Pore Facies Research Articles

Sedimentological and diagenetic facies of tight sandstones in lacustrine delta-front: A case study of the Jurassic Lianggaoshan Formation, eastern Sichuan Basin

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003–0.653 × 10−3 μm2 (av. 0.026 × 10−3 μm2), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 μm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data.

Pore throat distributions and movable fluid occurrences in different diagenetic facies of tight sandstone reservoirs in the Triassic Chang 6 reservoirs, Wuqi Area, Ordos Basin, China

The 6th member of the Triassic Yanchang Formation, hereafter referred to as Chang 6 reservoir, in the Wuqi area of the Ordos Basin presents formidable obstacles for efficient tight oil development. This reservoir is known for its tight lithology, strong heterogeneity, inadequate oil saturation, and abnormally low reservoir pressure, which collectively contribute to the highly differentiated mobility of tight oil within the formation. To overcome these challenges, a comprehensive understanding of the factors influencing oil mobility is essential. This study investigates the occurrence characteristics of movable fluids in different diagenetic facies and the corresponding influential factors by employing various microscopic experiments, including high-pressure mercury intrusion, constant-rate mercury intrusion, nuclear magnetic resonance test, scanning electron microscopy, pore-casted thin section analysis, and X-ray diffraction measurement. There is a weaker correlation between the pore-throat radius ratio and the movable fluid saturation in reservoirs of various diagenetic facies (R2 = 0.6104), whereas there is a stronger correlation between movable fluid saturation and throat radius (R2 = 0.9415). Among the seven types of diagenetic facies, chlorite membrane cementation-intergranular pore facies (Facies I) and chlorite and illite membrane cementation-intergranular pore facies (Facies II) have the best-developed throats and the highest coordination number. Illite cementation-intergranular pore facies (Facies III) and illite and chlorite membrane cementation-dissolution facies (Facies IV) demonstrate smaller pore-throat radii and moderate to poor reservoir connectivity. The other three facies, namely illite cementation-dissolution facies (Facies V), illite cementation facies (Facies VI), and carbonate tight cementation facies (Facies VII) exhibit underdeveloped pore structures and lower recovery rates. Pore-throat radius emerges as the principal factor influencing reservoir permeability and storage capacity. The distribution of favorable diagenetic facies is influenced by depositional environments, diagenetic processes, and microscopic pore-throat characteristics. This study significantly enhances our understanding of the differential occurrence characteristics of fluids in different diagenetic facies in the Chang 6 reservoir, providing valuable insights for future exploration and production endeavors aimed at optimizing oil recovery in tight sandstone reservoirs.

Identification of pore facies for evaluating the reservoir quality: A case study of the Hartha Formation in X Oilfield, Mesopotamian Basin, Iraq

Characterization of pore systems is a key to better understand the heterogeneity of reservoir quality. However, the complicated pore types and pore facies of carbonates in the Hartha Formation of X Oilfield remain poorly understood. In this study, we recognized pore types and explored the impact of depositional environment and diagenetic alterations on pore facies and reservoir heterogeneity. Six types and nine subtypes of pore facies displaying various physical properties and fossils are classified based on the proportion of depositional pores, fabric‐ and non‐fabric‐selective pores. The distribution of pore facies are controlled by the interaction between depositional environment and diagenesis: (i) the depositional environment has an impact on the primary pore types mainly through different lithology and fossils. Micro‐interparticle pores and intraparticle pores of foraminifera are dominated in lagoon, middle ramp and outer ramp, while interparticle pores between grains are dominated in rudist shoal. Rocks deposited in medium‐ to low‐energy shoal contain interparticle pores between grains, micro‐interparticle pores and intraparticle pores of foraminifera. (ii) Major diagenetic events that modify pore types include micritization, fabric‐selective dissolution, cementation, compaction and non‐fabric‐selective dissolution. Micritization facilitates the development of micro‐interparticle pores, while compaction can cause the loss of interparticle pores between grains and micro‐interparticle pores. Cementation destroys not only interparticle pores between grains but also intraparticle pores of foraminifera. Fabric‐ and non‐fabric‐selective dissolution are the main causes for increasing the volume of pores. (iii) The intensity of the diagenetic event is linked to rock composition, rock fabric and palaeotopography that are controlled by depositional environment. Thus, the distribution of pore facies related to the environment is established, which can provide insights for areas lacking cores and adjacent fields with similar settings.

Diagenetic Facies and Their Controls on the Quality of Tight Sandstone Reservoirs: A Case Study from the Upper Paleozoic Gas Reservoir in the Eastern Ordos Basin, North China

Diagenetic facies play a significant role in the evaluation and prediction of reservoirs as they comprehensively reflect the spatial distribution characteristics of deposition, diagenesis, and petrophysical properties. Based on the petrographic observation and considering pores, lithology, and diagenesis types, the diagenetic facies types were identified, and the pore evolution process and its influence on the quality of low permeability tight gas reservoirs were analyzed. The results show that six types of diagenetic facies were identified, including siliceous cementation intergranular pore facies (A), carbonate dissolution pore facies (B), matrix dissolution pore facies (C), clastic dissolution pore facies (D), matrix filling and strong compaction tight facies (E), and carbonate cementation and metasomatism tight facies (F). The evolution process of porosity shows that the restored original porosity is indicated to be between 34.2% and 36.0%. The average porosity loss caused by compaction was 17.1%, while the average porosity loss caused by cementation is 14.1%. The average porosity increased by 2.5% on diagenetic facies B, C, and D due to dissolution. Consequently, diagenetic facies A with weak compaction and diagenetic facies B, C, and D with strong dissolution are effective reservoirs with porosity greater than 6.6% and permeability greater than 0.25 − 0.6 × 10 − 3 μm2. The distribution areas of A, B, C, and D are favorable areas for tight gas exploration and are important indicators for the prediction of tight gas in the Upper Paleozoic Shanxi Formation in the eastern Ordos Basin. This study provides a new petrographic method for reservoir prediction and exploration of natural gas, which has practical value and economic significance.

Identification of Pore Facies for Evaluating the Reservoir Quality: A Case Study of the Hartha Formation in E Oilfield, Mesopotamian Basin, Iraq

Identification of Pore Facies for Evaluating the Reservoir Quality: A Case Study of the Hartha Formation in E Oilfield, Mesopotamian Basin, Iraq

Sedimentary diagenesis and pore characteristics for the reservoir evaluation of Domanik formations (Semiluksk and Mendymsk) in the central part of Volga-Ural petroleum province

The Upper Devonian Semiluksk (Domanik) and Mendymsk carbonate successions have been identified as the most promising unconventional oil and gas deposits in Russia's Volga-Ural petroleum province. Three lithofacies were identified: limestones, organic matter-rich siliceous carbonate, and dolomitic limestones/dolomite. Their sediments are thought to have accumulated in the relatively deep-sea shelf depositional environment. According to X-ray analysis, calcite is the most common mineral phase in the limestones. The siliceous carbonate rocks' major mineral phases were identified to be quartz, followed by calcite. The rocks have relatively poor reservoir qualities, with porosity ranging from 0.1 to 5% and permeability ranging from 0.01 to 10 mD. Petrographic examination of thin sections reveals four major types of pores: 1. interparticle pores, which are abundant in all of the examined lithofacies; 2. intercrystalline pores formed between dolomite crystals and the very fine components of the siliceous carbonate rocks. 3. vugs as a result of leaching, and 4. fracture as a result of tectonic and/or diagenetic events. Plotting the obtained data from the petrographically examined thin sections on the ternary pore plot diagram resulted in the identification of six pore facies and their related diagenetic patterns. Pore facies 1 depicts the pores that formed during the depositional process. Pore facies 4 displays moldic pores. The vugs are represented by pore facies 6. Pore facies 2 is a mixture between pore facies 1 and pore facies 4. Pore facies 3 is a mixture between pore facies 1 and pore facies 6. Pore facies 5 is a mixture between pore facies 4 and pore facies 6. Comparing the petrographic results and the identified pore facies show that pore facies 6 have touching pores and they played the most important role in improving the reservoir quality. The pore facies 4 which have separate pores have the most influence in the reduction of the reservoir quality. The diagenetic origin secondary pores are the most pores identified in the studied carbonate section. This reflects the strong modification of the pores by the diagenetic overprinting. The massive dissolution that forms the touching vugs, and the dolomitization process are the most diagenetic processes that affect the pore system within the studied rocks.

Integrated rock typing and pore facies analyses in a heterogeneous carbonate for saturation height modelling, a case study from Fahliyan Formation, the Persian Gulf

Knowledge of initial fluids saturation has great importance in hydrocarbon reservoir analysis and modelling. Distribution of initial water saturation (Swi) in 3D models dictates the original oil in place (STOIIP), which consequently influences reserve estimation and dynamic modelling. Calculation of initial water saturation in heterogeneous carbonate reservoirs always is a challenging task, because these reservoirs have complex depositional and diagenetic history with a complex pore network. This paper aims to model the initial water saturation in a pore facies framework, in a heterogeneous carbonate reservoir. Petrographic studies were accomplished to define depositional facies, diagenetic features and pore types. Accordingly, isolated pores are dominant in the upper parts, while the lower intervals contain more interconnected interparticle pore types. Generally, in the upper and middle parts of the reservoir, diagenetic alterations such as cementation and compaction decreased the primary reservoir potential. However, in the lower interval, which mainly includes high-energy shoal facies, high reservoir quality was formed by primary interparticle pores and secondary dissolution moulds and vugs. Using huge number of primary drainage mercury injection capillary pressure tests, we evaluate the ability of FZI, r35Winland, r35Pittman, FZI* and Lucia’s petrophysical classes in definition of rock types. Results show that recently introduced rock typing method is an efficient way to classify samples into petrophysical rock types with same pore characteristics. Moreover, as in this study MICP data were available from every one meter of reservoir interval, results show that using FZI* method much more representative sample can be selected for SCAL laboratory tests, in case of limitation in number of SCAL tests samples. Integration of petrographic analyses with routine (RCAL) and special (SCAL) core data resulted in recognition of four pore facies in the studied reservoir. Finally, in order to model initial water saturation, capillary pressure data were averaged in each pore facies which was defined by FZI* method and using a nonlinear curve fitting approach, fitting parameters (M and C) were extracted. Finally, relationship between fitting parameters and porosity in core samples was used to model initial water saturation in wells and between wells. As permeability prediction and reservoir rock typing are challenging tasks, findings of this study help to model initial water saturation using log-derived porosity.

Acid-base alternation diagenesis and its influence on shale reservoirs in the Permian Lucaogou Formation, Jimusar Sag, Junggar Basin, NW China

Abstract The diagenesis and diagenetic facies of shale reservoirs in Lucaogou Formation of Jimusar Sag were studied by means of microscopic observation and identification of ordinary thin sections and cast thin sections, X-ray diffraction, scanning electron microscope and electron probe tests. The results show that alkaline and acidic diagenetic processes occurred alternately during the deposition of Permian Lucaogou Formation in Jimusar Sag. The evolution of porosity in the shale reservoirs was influenced by compaction and alternate alkaline and acidic diagenetic processes jointly, and has gone through three stages, namely, stage of porosity reduction and increase caused by alkaline compaction, stage of porosity increase caused by acid dissolution, and stage of porosity increase and reduction caused by alkaline dissolution. Correspondingly, three secondary pore zones developed in Lucaogou Formation. The shale reservoirs are divided into three diagenetic facies: tuff residual intergranular pore-dissolution pore facies, tuff organic micrite dolomite mixed pore facies, and micrite alga-dolomite intercrystalline pore facies. With wide distribution, good pore structure and high oil content, the first two facies are diagenetic facies of favorable reservoirs in Lucaogou Formation. The research results provide a basis for better understanding and exploration and development of the Lucaogou Formation shale reservoirs.

The effect of carbonate reservoir heterogeneity on Archie's exponents (a and m), an example from Kangan and Dalan gas formations in the central Persian Gulf

Calculating hydrocarbon in place is one of the most important aspects to be considered in reservoir evaluation. Carbonate rocks with high heterogeneity, exhibit significant changes in petrophysical and lithological properties. Archie's exponents (m and a) are basic parameters for saturation calculations. Uncertainties in obtaining these exponents lead to considerable errors in the saturation assessment. In this study, various pore and rock typing methods were carried out on a Permian–Triassic carbonate reservoir in the central Persian Gulf, Iran. The used methods include pore typing, pore facies classification, velocity deviation log, reservoir quality index, Winland R35, Pittman R35 and ranges of core permeability. Archie's exponents were obtained for different classes based on extracted data from petrographical studies, conventional core analysis and wire line log data. Results showed that determination of rock types based on pore typing has the greatest effect on the precise determination of Archie's exponents. On the other hand, the most unreliable results were related to the velocity deviation log. Pore types directly control the connectivity of the fluid pathways and so have the most important effect. Combining pore types in various groups such as velocity deviation or pore facies classification, reduce the measurement accuracy of Archie's exponents and resulted water saturation. Finally, it can be concluded that, in addition to the high impact of pore type on the accuracy of the obtained exponents, the permeability and pore throat radius are less effective in determining the Archie's exponents.

The effect of heterogeneity on NMR derived capillary pressure curves, case study of Dariyan tight carbonate reservoir in the central Persian Gulf

The porous network controls the behavior of fluids in the reservoir rocks. In carbonate reservoirs fluid flow characteristics do not certainly follow initial sedimentary fabrics. Therefore in these reservoirs, the properties of the porous network should be used in determining the facies. In this study, using a combination of petrographic, reservoir petrophysical and reservoir engineering data, porous network in Aptian-Albian Dariyan carbonates have been studied in one of the central Persian Gulf fields. Accordingly, four pore facies were determined by capillary pressure curves from mercury injection and nuclear magnetic resonance data in four different types of lithology with different microfacies. Also, 13 different petrophysical parameters of these curves derived from both methods and compared with each other. A clear trend was observed in reducing the reservoir quality from pore facies 1 to pore facies 4. The performance of the capillary pressure curves obtained from mercury injection and nuclear magnetic resonance and their derived parameters in 4 facies and the effect of lithology on these curves have been investigated. Results showed that the porosity of the NMR is completely independent of lithology and complexity of the porous system, while the permeability-dependent parameters are largely influenced by both lithology and pore system structure. It was also shown that the NMR curves are a suitable tool for determining the pore facies and their petrophysical parameters in homogeneous tight carbonate lithology with a simple porous system.

Geoelectrohydraulic investigation of the surficial aquifer units and corrosivity in parts of Uyo L. G. A., Akwa Ibom State, Southern Nigeria

This study was carried out employing vertical electrical sounding (VES) with Schlumberger electrode configuration. The objectives were to investigate the distribution of the geohydraulic parameters and the corrosivity of the aquifer layer within the study area. The sand-to-coarse grain sands aquifer have resistivity ranging from 8.1 to 2204 Ωm, while the thickness ranged from 7.4 to 55.3 m. These parameters were used in computing the geohydraulic parameters. Hydraulic conductivity was estimated using the Heigold equation, and its values ranged from 1.42 to 54.90 m/day. Estimated hydraulic conductivity values were employed in determining the aquifer transmissivity which ranged from 11.28 to 812.00 m2/day, fractional porosities ranged from 0.0351 to 0.0598. The longitudinarl conductance also varies from 0.01 to 1.83 Ω−1. The contour plots generated from the SURFER software package show the variation of these parameters. The ranges of these estimated parameters indicate variation in grain sizes, magnitude of pore sizes and facies changes. The corrosivity rating indicates that most of the VES points were practically non-corrosive.

Identification of pore types and pore facies for evaluating the diagenetic performance on reservoir quality: a case study from the Asmari Formation in Ramin Oil Field, SW Iran

The purpose of this study is to identify the pore types and distinguish the pore facies based on the diagenetic performance. The petrographic examination of 230 thin sections lead to the identification of a variety of primary and secondary porosities and show that the vuggy, moldic and intercrystalline pores have more frequency than the intraparticle, interparticle and fenestral pores. The plot of data obtained from thin sections on the ternary porosity graph used for determining the pore facies and their diagenetic trends and led to the identification of6 pore facies including depositional (PF1), moldic (PF4), and vuggy (PF6) pore facies, and also mixture pore facies PF2 (mixture of PF1 and PF4), PF3 (mixture of PF1 and PF6) and PF5 (mixture of PF4 and PF6). The comparison of petrography results with the well logs, core permeability and the calculated RQI and FZI values show that the pore facies which have touching pores, especially PF6 and PF1, have played the most important role in improving the quality of the reservoir, especially in the upper part of the studied zone. Also the pore facies which have separate pores, especially PF4, have the most influence in the reduction of reservoir quality relative to other pore facies, especially in the lower part of the studied zone. Most of the pores identified in the studied zone are the secondary porosity and diagenetic in origin. This demonstrates that the reservoir characteristics in the studied zone have been strongly modified by diagenetic overprinting. The most important diagenetic processes affecting the pore systems of the Asmari reservoir are cementation, selective and massive dissolution and dolomitization. Massive dissolution plays the most active role in the formation of touching vugs as well as enhancement of reservoir quality. Cementation and fabric selective dolomitization play the most active role in decrease of the reservoir quality.

Pore facies analysis: incorporation of rock properties into pore geometry based classes in a Permo-Triassic carbonate reservoir in the Persian Gulf

Pore facies analysis is a useful method for the classification of reservoir rocks according to pore geometry characteristics. The importance of this method is related to the dependence of the dynamic behaviour of the reservoir rock on the pore geometry. In this study, pore facies analysis was performed by the quantification and classification of the mercury injection capillary pressure (MICP) curves applying the multi-resolution graph-based clustering (MRGC) method. Each pore facies includes a limited variety of rock samples with different depositional fabrics and diagenetic histories, which are representative of one type of pore geometry. The present pore geometry is the result of the interaction between the primary rock fabric and its diagenetic overprint. Thus the variations in petrographic properties can be correlated with the pore geometry characteristics. Accordingly, the controlling parameters in the pore geometry characteristics were revealed by detailed petrographic analysis in each pore facies. The reservoir rock samples were then classified using the determined petrographic properties which control the pore system quality. This method is proposed for the classification of reservoir rocks in complicated carbonate reservoirs, in order to reduce the incompatibility of traditional facies analysis with pore system characteristics. The method is applicable where enough capillary pressure data is not available.

Distinguishing Carbonate Reservoir Pore Facies with Nuclear Magnetic Resonance Measurements

Characterization of carbonate rocks may involve identifying the important pore types which are present. In the past, this task has required detailed petrographic analysis of many core samples. Here, we describe a method which uses nuclear magnetic resonance (NMR) measurements to reduce the amount of petrographic analysis needed for porosity typing of carbonate reservoir rocks. For a rock sample which has been measured with NMR, our method decomposes the log(T2) spectrum into at most three Gaussian-shaped components and gives a set of nine parameters. Two characteristic quantities having geological significance are extracted from the nine parameters. Values of the two quantities are compared with a reference set, established from samples having both NMR and petrographic evaluations of porosity types. We use a Bayesian approach to the classification of the dominant porosity type. Tests of our method on 103 samples show a correct prediction in 60 to 90 percent of the samples. The lower success rate was obtained for samples with five porosity types from three fields; the higher success rate obtained with samples with three porosity types from one well. The use of geologically significant quantities extracted from the decomposition gives comparable success rate to those obtained using a standard, non-geological approach such as canonical variates.

Regional porosity evolution in the Smackover Formation of Alabama

The Upper Jurassic (Oxfordian) Smackover Formation is the most prolific oil producer in Alabama. Smackover strata in Alabama were deposited on carbonate ramps under conditions of stable relative sea level. Reservoir rocks consist primarily of nonskeletal (primarily oolitic and pelletal) dolograinstone, with lesser amounts of nonskeletal dolopackstone, microbial doloboundstone, and nondolomitized nonskeletal grainstone and packstone. Porous and permeable strata are classified on the basis of the relative proportions of genetic pore types as belonging to one of three pore facies: moklic, intercrystalline, and intermediate (mixtures of moklic and intercystalline pores at various scales). Equivalent vitrinite reflectance (Ro) data, commercial core-plug porosity data, conventional core description, and point counting of petrographic thin sections were used to evaluate the relationships among thermal exposure, pore types, and porosity evolution in Smackover reservoirs in Alabama. Porosity and thermal exposure are inversely related in Smackover reservoirs of Alabama, as they are in most sedimentary rocks. However, the overall correlation between porosity and Ro is not strong, indicating that other factors significantly affected porosity evolution. Factors of rock type (limestone vs. dolomite), depositional environment, and depositional fabric did not strongly influence regional porosity evolution. By contrast, mode of dolomitization as expressed by pore-facies classification had a direct effect on regional porosity evolution. This results from regional geographic trends in mode of dolomitization. Subdivision of the data set by pore facies increases correlation coefficients of porosity-Ro as a function of geographic variation in pore-facies assignment. Intermediate pore systems are more porous than moldic pore systems at a given value of Ro. Reservoirs with intercrystalline pore systems were too few to analyze quantitatively, but these reservoirs plot approximately within the field defined by intermediate reservoirs on a porosity-Ro plot, and resemble intermediate reservoirs petrophysically. Smackover reservoir rocks on the north flank of the eastern (Alabama) end of the Wiggins arch, a major paleohigh that was partially exposed throughout deposition of the Smackover, are unusually porous for the Smackover of Alabama. Smackover reservoirs in this area are unique in other ways as well: they are more completely dolomitized, contain more hydrocarbons than would a similar number of Smackover fields elsewhere in Alabama, are dominated by intercrystalline pore systems (uncommon elsewhere in the Alabama Smackover), and exhibit values of mean porosity, mean permeability, standard deviation of permeability, Dykstra-Parsons coefficient, and microscopic reservoir heterogeneity (variable defined by Kopaska-Merkel and Mann, 1992) that deviate from regional trends.

Regional Variation in Microscopic and Megascopic Reservoir Heterogeneity in the Smackover Formation, Southwest Alabama

ABSTRACT Quantitative (rank) measures of microscopic and megascopic reservoir heterogeneity are used to characterize the distribution of reservoir heterogeneity in Smackover hydrocarbon fields and wildcat wells in southwest Alabama. Microscopic reservoir heterogeneity (µH) is {[(0.25) + (meanlnK) + (1.5lnK)]/3}. Megascopic Heterogeneity (MH) is [(# of reservoir intervals) + (# of high-K reservoir intervals) + ( of # of reservoir intervals)] where reservoir rock is defined as exhibiting permeability values >= 0.1 md and high-permeability reservoir rock exhibits permeability values >= 1.0 md. Both MH and µH are determined from core data. The Dykstra-Parsons coefficient (DP) is a measure of microscopic heterogeneity that is partially independent of µH(r2 = 0.428). All three of these parameters are primarily measures of vertical heterogeneity, although averaging of wells within a field incorporates lateral heterogeneity in µH and DP. µH and MH are distributed in contrasting but related patterns. µH generally decreases from northwest to southeast, with the highest values found in the vicinity of the Choctaw Ridge complex north of the Mississippi Interior Salt Basin (MISB). Moderately high values typify the Manila Embayment and the Conecuh Ridge complex to the south, whereas lower values are found in the MISB, on the north flank of the Wiggins Arch, and in the Conecuh Embayment. µH values are high in the Moldic Pore Facies and low in the Intercrystalline Pore Facies. The distribution of MH is roughly opposite to that of µH. MH values are high on the north flank of the Wiggins Arch, on the Conecuh Ridge complex and in the Conecuh Embayment: MH values are low near the Choctaw Ridge complex. The Conecuh Ridge is unique because it is characterized by high values of both µH and MH. Also, the low-relief north-south trending salt-cored anticline in western Washington County is characterized by relatively high values of MH. Reservoirs belonging to the Moldic Pore Facies tend to be homogeneous with respect to MH, whereas reservoirs assigned to the Intercrystalline Pore Facies are characterized by relatively high values of MH. MH and µH vary congruently with pore-system characteristics (controlled by depositional patterns, dissolution, and dolomitization) and regional structural and paleogeographic trends. This suggests that reservoir heterogeneity characteristics are controlled by structural and paleogeographic setting, by depositional fabric, and by diagenesis. However, because contours of µH and MH are approximately normal to structure contours but parallel to Smackover thickness contours, it appears that depositional setting (or paleogeography) influenced reservoir heterogeneity more than did structural evolution. The distribution of DP values is not related to pore-facies distribution. Thus we conclude that DP is less useful for regional heterogeneity studies than is MH or µH.

Pore Facies of Smackover Carbonate Reservoirs in Southwest Alabama

This DOI is not currently attached to any metadata records. DOIs can’t actually ever be deleted (they’re persistent), but sometimes our members create DOIs in error. We do have a process to approximate deletion which we follow only in rare cases where the DOI has been genuinely created in error, and most crucially, if the DOI has never been published anywhere online or in print and never otherwise distributed to or communicated with anyone (authors, readers, reviewers, etc.