Microbial carbonates developed in the Middle Triassic (Leikoupo Formation, Anisian Stage) of the western Sichuan Basin. The microbial components have been identified and include Renaclis-resembling , Rivularia lissaviensis , Carpathocodium anae , Hedstroemia moldavica , Bacinellacodium calcareus , and Paraortonella getica . These form stromatolitic, laminitic, thrombolitic, spongiostromata stones, dendrolites, and oncolitic structures. Microbial carbonate reservoirs occur in submember unit (SMU) 3-3 in the Zhongba area of the northern segment and SMU 4-3 in the middle segment of the western Sichuan Basin, both of which are of low porosity and permeability. Core descriptions and thin-section analysis show that reservoir porosity is mostly microbial coelom pores, framework pores, fenestral pores, and inter- and intraclot dissolved pores, within which the pores of ≥200 μm in diameter and throat of (40~50) μm are the most important. The SMU 4-3 microbial carbonate reservoirs are more thoroughly studied because of recent exploration activities, including the identification of three reservoir intervals. The middle reservoir interval, composed of thrombolitic and stromatolitic dolostone, hosts the reservoir of best quality. However, this high-quality interval loses effective porosity and thins to the northeast. It is proposed that extreme geological conditions, dolomitization, and burial dissolution influenced the development and distribution of the microbial carbonate reservoirs. The dolomitization process is thought to be penecontemporaneous to very early postdeposition. This early dolomitization contributed significantly to porosity of the microbial carbonate reservoirs and was likely enhanced through burial dissolution.

Pore systems in the Middle Permian Phosphoria Rock Complex (PRC), Rocky Mountain Region, USA, evolved with biotic and chemical dynamics in a shallow epicontinental seaway undergoing extreme environmental shifts. Biochemical responses to environmental changes directly affected pore systems and controlled diagenetic pathways through burial. Petrographic methods and spatially resolved measurements of δ 18 O in sequence stratigraphic context allow characterization of pore systems and their evolution in heterogenous biochemical sediments. Pore systems vary regionally and across systems tracts on second-order (9–10 million years [MY]) and third-order (2–5 MY) timescales. Minimal porosity occurs in transgressive mudrocks rich in organic matter (OM), phosphorites, and carbonates. Cool, acidic, low-oxygen, nutrient-rich basinal waters interacted with warm open to restricted shelfal waters in transgressions. This resulted in accumulation and microbial decay of S-rich OM, phosphatization, carbonate precipitation, silicification, as well as deposition of calcitic-biotic debris (bryozoans, brachiopods, and crinoids) and micrite. Relative to landward and highstand marine components, transgressive basinal marine carbonates and silica are δ 18 O depleted due to microbial decay of OM. Extensive cementation coupled with near-surface compaction and recrystallization of micrite occluded large portions of porosity in transgressive phosphorites and carbonates. Porosity in these rocks is dominated by interparticle and, to a lesser degree, intraparticle microporosity in microbored phosphatized and micritized grains. Phosphorites are compacted where cements are not pervasive. OM-rich sediments host minimal volumes of interparticle nanoporosity due to mechanical compaction and incursion of secondary OM (bitumen) during burial. PRC OM is S-rich, due to sulfate-reducing bacterial enrichment, and locally abundant. This drove early generation of secondary OM and inhibited OM-hosted porosity development through thermal maturation. Large volumes of porosity accumulated in highstand sediments and varied with transitions from silicisponge spicule cherts and calcitic-biota carbonates to pervasively dolomitized micritic, peloidal, aragonitic mollusk, and peritidal microbial sediments. These biochemical transitions, and ultimately pore-system evolution, were driven by interaction between oxygenated open marine waters, eolian siliciclastic debris, and increasingly restricted shelfal waters. Marine carbonate and silica δ 18 O are consistent with Middle Permian open marine waters but are enriched landward and through highstands with evaporative fractionation. This δ 18 O-enriched authigenic silica in carbonates and evaporite replacements, as well as δ 18 O enrichment through silica precipitation, suggest dolomitization and silicification were driven by evaporitic processes. In spiculitic cherts and siltstones, silicification and carbonate diagenesis resulted in small volumes of intraparticle, interparticle, and moldic porosity, as well as increased susceptibility to fracturing and associated permeability enhancement. Chalcedony in spiculites and silicified carbonates host minor volumes of porosity where moganite crystallites dissolved during hydrocarbon migration. Highstand dolomites host abundant intercrystalline, moldic, fenestral, and interparticle macroporosity and microporosity, especially in peloidal wackestones, mollusk debris, ooid grainstones, and peritidal microbialites. Dolomitization resulted in dissolution of aragonitic mollusk and ooids, cementation, and preservation of primary porosity. Porosity loss through burial in dolomites occurs through mechanical compaction, and to a lesser degree, precipitation of zoned carbonate cements that are δ 18 O depleted relative to earlier dolomite. Compaction strongly decreases intercrystalline porosity in dolomitized peloidal wackestones. Secondary OM related to hydrocarbon migration coats surfaces and fills small pore volumes, inhibiting burial cementation.

This study characterizes an Albian carbonate reservoir of oilfield B in the Campos Basin, based on geophysical well logs and laboratory petrophysical data. The use of current approaches to characterize reservoirs allowed us to estimate the porosity, permeability, and water saturation of this reservoir in a more reliable way than when this oilfield was discovered in 1976. To achieve this goal, the cluster analysis for rock typing module of the Interactive Petrophysics software was used to divide the succession into 11 electrofacies. Using log and laboratory data, an equation was derived to determine the porosity and the permeability of each electrofacies through the multiple linear regression technique. The results were compared with different models proposed by other authors, with the best results being found with multiple linear regression. Water saturation, on the other hand, was estimated by the Archie (The electrical resistivity log as an aid in determining some reservoir characteristics, Petroleum Transactions of AIME , 146:54–62, 1942) equation after identifying the cementation coefficient with the Pickett (A review of current techniques for determination of water saturation from logs, Journal of Petroleum Technology 18:1425–1433, 1966) cross plot. Finally, the porosity and permeability data were again used to identify three main flow units in the reservoir through the Winland (Oil accumulation in response to pore size changes, Weyburn field, Saskatchewan. Amoco Production Company Report F72-G-25, 20 p., 1972) graph. To verify the effectiveness of the adopted methodology, it was applied (successfully) in a test well, defining porosity, permeability, water saturation, and flow units, where laboratory data were absent.

Diligent reservoir characterization is the key to successful production in most unconventional plays. Unconventional resource plays require one to adapt to the scale of observation (1 nm to 1 μm) and to use special imagery techniques (e.g., scanning electron microscope [SEM], ion-milled SEM) to characterize the nature and classes of the pore system. For the Duvernay Formation, a quantitative approach to porosity typing and measurement was conducted on two- and three-dimensional focused ion beam SEM images. These images showed that between 69% and 85% of the porosity is kerogen porosity, with an average of 75% for the studied wells. It is important to recognize that although organic porosity is also developed in the less mature wells, the biggest pores were found in the most mature areas. These results indicate that there is a positive correlation between liquid yield and pore size, as well as a positive correlation between thermal maturity and pore size. The pore volume and/or the number of accessible pores increase (i.e., hydrocarbon in the pore volume and, thus, permeability) following the same trend as the mean pore size. It is concluded that the matrix porosity and, more importantly, the matrix permeability are primarily the result of thermal maturation of the kerogen. These results were not observed in previous studies due to an erroneous estimation of maturity using vitrinite reflectance, or a lack of appropriate diversity and quality of samples collected throughout the maturation phase windows to obtain statistically representative results. Subsurface data (wells, seismic), outcrop work from literature, and public domain production data from the West Shale Basin were integrated at the regional scale with this nanoscale pore-system characterization to define the hydrocarbon production potential of the Duvernay Formation.

In carbonates, fault zone architecture, distribution of different types of fault rocks in fault cores (e.g., breccias, cataclasites), and the interplay between deformation and diagenesis must be considered to predict the flow properties of a fault zone. We present the results of an integrated structural and petrophysical study of two carbonate outcrops in central Italy, where faults are known to act as dynamic seals at depth, causing ≈70 m of hydraulic head drop in a karstified groundwater reservoir. The architecture of these fault zones is very well exposed, allowing for detailed mapping of the along-strike and across-strike distribution and continuity of fault cores and associated fault rocks over a distance of ≈8 km. More than 150 samples, comprising several fault architectural elements and carbonate host rocks, were collected in transects orthogonal to the fault zones. Fault rock porosity and permeability were measured on 1-inch plugs and then linked to characteristic microstructures and fault rock textures. The results of this integration consisted of ranges of porosity and permeability for each type of fault rock. A trend of increasing comminution and decreasing pore size is evident from the outer toward the inner portions of fault cores. Three types of breccias (crackle, mosaic, and chaotic) and various types of cataclasites were identified. Crackle breccias show the highest plug permeabilities (up to hundredss of mD), whereas the ultracataclasites have the lowest plug permeability (down to 0.01 mD, which is roughly equivalent to unfractured host rock). These data reveal the interplay between various fault rocks and host rock permeability and the development of permeability anisotropy of fault zones in carbonates.

Oil and gas reside in reservoirs within peritidal and shallow subtidal lagoonal carbonate sediments across the globe. This is a zone of facies heterogeneity, controlled by changes in depositional energy, water depth, clastic influx, and evapotranspiration. Close proximity to evaporitic brine pools means that it is also an environment with the potential for dolomitization during shallow burial. As a result, the original pore system of carbonate sediment can become drastically altered prior to burial, such that reservoir properties may not be predictable from facies models alone. The Miocene Santanyí Limestone Formation, Mallorca, Spain, is well exposed and has undergone minimal burial and therefore presents an excellent opportunity to integrate sedimentology, facies architecture, and diagenesis to determine how porosity evolves within individual facies in the shallow subsurface. From here, the impact on pore type, pore volume, pore connectivity, and petrophysical anisotropy can be assessed. The Santanyí Limestone consists of pale mudstones and wackestones, rooted wacke-packstones, stratiform laminites, and skeletal and oolitic, cross-bedded grainstone. Thin-section analysis reveals a paragenetic pathway of grain micritization, followed by dissolution of aragonite, possibly by meteoric fluids associated with karstification. Subsequently, the unit underwent fracturing, compaction, recrystallization, cementation, dolomitization, and matrix dissolution to form vugs. Petrophysical analyses of 2.54-cm-diameter plugs indicate that these complex diagenetic pathways created petrophysical anisotropy [mean horizontal permeability (Kh)/vertical permeability (Kv) of whole formation = 3.4] and that measured parameters cannot be related directly to either geological facies or pore type. Instead, petrophysical data can be grouped according to the diagenetic pathways that were followed after deposition. The best reservoir quality (i.e., typical porosity 15 to >40% and permeability >100 mD) is associated with pale mudstones, stratiform laminites, and skeletal and oolitic grainstone that have undergone pervasive recrystallization or dolomitization. These rocks have the some of the lowest formation resistivity factor (FRF) values (<200) and thus the simplest pore system. The poorest reservoir properties ( k <10 mD) occur in mudstones and wackestones that have not been recrystallized and, hence, are dominated by a simple network of micropores (FRF <101). Skeletal and oolitic grainstones and rooted and brecciated wacke-packstones that have undergone some cementation and partial recrystallization have moderate reservoir properties and a high FRF (>>1000), reflecting a complex pore system of biomolds, vugs, and microporosity. Consequently, reservoir properties can be predicted based on their primary rock properties and the diagenetic pathway that they followed after deposition.

Shallow to deeply penetrating bioturbation by organisms on carbonate shelves can alter the original depositional texture of carbonate sediments, rearrange and modify the primary porosity and permeability patterns, and effectively increase the overall flow properties in multiple intervals. To explore the impact of bioturbation on reservoir quality and its spatial and vertical patterns, this study examined sedimentologically, ichnologically, and geostatistically ubiquitous bioturbated strata throughout outcrops of the Middle Jurassic Tuwaiq Mountain Formation and Upper Jurassic Hanifa Formation in central Saudi Arabia. Each lithofacies within the studied intervals had an ichnofabric index (ii) range from nonbioturbated (ii1) to beds completely homogenized by bioturbation (ii6). Most important was the occurrence of laterally extensive (>5 km) Glossifungites Ichnofacies, which represent firmgrounds with ii2 to ii5. These Glossifungites Ichnofacies are composed of complex and deep, three-dimensional Thalassinoides burrow networks (TBN) in mud-dominated lithofacies. These TBN have pore systems that consist of (1) open and partially open macropores (size of several centimeters), and (2) interparticle and moldic pores within the burrow filling, which consists of peloids, skeletal grains, and coated grains in a grain-dominated packstone texture. The TBN pore system, which typically penetrates the entire extent of the mud-dominated bioturbated beds, provides permeability pathways in an otherwise less permeable medium. Outcrop data and three-dimensional models suggest that these permeable pathways can contribute to overall reservoir flow in three ways: (1) TBN beds contribute to the overall reservoir flow as a single flow unit if bound above and below by impermeable beds (e.g., lateral flow in vertical well). (2) TBN breach the bed boundaries and, thus, connect above and below into more porous, more permeable grainy beds, providing overall reservoir connectivity for the carbonate reservoir and contributing to vertical and lateral flow. (3) TBN beds connect otherwise laterally compartmentalized reservoirs and contribute to vertical flow. Controls on the lateral and vertical variability of the TBN in the study area can be attributed to changes in water chemistry of the depositional environments, which are likely linked to global and local controls. This spatial and temporal relationship impacts the lateral and vertical distribution of flow properties of TBN strata in bioturbated reservoirs. Understanding such relationships is critical for secondary and tertiary recovery of oil by water flooding because such relationships can provide a prediction about the trend of vertical and lateral flow properties.

Natural fractures are common in the unconventional “Mississippian Limestone” play of the US Southern Mid-Continent region. Owing to their narrow width, vertical cores provide limited data on the distribution of fracture attributes (e.g., kinematic aperture, height, and spacing) in relation to fracture abundance. For the purpose of searching for an outcrop analog that provides an extensive view of lateral fracture distribution, this study uses an outcrop with Mississippian-aged strata in northwestern Arkansas. Targeting the Reeds Spring Formation, this study aims to characterize the type, attributes, and distribution of natural fractures and to test the outcrop’s suitability as a fracture analog for the subsurface. In the outcrop, planar and nodular beds of lime mudstone and chert contain near-vertical cemented fractures. Fracture types mainly include ptygmatic and opening-mode fractures. Ptygmatic fractures are the most common fracture type in both lime mudstone and chert, whereas the opening-mode fractures are present mostly in chert. Bedding structures, which are defined by lime mudstone–chert variations, affect fracture growth, as indicated by the observation that perfect bed-bounded, top- or base-bounded, and confined fractures collectively account for the majority of the fracture population. In terms of fracture intensity, chert shows a higher average value as compared with lime mudstone. Negative exponential and power law are present as the statistical patterns between cumulative frequency and fracture height, kinematic aperture, aspect ratio, and spacing. The best-fitting distribution pattern and the coefficient of determination vary with lithology, fracture type, and fracture height. These patterns likely point to a cooperative role of lithology, fracture type, and fracture-bedding relationships, as well as the dynamics of rock mechanical properties, in affecting these fracture attributes. In comparison with the cores, this outcrop may serve as a fracture analog for the Mississippian Limestone play in northernmost Oklahoma–southernmost Kansas where cherty facies are widespread, but not for the play areas in north-central Oklahoma, which are dominated by mixed carbonate–siliciclastic facies.

Although carbonate reservoirs often have high total pore volumes, permeability often does not show a strong correlation to total porosity. Carbonate pore networks are also widely recognized as being highly heterogeneous, with marked variability in pore size (from submicron to millimeter scale and above) within an individual core plug. It is perhaps for this reason that there has been relatively little quantification of carbonate pore size and shape, despite significant advances in our ability to image naturally porous media using electron microscopy and advanced X-ray imaging. This study focuses on four samples of limestone from the uppermost Shuaiba Formation in northern Oman. These samples were selected for X-ray computerized tomography (CT) and environmental scanning electron microscope (ESEM) imaging and quantitative analysis following a detailed reservoir quality evaluation of the study interval across seven fields. This interval has been well studied sedimentologically, but the processes and timing of diagenetic modification, and the nature of the resultant pore network are less well understood. The samples represent a range of lithofacies associations that occur immediately beneath the Shuaiba–Nahr Umr unconformity, within an interval that is recognized for possessing higher permeability than the underlying reservoir. The samples were imaged at multiple scales, and their pore network was analyzed. Within the sample set, over 70% of the total pore volume was <1 μm in diameter. The three-dimensional (3D) equivalent pore radii within individual samples ranged from <0.1 μm to >100 μm, with the size of the X-ray imaged samples being limited to 1 mm 3 . The average aspect ratios of all pores was <2, and it was highest in micropores (<1 μm pore radii). Mean coordination number was <3 in all samples, and it was highest within micropores. Since most pore throat radii are <1 μm, this most likely reflects the higher resolution needed to image micropores. Multivariant analysis shows that permeability prediction is improved when pore topological parameters are known. The highest measured permeability within the data set occurred in the sample with the highest volume of resolved porosity, highest aspect ratio, and highest coordination number. However, average permeability overall was highest in those facies associations with abundant macropores, where the representative elemental volume is greater than the sample size required for X-ray CT analysis and even routine core analysis. In these samples, high permeability is facilitated by the connectivity of a low volume of large (>>30 μm) pores embedded within a network of micropores. In these samples, sweep efficiency during hydrocarbon production is likely to be poor. The results of this study provide one of the first detailed data sets of 3D pore shape and size within this volumetrically important reservoir and insight into pore connectivity within microporous reservoirs on the Arabian Plate. The results provide good evidence that the >1 μm fraction of these rocks contributes to single-phase flow, but they demonstrate the complexity of pore shape even at the micron scale.

This article investigates the relationship between rock properties (composition, porosity, and pore architecture) and dry ultrasonic P-wave velocity ( V P ) of 14 samples representing three facies of the Mid-Continent Mississippian-age Limestone (Miss Lime) units of North–Central Oklahoma. Generally, in carbonate rocks, what drives V P , in addition to bulk porosity (ϕ) and composition, is not straightforward to determine. In this data set, when samples are categorized based on their facies and composition (quartz fraction), V P shows a better trend with dominant pore size rather than ϕ. Results show the dependence of elastic properties on texture and highlight a need for incorporating pore-size distribution in seismic models used for seismic interpretation of low-permeability reservoirs such as the Miss Lime.

Petrophysical characterization and understanding of pore systems and producibility in unconventional reservoirs remains challenging when evaluating reservoir potential. This study’s main objective is to identify and evaluate the controls on petrophysical rock types in unconventional low porosity, low permeability carbonate reservoirs in Mississippian-aged rocks of the southern Midcontinent. Representative samples selected from cores in the study area are calcareous siltstones and grain-rich packstones to grainstones. Rock fabric, pore types, and pore structure of 23 samples were investigated using multiscale image analysis of optical micrographs and scanning electron microscope (SEM) mosaics. Petrographic observations and quantified pore parameters were correlated with nuclear magnetic resonance (NMR) plug measurements of transverse relaxation times ( T 2 ), pore size distribution, and porosity. Results indicate that pore structure, permeability, and NMR response are closely linked to the dominant pore types, pore sizes, and mineralogy, which are distinctive for specific rocks—allowing for petrophysical rock type (PRT) grouping. NMR signature geometry is distinct in each of these rock type groups. Complex mixed mineralogies in these rocks homogenizes porosity and permeability relationships among rocks of different depositional facies, making it difficult to define clear-cut correlative relationships between pore architecture, rock fabric, and petrophysical response. Petrographic assessment indicates that the primary cause of pore-scale heterogeneity and varying petrophysical response is related to postdepositional diagenesis, such as silicification, cementation, dissolution, and mineralization along pores and pore throats, which produce complicated pore systems and affects matrix permeability. These observations confirm that incorporating geologic information such as mineralogy, diagenesis, and pore types/pore architecture into rock typing workflows in carbonate mudrock reservoirs is critical to understanding petrophysical response. Additionally, the distinct geometries in each petrophysical rock type group establishes the viability of using NMR as a rock typing tool based on the correlative relationships between NMR response, pore types, and facies.

Marine low-magnesium calcite concretions are widespread in many siliciclastic and mixed carbonate–siliciclastic shelf and basinal settings. The process of concretion formation is generally well established and involves microbial influence (mostly sulfate reduction to oxidize organic material at or just below the seafloor). The microbes produce interstitial fluids that are conducive to abundant, and apparently rapid, precipitation of calcite cements. Pervasive cementation generates well-indurated beds or isolated flattened “pods” that are commonly confined to specific stratigraphic horizons. Stratabound concretions can be important as fluid-flow barriers during subsequent burial and compaction. Thin-section and scanning electron microscopy of Cenozoic and Mesozoic concretions has revealed a dense occurrence of small (mostly 2–10 μm), equant, mostly subhedral calcite crystals. The best resolution of both techniques is, however, unable to adequately characterize crystal boundaries, the distribution of clays or organic matter, or the nature of the pores within the calcite matrix. Here, we used scanning electron microscopy to examine ion-micromilled surfaces of concretions from Upper Miocene and Upper Jurassic strata. Results indicate that the dominant crystal size is 1 to 3 μm (mean 2.08 μm; standard deviation = 1.42 μm). Pores were formed at the intersections of calcite crystals by the constriction of the fluid-filled interstitial space, likely prior to dewatering and initial compaction. These (micro) pores are of the “type III, fitted fused” variety. Two-dimensional pore shapes analyzed on micromilled surfaces are near-equidimensional (length/width = ~1–1.5), oval (length/width = 1.5–5), and elongate (length/width = >5) forms. Equidimensional and oval pores occur at the intersections of calcite crystals (along with clay minerals and organic material). Elongate pores of uncertain origin are found at the boundaries between adjacent calcite crystals. The helium pycnometer porosity of the plugs associated with the Upper Jurassic micromilled sample is consistent with a relatively low total porosity, with values of 0.38, 0.58, and 0.82%. Micromilled surfaces improve our understanding of two-dimensional crystal structure and porosity within the matrix of marine concretions. The size and shape of cement crystals and pores suggest that relatively early, rapid, and pervasive precipitation produced a homogeneous mass of calcite and small isolated pores. The resultant low porosity and permeability formed a rock that was diagenetically stable and resistant to chemical and physical modification later during burial.

Automated scanning electron microscopy image collection from geological polished thin sections, in conjunction with autonomous stitching, can be used to construct high-resolution (micron- to submicron-resolution) image montages over areas up to several square centimeters. The technique is here applied to an oolitic limestone and a carbonate laminite to illustrate its application as a tool to study carbonate porosity and diagenesis. Montages constructed from backscattered images are ideally suited to the extraction of data on microporosity, with possibilities including the construction of contoured maps to illustrate the spatial variation in porosity; the construction of porosity logs to illustrate trends in porosity across thin sections; and stochastic construction of digital rock models, for subsequent permeability calculation. Montages taken with a gaseous secondary electron detector in low-vacuum mode can utilize charge contrast imaging (CCI) at a variety of scales and were used here in examining the evolution of carbonate cementation. One example is oolitic limestone, illustrating the formation of grain-lining and pore-occluding cements, as well as recrystallization of the depositional fabric. CCI montages commonly suffer from a variety of contrast and brightness artifacts due to variation in charge distribution across the individual scanned image tiles. Several remedies are discussed that can reduce these artifacts, making it easier to apply image analysis techniques across such montages.

The measurement of porosity and permeability in shallow-water carbonates is often complicated by the nature and degree of diagenesis, as well as the issue of scale-dependence in the measurement technique. Vertical profiles of hydraulic conductivity were calculated from short-interval straddle-packer injection tests in a three-well transect across the Pleistocene reefal limestone of the southern Dominican Republic (DR). Combined with whole-core porosity estimates and small-diameter (2.54 cm) plug estimates of matrix porosity and permeability, these data provide a means of assessing the scale-dependent petrophysical variability within a complex carbonate pore system, as well as the primary factors that control flow within such a system. Interval permeability values (converted from hydraulic conductivity) based on in situ injection tests ranged between 5 and 25 Darcy (D) (12.2 D geometric mean), up to three orders of magnitude higher than associated plug permeability values (0.08 D geometric mean). Although plug permeability is related to depositional environment (backreef, reef crest, forereef), injection tests did not show a relation to environment. Furthermore, interval permeabilities showed no relation to “matrix” (plug-based) porosity or permeability values. Interval injection permeability was correlated to “total” (whole-core) porosity and, even more so to larger scale “vuggy” (>~5 mm) porosity, quantified by subtracting the plug-based “matrix” porosity from the whole-core “total” porosity. The differences in permeability between plug and interval injection tests for these vuggy carbonates becomes greater over time, since cementation occludes matrix porosity and dissolution opens up larger molds and vugs, especially corals and other large aragonitic grains. The in situ interval permeability values measured in the DR reefal carbonates provide better values (than plug or core) of the impact of early meteoric diagenesis. These results confirm early development of vuggy intervals that can have permeability that is orders of magnitude greater than measured plug permeabilities. A touching-vug pore system shifts the scale dependence of hydraulic conductivity from the plug scale to the packer (bed) scale and probably toward the regional scale.

Understanding reservoir performance and predicting hydrocarbon recovery in carbonate reservoirs are challenging due to the complexity of the pore system and the dynamic interplay of multiphase fluids that move through the pore network. A multiyear study of carbonate reservoirs across a broad spectrum of geologic conditions, fluid types, and field maturities has resulted in key insights on the links between pore-system characteristics and dynamic fluid-flow behavior with material relevance to carbonate resource assessment, field development optimization, and maximizing ultimate recovery. Pore-system heterogeneity is a primary control on hydrocarbon displacement efficiency. Multiphase flow through heterogeneous pore systems with a mix of pore types results in lower recovery than flow through more homogeneous pore systems. Due to the homogeneous nature of the micropore system, rocks dominated by micropores can have favorable hydrocarbon displacement with residual oil saturation to water displacement (Sorw) less than 5%. Rocks with a heterogeneous mix of interparticle and micropores have less favorable displacement, with Sorw as high as 20%, despite having higher permeability. A threshold of approximately 80% microporosity appears to distinguish: (1) more favorable displacement in micropore-dominated rocks vs. less favorable displacement in rocks with a mixed pore system, (2) the magnitude of permeability for a given porosity in mixed vs. micropore systems, and (3) the proportion of microporosity above which pore space of any type is connected exclusively through the micropore network and flow properties reflect the homogeneous nature of that pore system. Within the homogeneous micropore system, Sorw increases from about 5% to 20% as porosity and permeability decrease and micropore type transitions from type 1 (higher quality) to type 2 (lower quality). A major control on multiphase fluid movement in reservoirs with interlayered mixed and micropore-dominated flow units is the contrast in capillary pressure (Pc) and water relative permeability (Krw) between these distinct pore systems. When compared on a consistent basis, 60% water saturation, for instance, rocks with a mixed pore system have approximately neutral (0 psi, 0 kPa) Pc values and higher Krw values, whereas rocks dominated by microporosity have more strongly negative (−6 psi, (−41 kPa) Pc values and lower Krw values. In the case of a water flood operation, this contrast in Pc and Krw can lead to more heterogeneous sweep patterns and lower recovery. A new method for tagging in-place oil with xenon was coupled with flow-through micro-computed tomography imaging to directly investigate oil displacement under water flood conditions. The results provide a qualitative demonstration of how brine flooding displaces xenon-saturated oil. Displacement patterns in micropore-dominated rocks are homogeneous and compact with limited bypass of oil, consistent with relatively low Sorw. Conversely, the displacement pattern in rocks with a mixed pore system is more heterogeneous and exhibits significant regions of bypassed oil, consistent with higher Sorw and Krw.

Carbonate reservoirs are often comprised of a heterogeneous pore system within a matrix of variably distributed minerals including anhydrite, dolomite, and calcite. When describing carbonate thin sections, it is routine to assign relative abundance levels to each of these components, which are qualitative to semiquantitative (e.g., point counting) and vary greatly depending on the petrographer. Over the past few decades image analysis has gained wide use among petrographers; however, thin-section characterization using this technique has been primarily limited to quantifying the pore space due to the difficulty associated with optical recognition beyond the blue-dyed epoxy associated with the pores. Here, we present a new method of computerized object-based image analysis (Quantitative Digital Petrography: QDP) that relies on a predefined rule set to enable rapid, automated thin-section quantification with limited interaction of a petrographer. We have developed a novel work flow that automatically isolates the sample on a high resolution (i.e., <1 μm/pixel) scanned thin section, segments the image, and assigns those segments to predefined categories; e.g., pores, cement, and grains. With this technique, statistically relevant numbers of thin sections can be rapidly batch processed and quality controlled, thereby allowing quantitative data from conventional core analysis, special core analysis, and reservoir surveillance to be integrated with the petrographic data for a more dynamic description of the carbonate rock. Our technique can also incorporate multiple layers, such as cross-polarization, backscatter electron imaging, and elemental maps, which allow additional information to be easily integrated with results from QDP. The QDP approach is a significant improvement over previous digital image analysis methods because it (1) does not require binarization, (2) eliminates the subjectivity in assessing abundance levels, (3) requires less interaction with a petrographer, and (4) provides a much fuller dataset that can be incorporated across an entire well or field to better address common challenges associated with carbonate reservoir characterization, such as understanding pore type and cement abundance, pore connectivity, grain distribution, and reservoir flow characteristics.