-well property from a major; as usual, interpretive information was not included in the well files. Therefore, reservoir characterization relied chiefly on public information (1960 vintage well logs and production/ injection history). The old logs were evaluated by correlating them with a modern suite of logs to estimate the porosity, deep resistivity, and water saturation in three zones. The permeability was empirically predicted from the porosity and residual water saturation. Geostatistical maps based on the well values were used to estimate interwell grid block properties required for simulation. The initial reservoir characterization was modified while matching the 42 years of production/injection history of the individual wells. The primary and secondary history match suggested that ~10% of the original oil in place was recovered. The remaining 35 million barrels of oil is an attractive redevelopment target. The calibrated simulation model was used to forecast continued operation as currently practiced. The performance of a new well with a 990-ft horizontal lateral was also evaluated, as well as the benefits of five different horizontal lateral completion strategies. Introduction Advanced reservoir management techniques, which include the integration of dynamic production data with the static geologic information, are generally applied to large reservoirs with major reserves. Major oil companies with the resources to apply advanced reservoir management techniques operate fields of this type. With their operating experience, the majors have come to understand the value of advanced reservoir management techniques. Independent oil and gas companies generally do not have the benefit of this experience. Lynx Petroleum Consultants, Inc acquired the Reed Sanderson Unit from Conoco Inc. in 1992. Lynx entered into an agreement with Los Alamos National Laboratory under the ACTI Advanced Reservoir Management CRADA No. LA95C10237 to demonstrate the applicability of computer modeling/communications technology as a means of reducing costs and increasing the effectiveness of producing oil and gas from the Reed Sanderson Unit, Penrose Sand zone. Most large fields are discovered and eventually operated by large companies with the clerical staff required to maintain production records and well files. The sale of large units to smaller companies frequently does not include the entire set of well files. Thus, public records were used to supplement the Lynx well files.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico > Los Alamos County > Los Alamos (0.25)
- 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)
- (25 more...)
Abstract Because operators generally have taken a conservative approach to reservoir management, tremendous opportunities exist for increasing production and profitability in domestic reservoirs. Recognizing the potential recovery possible because of sub-optimal reservoir management, the U.S. Department of Energy (DOE) developed a Reservoir Management Demonstration Program to increase reservoir management understanding through demonstration and technology transfer. Three cost-shared projects were launched under cooperative research and development agreements (CRADAs). The first completed project, in East Randolph field, Portage County, OH, was in a small, newly discovered oil reservoir producing from Cambrian marginal marine sandstones of the Rose Run formation. The second completed project addressed a large, mature waterflood in Citronelle field, Mobile County, AL. Substantial progress was made on the third, in Bainville North field, Roosevelt County, MT. Reservoir management strategies were, indeed, developed to increase recovery and profitability. At East Randolph field, gas reinjection was recommended as a secondary recovery technique over waterflood. For Citronelle field, a flow-unit approach to optimizing waterfloods using existing data was developed for the short-term strategy, and recommendations for additional data collection and analysis were developed for the long-term. In the Bainville North field, a reservoir model for simulation aided evaluation of new potential in one of several producing zones. Each project shows the importance of developing reservoir management plans in the context of knowledge of the reservoir system, business environment, and technologies (such as affordable new PC-based programs capable of handling tasks previously requiring a mainframe). Experience also has led to valuable insights on reservoir management methodology, by identifying the general steps and considerations necessary to formulate reservoir management plans for any reservoir. P. 143
- North America > United States > Alabama > Mobile County (0.74)
- North America > United States > Ohio (0.66)
- North America > United States > North Dakota > McKenzie County (0.45)
- Asia > Middle East > Qatar > Arabian Gulf (0.45)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > Ohio > Rose Run Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Red River Formation (0.99)
- (7 more...)
- 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 > Open hole/cased hole log analysis (1.00)
- (2 more...)
Abstract In this paper, we have utilized a non-parametric transformation and regression technique called ACE (alternating conditional expectation) to estimate permeability from well logs at the Salt Creek Field Unit (SCFU), Texas, a heterogeneous reef carbonate reservoir. Previous attempts to derive permeability correlations at the SCFU have been less than satisfactory, leading to an over-dependence on porosity derived reservoir descriptions to predict fluid flow. Using non-parametric regression, we have now established a relationship between permeability and several common well logs that are available field-wide. These include density porosity, neutron porosity, shallow resistivity, deep resistivity and gamma ray logs. The approach adopted here also allowed US to integrate our geologic understanding of the reservoir into the non-parametric regression, further optimizing the final correlation. We have successfully predicted permeability in a majority of the uncored wells with acceptable accuracy at SCFU. These results have led to an enhanced reservoir characterization based on flow (permeability) rather than storage (porosity). This benefits both daily Operations and reservoir simulation efforts. This first, full-field application of ACE in a carbonate reservoir has demonstrated the strength and potential wide-scale use of non-parametric methods to predict permeability in heterogeneous reservoirs. P. 129
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.35)
- 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)
- (23 more...)
Abstract The cost-effective attributes of borehole surface-imaging technologies (i.e., video, acoustic, and resistivity technologies) make them logical candidates for use in improved recovery projects in both clastic and carbonate reservoirs. Imaging tools provide information about formation fluid content and reservoir heterogeneities at a scale and resolution that was formerly available only through oriented or native-state coring. The U.S. Department of Energy's Class Program is a series of industry cost- shared field-demonstration projects employing detailed reservoir characterization to evaluate and optimally implement improved recovery technologies in reservoirs that contain ample amounts of unrecovered oil but are in danger of being abandoned in the near future. Use of borehole-imaging technologies in Class 1, 2, and 3 projects has been a tremendous aid to reservoir decision making. Introduction This paper explores the role that borehole imaging can and does play in the improved exploitation of reservoirs. The focus is on defining the appropriate application of this family of tools for realizing improved oil recovery through more accurate reservoir description. The U.S. Department of Energy's Class Program, in which a wide variety of current and newly developing technologies are being demonstrated in field projects, is a rich source of practical examples from which to draw. A concentrated technology transfer effort is making the critical decision-making processes, application methodologies, and detailed technical and economic results from these projects available to industry. Boreholes as a Source of Information After a long history of improved recovery projects blemished with numerous marginally economic to uneconomic attempts, industry as a whole now realizes the importance of adequate reservoir description in improved recovery. Class Program projects place strong emphasis on reservoir description as the key to implementing technically and economically successful improved recovery technologies. Because reservoirs are generally heterogeneous on several different scales ranging from the microscopic scale of pores and individual sediment grains to the gigascopic scale of entire formations, it is extremely important for optimal implementation of improved recovery techniques to have knowledge of vertical and lateral changes in reservoir properties affecting fluid flow at all these scales. Boreholes are the traditional sampling points at which reservoir descriptive information can be obtained by direct measurement. Information pertaining to all the critical scales is available at the borehole, but the methods for obtaining it vary both in cost and effectiveness. Microscopic scale information on pore structure and rock composition is readily obtained from rock samples through coring. Ditch samples, cores, and wireline logs compared between wells can help establish major or large- scale changes in facies or formational architecture. There is, however, an important intermediate scale in reservoir description that must be observed and understood to link the large- and small-scale heterogeneities in meaningful ways and allow reservoir fluid flow patterns to be predicted with accuracy. This is the scale at which occur such heterogeneities as thin bed boundaries, stratification types, and other geological features of a similar scale. This is a scale at which information from boreholes has traditionally been difficult and expensive to collect. P. 603
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.94)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.95)
- North America > United States > Utah > Uinta Basin > Bluebell Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (34 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Borehole imaging and wellbore seismic (1.00)
Summary Data acquisition design and implementation challenges for mature reservoirs which are targets for Improved Oil Recovery (IOR) applications are discussed in this paper. Examples are provided for Shallow Shelf Carbonate (SSC) reservoirs in the Permian Basin of West Texas. What Are Mature reservoirs? Mature reservoirs are defined as properties with additional recovery potential by implementation of advanced reservoir characterization tools and techniques, reservoir management and/or changes in recovery mechanisms. Attributes of mature reservoirs are depicted in Figure 1, which shows the importance of reservoir characterization as a function of field development stage. Reservoir characterization and an understanding of heterogeneity become more important for maturing reservoirs as these factors have a profound impact on future reservoir development and management strategies. Mature reservoirs are typically characterized by some type of secondary drive mechanism. A change to a tertiary mode or implementation of other lOR methods may be necessary to extend the economic limit and productive life of the field. A team approach is also important to achieve data acquisition objectives in mature reservoirs. However, the data acquisition situation may be very different from that "new" reservoirs. The desire and need for IOR may be critical as the economic limit may be rapidly approaching and data required for IOR may not be available. Smaller reservoir size and lower remaining reserves may present economic constraints towards the acquisition of essential data for the implementation of many IOR methods. The lack of production, fluid properties and other data in the earlier stages of field development may present uncertainties in history matching with numerical simulation methods. This results in unreliable reservoir performance forecasts for IOR. Often, the implementation of data acquisition programs in mature reservoirs present opportunities to enhance near-term reservoir performance through effective reservoIr management. Data acquisition strategies for properties which are being considered for abandonment are not addressed in this paper. Redevelopment of these properties is often required to exploit behind pipe potential and undeveloped zones or horizons. INTRODUCTION - DATA ACQUISITION METHODOLOGY The data acquisition process for mature reservoirs can be segmented into two major areas:
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geophysics > Seismic 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)
- (22 more...)
Abstract This paper summarizes the comprehensive reservoir characterization effort for the foam pilot area and discusses the response to foam injection in the CO2 Foam Field Verification Pilot Test conducted in the East Vacuum Grayburg San Andre S Unit (EVGSAU) in New Mexico. A detailed study of the pilot pattern geology provided an understanding of the major controls on fluid flow in the foam pattern. Pattern performance data, falloff testing, profile surveys, and interwell tracer results were integrated into the geologic model to guide project design work and provide a framework for interpretation of foam performance. Localized regions of high permeability resulting from solution enhancement of the matrix pore system appear to be the primary cause of the early CO2 breakthrough and channeling of injected CO2 toward the problem production well in the foam pattern. Positive response to foam injection is indicated by reduced injectivity and injection profile data in the foam injection well; by results from time sequence monitor logging in the observation well; and by changes in production performance in the high GOR, "offending" production well in the foam pattern. Hall plots and pressure falloff testing were used to measure in situ changes in fluid mobility near the foam injection well. Time sequence logging responses at an observation well located 150 feet from the foam injector provided evidence of changes in fluid flow patterns in response to foam injection. Positive response to foam injection is further evidenced by changes in the CO2 production and oil rate performance at the "offending" production well in the foam pilot pattern. EVGSAU GEOLOGIC SETTING The Vacuum Field, located about 15 miles northwest of Hobbs in Lea County, New Mexico, is comprised of several large Units and leases. The East Vacuum Grayburg-San Andres Unit (EVGSAU) covers more than 7000 acres on the eastern side of the Vacuum Field. The primary productive interval at EVGSAU is comprised of the dolomitized carbonate sequences in the upper few hundred feet of the San Andres Formation, at a depth of approximately 4500 feet. The San Andres structure is an east-west trending anticline with more than 400 feet of closure above the original oil/water contact. The reservoir section is informally subdivided into a "lower" San Andres section and an "upper" San Andres section, separated by the more siliciclastic Lovington Sandstone Member. Stratigraphy and Lithofacics The San Andres reservoir section is comprised of a series of repeated, anhydritic, dolomitized, fining-upward, carbonate sequences composed of grain-rich dolostones which grade upward into dolomudstones. The subtidal, grain-rich carbonate facies form the primary reservoir units; the dolomudstones contain little effective porosity. Repetition of these depositional packages upwards through the formation results in a San Andres section composed of cyclical, shallowing/shoaling upward parasequences. Commonly occurring reservoir pore types include primary intergranular porosity, intercrystalline porosity (related to dolomitization), grain-moldic porosity, and vugular porosity. All of these pore types show varying degrees of solution enhancement. P. 163^
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.69)
- North America > United States > Texas > Permian Basin > Central Basin > Word Group > San Andres Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > San Andreas Formation > Upper San Andreas Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin > Upper Pennsylvanian > Vacuum Field > San Andreas Formation > Lower San Andreas Formation > Upper San Andreas Formation (0.99)
- (13 more...)
- 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)
- (3 more...)