Thin Section Porosity Research Articles

Determination of porosity types from NMR data and their relationship to porosity types derived from thin section

Pore size frequency distributions can be derived from Nuclear Magnetic Resonance (NMR) longitudinal relaxation measurements ( T 1) on water saturated plugs. This paper discusses the cross validation of NMR T 1 relaxation distributions of porosity and how they are related to distributions obtained from image analysis of porosity in thin section. Both sets of distributions are polymodal and decomposition of each yields porosity types. Each pore type represents a subdistribution of pores with a characteristic size and shape. The mean T 1 values associated with the NMR pore types are linearly related to the mean size of pore types determined from image analysis. The constant of proportionality of this relationship represents the surface relaxivity (ρ), a parameter that represents the enhancement of relaxation caused by nuclei interacting with the pore wall. The major difference between image analysis and NMR methods is that NMR can resolve much smaller pores. The relationships between pore types and throat sizes using NMR generated pore types are the same as that using image analysis generated pore types. The existence of a strong relationship between pore type and throat size ensures the relevance of NMR data in studying the properties associated with single and multiphase flow.

Artifact porosity in thin sections of sandstones : Pittman, E D J Sediment PetrolV62, N4, July 1992, P734–737

Artifact porosity in thin sections of sandstones : Pittman, E D J Sediment PetrolV62, N4, July 1992, P734–737

Artifact porosity in thin sections of sandstones

Artifact porosity in thin sections of sandstones

Petrography and reservoir physics II: relating thin section porosity to capillary pressure, the association between pore types and throat size : McCreesh, C A; Ehrlich, R; Crabtree, S J Bull Am Assoc Petrol GeolV75, N10, Oct 1991, P1563–1578

Petrography and reservoir physics II: relating thin section porosity to capillary pressure, the association between pore types and throat size : McCreesh, C A; Ehrlich, R; Crabtree, S J Bull Am Assoc Petrol GeolV75, N10, Oct 1991, P1563–1578

Depositional Environments, Petrology, and Fractures of the Lower Atoka Davis"Sandstone, A Low-Permeability Gas-Bearing Sandstone of the Fort Worth Basin, North-Central Texas"

The gas-bearing Pennsylvanian 'Davis' sandstone, also called the 'Pregnant' shale, consists of several stacked coarsening-upward depositional packages that formed in wave-dominated deltaic environments. In northwestern Parker County, the Davis consists of an upper 100-ft-thick (30-m-thick) sandstone-rich unit deposited in prodelta, delta-front, and channel-mouth-bar environments. This upper unit overlies about 150 ft (45 m) of older Davis shale and siltstone deposited as prodelta and distal delta-front facies of older deltas that did not prograde as far west-northwestward as did the upper deltaic package. Sandstones exhibit mostly ripple cross-laminations and some planar cross-bedding. Quartz, plagioclase, and metamorphic rock fragments are the most abundant detrital grains. Thin-section porosity ranges up to 6%, porosimeter porosity is generally less than 8%. Matrix permeability is mostly less than 0.1 md, although natural fractures may contribute to higher local permeability. Natural fractures ranging in height from a few inches to 1 ft (30 cm) occur in core from wells located in areas that lack mappable folds and faults. Fractures are most common in sandstone beds, although some cut shale layers interbedded in sandstone. Calcite commonly partly fills the fractures. Understanding the variability in depositional facies, diagenesis, and natural fracture distribution can aid in predicting zones having themore » best permeability and in determining appropriate production methods in this low-permeability sandstone.« less

Petrography and Reservoir Physics II: Relating Thin Section Porosity to Capillary Pressure, the Association Between Pore Types and Throat Size (1)

Porosity in reservoir rocks is configured into a few types of pores whose size and shape are controlled by depositional fabric and postdepositional processes. The size, shape, and abundance of each pore type can be objectively determined from thin section using image analysis and pattern recognition procedures. Each pore type tends to be associated with a limited range of throat sizes. The association between pore type and throat size can be determined using regression procedures linking pore type data obtained from thin section with capillary pressure data. To do so, a set of samples is required wherein the association between pore type and throat size is fixed, but where pore type proportions vary between samples. This condition is met by a sample suite representing res rvoir facies from a single core or, in many cases, from a single field. The relationship between pore type and throat size is an effective means to relate reservoirs in terms of the efficiency of the porous microstructure to multiphase flow. Parameters derived from the relationship can be used to construct accurate physical models that subdivide physical response in terms of the contributions of each pore type.

Diagenesis of Sandstones at Shale Contacts and Diagenetic Heterogeneity, Frio Formation, Texas (1)

Diagenetic trends near sandstone/shale contacts were studied in 12 cored sequences from four wells between depths of 5200 and 15,700 ft (1585 and 4785 m) to evaluate the heterogeneity of diagenetic processes on a local scale and to evaluate the hypothesis that reactive aqueous fluids and components for cements in sandstones were derived from adjacent shales. The only evidence suggesting that diagenetic components in sandstones were derived from immediately adjacent shales is an increase in chlorite cement in sandstones toward contacts with shale beds for two of three contacts appropriate for study. Secondary pores and cements of quartz, carbonate, and kaolinite do not correlate with proximity to shale beds, but have a preference for sandstones that had relatively high ini ial porosities and permeabilities. Thus, the flux of formation water and probably long-distance transportation of diagenetic components were more important influences on reservoir quality of sandstones than was the local availability of components. Multiple regression of 22 independent variables indicates that the best predictors of secondary porosity are kaolinite cement and intergranular porosity. Sandstone sequences are extremely heterogeneous in the distribution of total thin section porosity, secondary porosity, and quartz and carbonate cements; in addition, they have significant variations in the abundance of kaolinite and chlorite cements. Mass balance calculations for silica and aluminum indicate silica was imported to and aluminum was exported from the sandstones.

Diagenetic Control of Reservoir Quality of Araba and Naqua Diagenetic Quartzarenites (Cambrian), Gebel Araba-Qabeliat, Southwest Sinai, Egypt

Sandstones of the marine Lower Cambrian Araba Formation and the overlying fluvial Upper Cambrian( ) Naqus Formation in Gebel Araba-Qabeliat, southwest Sinai (the eastern side of the Gulf of Suez) were studied to evaluate the major factors controlling potential hydrocarbon reservoir quality. The formations have a composite thickness of 873 m and overlie Precambrian granite and metamorphic rocks and underlie Cretaceous marine strata. The framework composition of both sandstones is almost entirely quartz with trace amounts of muscovite, K-feldspar, and heavy minerals. Up to 21.5% oversize pores, some filled with younger cements, attest to extensive dissolution loss of detrital grains, chiefly feldspar. Because the final mineralogical maturation of these quartzarenites was through diagenesis, they are diagenetic quartzarenites. Following deposition, the introduction of thin coatings of infiltered clay was followed by the precipitation of 6.3% unhomogeneously distributed quartz cement. Some outcrop samples contain pore-occluding gypsum cement or mixtures of gypsum and halite cement. Sr{sup 87}/Sr{sup 86} ratios of seven samples of gypsum cement have values (0.7077 to 0.7083) that are equal to Miocene and slightly younger seawater. These Cambrian sandstones have excellent reservoir potential (mean thin section porosity = 25.7%) because they contained few ductile grains to enhance compaction, and theymore » developed significant amounts of secondary pores by both dissolution of calcite cement and unstable detrital grains. Kaolinite and dickite are potential problems for hydrocarbon production in some beds.« less

The Medicine Hat Gas Field: A Large Upper Cretaceous Reservoir in Southeastern Alberta

The Medicine Hat gas field is the largest in Alberta, with estimated initial gas reserves of 3485 bcf. About half the reserves occur in the Medicine Hat A sand. This formation grades upward from a basal mudstone into siltstone and very fine grained sandstone, often capped by a thin layer of coarser granules which mark the base of overlying transgressive strata. The present shallow burial (450-525 m) and limited compaction are key factors in reservoir quality. Porosity is mainly of primary intergranular and interparticle micropore types, with core values ranging from 20 to 37%. Permeabilities range from 10 to more than 500 md. Divergence between core analysis porosity values (higher) and thin-section porosity values (lower) is attributed to high volumes of microporosity in the lightly compacted clay fabrics of the matrix and mudstones. This microporosity is read by logging tools as well as core analysis and results in high irreducible water saturation. Interstitial water saturation, derived from oil-based cores, ranges from 38 to 52.5%. Net pay was determined using an 8-ohm resistivity cutoff after normalizing to shale; then a net-to-gross ratio was established for each well with CNL-CDL logs using a density-neutron crossplot. This paper describes a gas reserve evaluationmore » conducted volumetrically using log, core, and selective perforation test data and compares such estimates to those from production performance and material balance.« less

Compaction and Porosity Evolution of Pliocene Sandstones, Ventura Basin, California: REPLY

Sandstones of the Pico and Repetto formations were studied to quantify the processes involved in compaction and to determine the porosity evolution of the beds during burial. The sandstones are mineralogically immature and, except for local carbonate-cemented beds, have insufficient cement to have prevented compaction. Stratigraphic studies and graphic porosity-depth plots suggest that the samples' maximum burial depths were approximately 10,000 ft (3,048 m) deeper than the present-day depths of 850-13,000 ft (259-3,962 m). Compaction produced closer grain packing as measured by the contact index (CI = average number of contacts per grain) and tight packing index (TPI = average number of long, sutured, and embayed contacts per grain). For samples with less than 10% cement the CI depth gradient is 0.21/1,000 ft (0.69/1,000 m) and TPI depth gradient is 0.27/1,000 ft (0.89/1,000 m). Assuming sands had 40% initial porosity, the sandstones that are at present most deeply buried lost a total absolute porosity of 26% by all compactional processes, which includes 14% by grain rearrangement and 6% each by pressure solution and ductile grain deformation. Porosity loss by nondeformational grain rearrangement was complete by a present-day depth of 5,000 ft (1,524 m), but in uncemented sandstones pressure solution (plus associated grain rearrangement) and ductile grain deformation continued to the maximum depths sampled. Compaction is most abrupt in sands with abundant micas and ductile rock fragments. The CI gradient is 0.14/1,000 ft (0.46/1,000 m) for samples with ess than 10% ductile grains, but 0.22/1,000 ft (0.72/1,000 m) for samples with more than 10% ductile grains. Compaction was almost entirely the result of overburden pressure and was not noticeably retarded in overpressured zones, suggesting that overpressures developed after maximum burial was achieved. For samples with less than 10% cement, the CI is a better depth predictor than the TPI (r2 = 0.58 vs. 0.45), but the TPI is a better predictor of pre-cement porosity than the CI (r2 = 0.54 vs. 0.31). Secondary porosity averages 20-40% of the total thin-section porosity. Secondary porosity is present at all depths, but makes up the greatest percentage of total porosity between present depths of 6,000 and 9,500 ft (1,829 and 2,896 m). Except for grain fracturing, secondary porosity formed only by dissolution of framework grains. Fractured-grain porosity contributes up to 29% of total porosity (5% absolute porosity) in some samples; fractures formed during Pleistocene tectonic episodes.

Petrography Stable-Isotope Geochemistry and Diagenesis of Miocene Sandstones, Vermilion Block 31, Offshore Louisiana: ABSTRACT

ABSTRACT Sandstones from three conventional cores between depths of 11,140 and 14,910 feet currently have an average composition of Q86F10R4, but have lost approximately 5 percent feldspar to replacement by carbonates and to dissolution. Like other deeply buried Gulf Coast sandtones, plagioclase is being albitized and K-feldspar is dissolving. Patterns of feldspar distsribution in the deeper cores suggest that tight cementation by calcite retarded feldspar diagenesis and that waters of different composition or temperature must have invaded different sandstone beds in close proximity. Calcite, quartz and chlorite are most responsible for causing deterioration of reservoir quality. Calcite volume averages 4.8 percent and occludes all pores in samples containing more than 5 percent calcite. Textural relations and isotopic data indicate that calcite precipitated over a broad temperature range and from fluids of variable composition during burial. The 87Sr/86Sr ratio of cements is consistent with the derivation of the Sr from coeval, or only very slightly older skeletal material, prior to extensive silicate reactions. The volume of quartz cement ranges from 0 to 14 percent (mean - 5%) and is selective to coarser, cleaner sandstones that had the highest permeability. 18O values of quartz overgrowths (34.2 SMOW) suggest that quartz cement precipitated between temperatures of 35° to 50° C from water having a 18O of about +3+1.5 . Silica for quartz cement was largely imported because there is negligible pressure solution of silicate grains and the amount of silica released from feldspar alteration is insufficient to account for the present quartz volume. Chlorite is not abundant and its diagenesis is complex, including two stages of precipitation and a later stage of dissolution. The first episode of precipitation formed thin grain coats that rarely inhibited quartz cementation. A later episode partly filled both primary and secondary pores and strongly influenced permeability. Total thin section porosity ranges from 0 to 31 percent and averages 16 percent. Of total pores, 75 percent are intergranular, 17 percent are oversize pores inferred to have formed by feldspar dissolution, 6 percent are intragranular pores, 1 percent are oversize pores developed by fossil dissolution, and a trace are micropores within clay clasts, glauconite, rocks fragments and clay cements.

Compaction and Porosity Evolution of Pliocene Sandstones, Ventura Basin, California

Sandstones of the Pico and Repetto formations were studied to quantify the processes involved in compaction and to determine the porosity evolution of the beds during burial. The sandstones are mineralogically immature and, except for local carbonate-cemented beds, have insufficient cement to have prevented compaction. Stratigraphic studies and graphic porosity-depth plots suggest that the samples' maximum burial depths were approximately 10,000 ft (3,048 m) deeper than the present-day depths of 850-13,000 ft (259-3,962 m). Compaction produced closer grain packing as measured by the contact index (CI = average number of contacts per grain) and tight packing index (TPI = average number of long, sutured, and embayed contacts per grain). For samples with less than 10% cement the CI depth gradient is 0.21/1,000 ft (0.69/1,000 m) and TPI depth gradient is 0.27/1,000 ft (0.89/1,000 m). Assuming sands had 40% initial porosity, the sandstones that are at present most deeply buried lost a total absolute porosity of 26% by all compactional processes, which includes 14% by grain rearrangement and 6% each by pressure solution and ductile grain deformation. Porosity loss by nondeformational grain rearrangement was complete by a present-day depth of 5,000 ft (1,524 m), but in uncemented sandstones pressure solution (plus associated grain rearrangement) and ductile grain deformation continued to the maximum depths sampled. Compaction is most abrupt in sands with abundant micas and ductile rock fragments. The CI gradient is 0.14/1,000 ft (0.46/1,000 m) for samples with ess than 10% ductile grains, but 0.22/1,000 ft (0.72/1,000 m) for samples with more than 10% ductile grains. Compaction was almost entirely the result of overburden pressure and was not noticeably retarded in overpressured zones, suggesting that overpressures developed after maximum burial was achieved. For samples with less than 10% cement, the CI is a better depth predictor than the TPI (r2 = 0.58 vs. 0.45), but the TPI is a better predictor of pre-cement porosity than the CI (r2 = 0.54 vs. 0.31). Secondary porosity averages 20-40% of the total thin-section porosity. Secondary porosity is present at all depths, but makes up the greatest percentage of total porosity between present depths of 6,000 and 9,500 ft (1,829 and 2,896 m). Except for grain fracturing, secondary porosity formed only by dissolution of framework grains. Fractured-grain porosity contributes up to 29% of total porosity (5% absolute porosity) in some samples; fractures formed during Pleistocene tectonic episodes.

Diagenesis of Eolian and Fluvial Feldspathic Sandstones, Norphlet Formation (Upper Jurassic), Rankin County, Mississippi, and Mobile County, Alabama

Norphlet sandstones in seven cores from Mississippi and Alabama are arkoses and subarkoses deposited in eolian-dune, interdune, and fluvial environments. Similar to the deeply buried (> 5 km) Tertiary feldspathic sandstones of the Gulf basin, all detrital plagioclase that survived dissolution has been albitized. However, some K-feldspar, instead of dissolving, was stabilized by K+-rich brines derived from adjacent evaporites. This K-feldspar then developed extensive overgrowths. Fluvial red sandstone lost all initial porosity by the introduction of preburial pedogenic calcite and compaction. Initial porosity of eolian sands was reduced by compaction to an average of 29%; and later by cementation by quartz, carbonates, anhydrite, halite, K-feldspar, and illite. Quartz and anhydrite cements precipitated between 90° and 100°C (approximately 2.3 km deep), carbonates and halite cements formed below 120°C (< 3 km), and late-stage illite cement formed between 130° and 150°C (4-5 km deep). Cements are patchy, and some, especially quartz and anhydrite, are texture-selective, being more abundant in coarser laminae. Secondary porosity, which makes up approximately half the porosity in thin sections, formed by dissolution of detrital grains (f ldspar, rock fragments) and cements (anhydrite, carbonate, halite). Reservoir bitumen records an early phase of oil entrapment. Reservoir quality is influenced by the abundance of reservoir bitumen and thread-like illite, both of which bridge pores. The radiometric age of illite (approximately 55 Ma) probably reflects its cementation age, but may also record a later recrystallization event. Depleted oxygen and carbon isotopic values for ferroan dolomite reflect the progressive replacement of earlier, more enriched carbonate phases by higher temperature phases. Isotopic data suggest that during the first 30 to 40 m.y. of burial, subsurface diagenesis of the Norphlet Formation was dominated by deep-circulating, hot, meteoric water. This phenomenon may be characteristic of the early diagene ic history of rifted basins.

Comparative Petrography of Two Upper Devonian Oil Sands of Warren County, Pennsylvania: ABSTRACT

The Glade sand and Clarendon sand are Upper Devonian shoestring sands occurring at relatively shallow depth, in most places not exceeding 1,500 ft (457 m). Both are producers of Penn Grade crude oil, having been discovered before the turn of the century. Data for this study are derived from four independent sources, namely the petrographic microscope, image analysis instruments, the X-ray diffractometer, and geophysical (nuclear and electric) log data. Special emphasis is given to grain shapes, grain sizes, primary and secondary mineral compositions (including matrix constituents), rock textures, and the relationship of permeability and porosity in thin section to geophysical data. Compositionally, the Glade and the Clarendon are very-fine to medium-grained low-rank grayw ckes with variable amounts of muscovite, biotite, chert, plagioclase feldspar, orthoclase feldspar, and carbonates. The Clarendon, however, is predominantly more silty throughout. Porosity in thin section is measured on the basis of its ratio to the total area of the rock being examined. Permeability, however, is described in terms of the relative interconnectivity of pore space and its tortuosity. In the end, correlation of these petrographic features with geophysical data aids in interpreting the rocks' characteristics. End_of_Article - Last_Page 566------------

Importance of Secondary Porosity in Sandstones to Hydrocarbon Exploration: ABSTRACT

Terrigenous sandstones in many basins owe their reservoir quality to secondary porosity that developed by the dissolution of detrital framework grains (chiefly feldspar) and cement minerals (chiefly calcite and evaporite minerals). This dissolution event is responsible for changing tight sandstones to porous and permeable sandstones slightly prior to the major episode of hydrocarbon migration. Dissolution of most non-evaporite minerals is accomplished by formation water containing carbon dioxide generated during the thermal or bacterial breakdown of hydrocarbons. Dissolution porosity is commonly well developed at 6,000 to 9,000 ft (1,829 to 2,743 m), but gradually is lost during deeper burial stages by recementation (chiefly by ferroan calcite, ferroan dolomite, and kaoli ite). During sandstone burial, variations in the simple scheme of cementation ^rarr decementation ^rarr recementation is complicated in basins with complex plumbing systems and those that experience uplift. For example, dissolution porosity in some uplifted sandstones develops during invasion by meteoric water flowing downdip. Dissolution porosity in sandstones can be suspected from certain log responses and water-saturation characteristics, but is best identified from clues visible in thin sections made of dyed, epoxy-impregnated perm plugs. Clues to secondary porosity in thin section include: (1) oversized pores formed where framework grains have been dissolved; (2) patchy distribution of carbonate or evaporite cement; (3) honeycombed feldspar grains; (4) fossil molds; (5) grains whose margins were etched by previous cement; (6) broken silicate grains that formed when rapid compaction followed removal of cement minerals; and (7) quartz grains that have been reduced to shards when calcite, which invaded quartz along hairline fractures during cementation, was dissolved. Secondary porosity is not likely to d velop good reservoir quality in sandstones whose primary porosity was lost chiefly by compaction. Sandstones with abundant clay clasts, fecal pellets, glauconite, or micaceous rock fragments can lose all effective porosity by ductile grain deformation. A knowledge of sandstone composition is important to predicting reservoir quality. End_of_Article - Last_Page 747------------