James W. Schmoker

Carbonate Porosity Versus Depth: A Predictable Relation for South Florida

This study examines the porosity of limestones and dolomites in the South Florida basin. Porosity data are derived from borehole-gravity measurements and from suites of acoustic, neutron, and density logs. Both types of wire-line measurements sample large volumes of rock relative to petrographic methods and can be examined at vertical scales approaching those of aquifers and hydrocarbon reservoirs. Investigation depths range from the surface to about 18,000 ft (5,500 m) and span the transition from high-porosity near-surface carbonate sediments of Pleistocene age to much denser Mesozoic carbonate rocks with porosities of only a few percent. Carbonate porosity in the South Florida basin was affected by a variety of diagenetic processes. However, a number of factors that could complicate porosity-depth relations are of limited importance in southern Florida. The basin contains little clastic material; present depths of burial are about equal to maximum depths of burial; the influences of tectonism, geopressures, and hydrocarbon accumulations are minimal. Curves of porosity versus depth, reflecting large-scale porosity-loss processes in the subsurface, are derived for a composite carbonate section and for carbonate strata of different ages and compositions. The decrease of porosity with depth for a composite carbonate section representing a wide range of depositional environments and subsequent diagenetic histories can be characterized by the exponential function ^phgr = 41.73e -z8197/ (ft) [^phgr = 41.73e-z2498/ (m)], where ^phgr is the porosity (%) and z is the depth below ground level (feet or meters). Average porosity is reduced by a factor of two in a depth interval of about 5,700 ft (1,740 m). Carbonate strata of different ages that are buried to equal depths show no systematic porosity differences. This implies that the effect of time on porosity in these rocks is probably subordinate to that of burial depth. The data also show a faster than expected rate of porosity decrease with depth for rocks of Eocene age and younger. If it is assumed that the decrease in the volume of evaporites in these rocks indicates less saline pore fluids, porosity loss in shallow-water carbonates may be inversely related to the magnesium content of pore waters. Dolomite porosity is lower than limestone porosity in the near surface, but does not decrease as rapidly with depth. Below about 5,600 ft (1,700 m), dolomite is more porous than limestone. It is hypothesized that most dolomitization occurred relatively early and either reduced original porosity or selectively favored lower-porosity limestones. With continued burial, dolomite was more resistant than limestone to associated porosity-reducing effects.

Organic Carbon in Bakken Formation, United States Portion of Williston Basin

The upper and lower members of the Mississippian and Devonian Bakken Formation in the United States portion of the Williston basin are black shales that are extremely rich in organic matter and are the source of much of the oil found in the basin. Organic-carbon values are calculated from formation-density logs using the equation: TOC = (154.497/^rgr) - 57.261, where TOC is organic-carbon content (wt. %) and ^rgr is formation density (g/cm3). Test calculations comparing this equation to laboratory organic-carbon analyses from 39 wells in North Dakota show an average absolute difference of 1.1% in organic-carbon content. Organic-carbon content, calculated at 159 locations in North Dakota and 107 in Montana, averages 12.1% for the upper member of the Bakken Formation and 11.5% for the lower member. There is a regional depletion of organic carbon, paralleling present-day isotherms, that reflects the conversion of organic matter to oil and subsequent expulsion of the oil from the formation. The mass of organic carbon in the Bakken Formation is approximately evenly divided between the upper and lower members, and it totals about 126 × 1012 kg in the study area, of which 102 × 1012 kg are in the thermally mature region. The assumption that 167 mg HC/g TOC have migrated out of the mature Bakken shales leads to a tentative estimate that hydrocarbons equivalent to 132 billion bbl of 43° (API gravity) oil have been expelled from the United States portion of the upper and lower members of the Bakken Formation.

Determination of Organic-Matter Content of Appalachian Devonian Shales from Gamma-Ray Logs

The organic-matter content of the Devonian shale of the Appalachian basin is important for assessing the natural-gas resources of these rocks, and patterns of organic-matter distribution convey information on sedimentary processes and depositional environment. In most of the western part of the Appalachian basin the organic-matter content of the Devonian shale can be estimated from gamma-ray wire-line logs using the equation: ^phgro = (^ggrB - ^ggr)/1.378A, where ^phgro is the organic-matter content of the shale (fractional volume), ^ggr the gamma-ray intensity (API units), ^ggrB the gamma-ray intensity if no organic matter is present (API units), and A the slope of the crossplot of gamma-ray intensity and formation density (API units/(g/cm3)). The quantities A and ^ggrB vary regionally and are mapped using data from gamma-ray and formation-density wire-line logs. Organic-matter contents estimated using this equation are compared with organic-matter contents determined from direct laboratory analyses of organic carbon for 74 intervals of varying thickness from 12 widely separated wells. The organic-matter content of these intervals ranges from near zero to about 20% by volume. Excluding the Cleveland Member of the Ohio Shale and the lower part of the Olentangy Shale, the distribution of the differences between volume-percent organic-matter content determined from core samples and estimated from gamma-ray logs has a mean of 0.44% and a standard deviation of 1.98%, which indicates that the accuracy of the gamma-ray method is adequate for most geologic applications. The gamma-ray intensity of the Cleveland Member of the Ohio Shale and the lower pa t of the Olentangy Shale is anomalously low compared to other Devonian shales of similar richness, so that organic-matter content computed for each of these units from gamma-ray logs is likely to be too low. Wire-line methods for estimating organic-matter content have the advantages of economy, readily available sources of data, and continuous sampling of the vertically heterogenous shale section. The gamma-ray log, in particular, is commonly run in the Devonian shale, its response characteristics are well known, and the cumulative pool of gamma-ray logs forms a large and geographically broad data base. The quantitative computation of organic-matter content from gamma-ray logs should be of practical value in studies of the Appalachian Devonian shale. The general approach described here may also be applicable to other formations with physical and geochemical characteristics similar to the Appalachian Devonian shale.

Determination of organic content of Appalachian Devonian shales from formation-density logs

The carbonaceous organic content of the Devonian shales of the Appalachian basin is an important parameter for determining the natural-gas resources of these rocks. To calculate organic content from formation-density logs, analyses of wire-line logs from seven wells in Ohio, West Virginia, Virginia, and Kentucky were compared to laboratory core analyses. These data show that organic content computed from density logs is as reliable and as accurate as that determined from core samples. The density-log method offers the advantage of continuous sampling of the vertically heterogeneous shale section and is based on wire-line logs which are common and readily available sources of data. Plots of gamma-ray intensity versus formation density are used to determine the applicabilit of the method at a given location and to identify individual intervals where the approach may not be valid. Available data indicate that the method can be used in a large area of the western Appalachian basin.

Resource-assessment perspectives for unconventional gas systems

Concepts are described for assessing those unconventional gas sys tems that can also be defined as continuous accumulations. Contin uous gas accumulations exist more or less independently of the wa ter column and do not owe their existence directly to the buoyancy of gas in water. They cannot be represented in terms of individual, countable fields or pools delineated by downdip water contacts. For these reasons, traditional resource-assessment methods based on es timating the sizes and numbers of undiscovered discrete fields can not be applied to continuous accumulations. Specialized assessment methods are required. Unconventional gas systems that are also continuous accumu lations include coalbed methane, basin-centered gas, so-called tight gas, fractured shale (and chalk) gas, and gas hydrates. Deep-basin and bacterial gas systems may or may not be continuous accumu lations, depending on their geologic setting. Two basic resource-assessment approaches have been em ployed for continuous accumulations. The first approach is based on estimates of gas in place. A volumetric estimate of total gas in place is commonly coupled with an overall recovery factor to nar row the assessment scope from a treatment of gas volumes residing in sedimentary strata to a prediction of potential additions to re serves. The second approach is based on the production perfor mance of continuous gas reservoirs, as shown empirically by wells and reservoir-simulation models. In these methods, production characteristics (as opposed to gas in place) are the foundation for forecasts of potential additions to reserves.

High-Porosity Cenozoic Carbonate Rocks of South Florida: Progressive Loss of Porosity with Depth

Porosity measurements by borehole gravity meter in subsurface Cenozoic carbonates of south Florida reveal an extremely porous mass of limestone and dolomite which is transitional in total pore volume between typical porosity values for modern carbonate sediments and ancient carbonate rocks. A persistent decrease of porosity with depth, similar to that of chalks of the Gulf Coast, occurs in these rocks. We make no attempt to differentiate depositional or diagenetic facies which produce scatter in the porosity-depth relationship; the dominant data trends thus are functions of carbonate rocks in general rather than of particular carbonate facies. Carbonate strata with less than 20% porosity are absent from the rocks studied here. Aquifers and aquicludes cannot be distinguished on the basis of porosity. Although aquifers are characterized by great permeability and well-developed vuggy and even cavernous porosity in some intervals, they are not exceptionally porous when compared to other Tertiary carbonate rocks in south Florida. Permeability in these strata is governed more by the spacial distribution of pore space and matrix than by the total volume of porosity present. Dolomite is as porous as, or slightly less porous than, limestones in these rocks. This observation places limits on any model proposed for dolomitization and suggests that dolomitization does not take place by a simple ion-for-ion replacement of magnesium for calcium. Dolomitization may be selective for less porous limestone, or it may involve the incorporation of significant amounts of carbonate as well as magnesium into the rock. The great volume of pore space in these rocks serves to highlight the inefficiency of early diagenesis in reducing carbonate porosity and to emphasize the importance of later porosity reduction which occurs during the burial or late near-surface history of limestones and dolomites.

Sandstone porosity as a function of thermal maturity

Sandstone porosity decreases in the subsurface as a power function of thermal maturity: {phi} = A(M){sup B}, where {phi} is porosity and M is a measure of thermal maturity representing integrated time-temperature history; A and B are constants for a given sandstone of homogeneous properties but vary between data sets. The commonly observed exponential dependence of sandstone porosity upon depth follows as a special case from this power-function relation when temperature increases linearly with depth. The consideration of sandstone porosity in terms of time-temperature exposure offers advantages in the comparison of porosity data from diverse geologic settings, the recognition of unusual porosity within a sandstone sequence, and the prediction of porosity ahead of the drill and at times in the geologic past.

Selected Characteristics of Limestone and Dolomite Reservoirs in the United States

Data from the United States Oil and Gas File (TOTL) developed by the University of Oklahoma, Norman, Oklahoma, are used to characterize the lithology, location (state and basin), geologic age, year of discovery, depth to top of pay, porosity, permeability, water saturation, volume of crude oil and nonassociated gas originally in place, and net-pay thickness of limestone and dolomite reservoirs in the United States. Distributions of these parameters, representing thousands of reservoirs, establish a framework to which individual carbonate reservoirs can be compared, and provide insights into geologic processes affecting reservoir characteristics. Limestone reservoirs are more numerous in the United States than dolomite reservoirs (by a ratio of about 3 to 1) because limestones are more abundant than dolomites. However, in the eight states that account for over 90% of United States carbonate reservoirs, there is a statistical tendency for carbonate reservoirs to occur preferentially in dolomites. Dolomite reservoirs, on the average, are larger and deeper than those of limestone, yet they often have lower matrix porosities and permeabilities. This line of investigation offers supplemental evidence that dolomitization tends to improve the reservoir properties of a given formation, and that effective fracture systems at reservoir depths are more likely to occur in dolomites than in limestones.

Empirical Relation Between Carbonate Porosity and Thermal Maturity: An Approach to Regional Porosity Prediction

Data indicate that porosity loss in subsurface carbonate rocks can be empirically represented by the power function, ^Thgr = a (TTI)b, where ^Thgr is regional porosity, TTI is Lopatins time-temperature index of thermal maturity, the exponent, b, equals approximately -0.372, and the multiplier, a, is constant for a given data population but varies by an order of magnitude overall. Implications include the following. 1. The decrease of carbonate porosity by burial diagenesis is a maturation process depending exponentially on temperature and linearly on time. 2. The exponent, b, is essentially independent of the rock matrix, and may reflect rate-limiting processes of diffusive transport. 3. The multiplying coefficient, a, incorporates the net effect on porosity of all depositional and diagenetic parameters. Within constraints, carbonate-porosity prediction appears possible on a regional measurement scale as a function of thermal maturity. Estimation of carbonate porosity at the time of hydrocarbon generation, migration, or trapping also appears possible.

Porosity Trends of the Lower Cretaceous J Sandstone, Denver Basin, Colorado

ABSTRACT This study examines relationships between porosity and time-temperature history, and the influence of rock properties upon porosity, for the Lower Cretaceous J sandstone in the Colorado portion of the Denver basin. The J sandstone is classified as a quartzarenite to litharenite and was deposited in nearshore-marine, deltaic, and fluvial-estuarine (valley-fill) settings. Principal elements of its paragenetic sequence include quartz cementation and pressure solution, carbonate cementation and dissolution, dissolution of feldspar and rock fragments, and formation of authigenic clays. Porosity versus vitrinite reflectance (R0) regression lines of the form = A(R0)B (where B is a negative number) depicting the 10th, 25th, 50th, 75th, and 90th porosity percentiles of the J sandstone were derived from 963 core-plug measurements representing 31 wells. The data span a thermal maturity range of R0 = 0.41%-1.14%. Porosity distributions at different locations within the basin can be estimated as a function of thermal maturity on the basis of these regression lines. Porosity trends of the J sandstone, if considered as a function of R0, are similar to those of broad, composite data sets representing sandstones in general. The petrographic factors that most affect J sandstone porosity variability at a given level of thermal maturity are carbonate cementation and clay content. Carbonate cement, where present, reduces porosity. If previously more widespread, carbonate cement could also introduce porosity heterogeneity by temporarily preserving the pore network relative to uncemented intervals. Abundant detrital and authigenic clay reduces porosity by occupying pores. Low clay content indirectly reduces porosity because the inhibiting effects of clay upon quartz cementation and pressure solution are largely absent.