Core Plug Porosity Research Articles

Pore to Core Scale Characterization of Hydraulic Flow Units Using Petrophysical and Digital Rock Analyses

This article illustrates an integrated method for characterizing hydraulic flow units in subsurface reservoirs using multiscale images and petrophysical data analysis from well cores. This method is applied to 35 meters of cores drilled from a Late Jurassic Upper Jubayla Formation outcrop in Saudi Arabia, which is analogous to the lower section of the Arab‐D reservoir. Scanning electron microscope (SEM) imagery, thin‐section petrography, and X‐ray computed tomography (CT) images of whole cores and core plugs are used to visualize and characterize these carbonate rocks across multiple length scales. Core plug porosity and permeability data are used for petrophysical characterization and deriving hydraulic flow units (HFU). The multimodal pore types associated with the HFUs and their connectivity using thin section and SEM image analysis, combined with mercury injection porosimetry are used. Whole‐core CT textures and heterogeneity logs are correlated with HFU and digital image analysis of core plugs. Whole‐core CT data prove to be a highly valuable tool for bridging the scale gap between well data and reservoir models. This methodology can be applied to datasets from a large number of wells, especially when combined with machine learning tools, allowing improved characterization of complex carbonate reservoirs.

Reservoir characteristics of Datta Formation (Early Jurassic), Marwat-Khisor Ranges, sub-Himalayas, Pakistan

The present work has been accomplished to carry out a detailed study of the characteristics of the Early Jurassic Datta Formation of Trans-Indus Ranges, Pakistan. The discovery of Saib well-1 (Gas and condensate discovery from Jurassic limestone) in the study basin takes an active interest in carrying out extensive exploration activities in the same basin. Jurassic rocks especially Datta Sandstone and Samana Suk Limestone are acting as good reservoirs. The study unit consists of variegated sandstone interbedded with siltstone, carbonaceous clay, and shale and coal stringer. For the current work, two stratigraphic sections (Pezu and Abbo Wanda) have been measured. To examine its sedimentology, depositional environment, diagenetic settings, and reservoir characteristics, a detailed study was conducted and various laboratory techniques have been utilized. About 95 rock samples from the bottom to the top of both sections were collected, and 50 rock samples have been selected for thin section analysis and were examined under a polarizing microscope to show their mineralogical composition, diagenesis, and their reservoir characteristics. XRD (X-ray diffraction), Cathodoluminescence (CL), SEM (Scanning electron microscope) with EDS (Energy-dispersive spectroscope), and Core plug porosity and permeability analysis have been used to interpret its chemical and mineralogical composition and its reservoir characteristics, respectively. Based on field observations and thin section analysis, four depositional facies and six lithofacies have been established. The sedimentary structures, depositional facies, and lithofacies indicate that Datta Formation was deposited in a deltaic environment. Compactions, cementation, fracturing and dissolution can greatly affect the quality of reservoir rock. Based on thin section and SEM analysis, large numbers of primary pores, fracture and secondary pores were observed and connectivity between the pores is good, and at some places, these pores were filled through the authigenic clay minerals like kaolinite, mixed layers illite/smectite and chlorite that influences the reservoir characteristics. Primary pores (thin section) and secondary pores (dissolution pores) and core plug porosity and permeability data (porosity 13.23%–26.89% and permeability 0.12 to 149 mD) shows that Datta Formation has a good reservoir quality.

Prediction of carbonate rock facies from core probe permeability measurements and well log data: a case study from carbonate reservoirs, Phu Khanh basin

Probe permeameter (also known as Mini-permeameter) has been widely used in many field and laboratory applications where in-situ measurements and spatial distributions of permeability are needed. Mini-permeameter measurements have become popular techniques for collecting localized permeability measurements in both laboratory and field applications. It is designed to obtain fast, cheap, intensive and non-destructive permeability measurements and to describe the spatial arrangement of permeability. Currently the probe permeability meter is designed and manufactured as a portable air permeability for field applications and to be used in outcrop and core samples. In this instrument, the permeability is measured by air that flows from the samples to be measured into an air chamber through the vacuum created by increasing the volume of the chamber. In carbonate reservoirs, permeability predicted from pure porosity-permeability empirical relationship is often difficult due to complex rock pore systems leading to poor porosity-permeability relations. Once the relationships between permeability and textural rock properties are clearly established in carbonates, they can provide better permeability predictions from porosity data. Rock texture is an important parameter for the understanding of the porosity and permeability characteristics of carbonate reservoirs. In addition to predicting carbonate rock facies from routine core plug porosity and permeability measurements, there is an approach to determine carbonate reservoir facies based on core-plug probe permeability. The results of the probe permeability measurements, in this paper, can be used in combination with the porosity values derived from the well logs to classify and predict rock facies in carbonate cored or uncored reservoirs in Phu Khanh basin.

Sedimentology and sequence stratigraphy of automated hydraulic flow units – The Permian Upper Dalan Formation, Persian Gulf

The Upper Dalan (Khuff-equivalent) Formation constitutes the principal reservoir of the giant gas fields in the Persian Gulf Superbasin. A sedimentological and sequence stratigraphic analysis was conducted on selected cores from the South Pars, Kish, and Lavan gas fields, offshore Iran, to evaluate a recently proposed method for automatic reservoir zonation, and discuss the predictability of such defined zones. The succession consists of nine evaporite-carbonate lithofacies grouped into three shallow-marine facies associations (shoal, lagoon, and tidal flat) that were deposited on a low-gradient homoclinal ramp. Lithofacies are stacked into two complete long-term (3rd-order?) transgressive-regressive depositional sequences. Sequence boundaries were defined by facies stacking patterns and presence of evaporites and meteoric diagenetic features. The reservoir quality was improved by both early-stage dolomitization and dissolution, whereas pervasive pore-filling anhydrite cementation, compaction, and late-stage over-dolomitization reduced the reservoir quality. Whereas dolomitization overall slightly affected porosity, it significantly increased the permeability in mud-dominated lithofacies. Fibrous and bladed calcite rim cements, as well as micritization of the grain-dominated lagoon and shoal lithofacies, prevented porosity reduction during the early- and late-stage burial by building a stronger framework. Core-plug porosity and permeability measurements were used to calculate the Winland R35, Reservoir Quality Index (RQI), and Flow-Zone Indicator (FZI) values. A novel, fully automated approach, was used to effectively identify the hydraulic flow units (HFUs). The HFUs are sedimentologically distinct units with characteristic combinations of the original rock texture and the subsequent diagenetic overprint, and their subsurface position within the sequence stratigraphic framework may be predicted.

New approach in analysing rock property changes in vuggy carbonates

X Field is a HPHT carbonate gas field containing about 70% of CO2, and is located in offshore East Malaysia. In order for this field to be economical and environmental friendly, PETRONAS plans to reinject produced CO2 back into the reservoir. With this objective, PETRONAS Research Sdn Bhd is conducting a feasibility study on changes of reservoir rock properties due to this CO2 sequestration activity. As the available vuggy-carbonate core-plugs have a higher risk of damage, the team employed digital core analysis (DCA) technology for this study. The study consists of three phases. In the first phase, the selected core plugs were analysed using micro CT scan and image processing software. To mimic the gas reservoir, the core plugs were then saturated with synthethic brine, before undergoing centrifuge until Sw-irr from Pc data was reached. The second phase consisted of aging the core-plugs by immersion in supercritical CO2 at pressure and temperature of the reservoir for 45 days. In the third phase the core plugs were analysed via DCA again to determine changes caused by CO2 reaction in rocks. Due to the fragility of the selected samples, they the post aging DCA analysis revealed both mechanical and geochemical changes. However, the central part of the core-plugs was not mechanically damaged and could be used to analyse the changes in porosity mainly due to geochemical reaction. Our results indicate that there will be small impact of porosity changes due to CO2 storage activity in X Field. DCA has proven to be a very useful method in determining porosity changes in reservoir rocks. Not only can DCA determine porosity of broken core plugs, but it also can extract the unbroken parts of the rock for more accurate analysis.

3D geo-cellular static virtual outcrop model and its implications for reservoir petro-physical characteristics and heterogeneities

Geostatistical data plays a vibrant role for surface-based reservoir modeling through outcrop analogues, which is used to understand three-dimensional (3D) variability of petrophysical properties. The main purpose of this study is to improvise the surface-based 3D geo-modeling to demonstrate petrophysical characteristics and heterogeneities of Sandakan reservoirs, NW Borneo. We used point cloud data from Light Detection and Ranging (LiDAR) to build high-resolution virtual outcrop modeling (VOM) onto which we mapped 6 different lithofacies. Porosity and permeability of core plugs were measured to determine the average variance of petrophysical properties for each lithofacies. By utilizing the integration of VOMs analogues and petrophysical properties in Petrel™, we demonstrated the distribution and associations of all lithofacies in pseudo wells that have inherent thin beds heterogeneities in 3D geo-cellular model. The results concluded that the heterogeneity of thin beds in lithofacies is dependent on porosity and permeability with input dataset. According to the final model, cross-bedding sandstone (CBS), hummocky cross-stratified sandstone (HCSS) and trough cross-bedding sandstone (TCBS) show good reservoir quality due to high porosity ranging from: 25.6% to 20.4% and, 19.3%–14.5%, and permeability ranging from: 74.03 mD to 66.84 mD and, 64.86 mD to 21.01 mD. In contrast, massive to weak laminae sandstone (MWLS) and bioturbated sandstone (BS) show fair to poor reservoir quality, caused baffling of surrounding mud sediments in the reservoir lithofacies. Results also revealed that LiDAR based VOM with petrophysical properties can significantly reduce the risk and minimize the cost of reservoir modeling in petroleum industry.

Impact of depositional and diagenetic features on petrophysical and rock mechanical properties in Arab-D reservoir equivalent upper Jubaila Formation, Saudi Arabia

This paper presents a comprehensive analysis of multiscale geological, petrophysical and rock mechanical data acquired from 35 m of outcrop well core from the Late Jurassic (Kimmeridgian) Upper Jubaila Formation, Saudi Arabia. In this location the sequence is a typical shallow marine heterogeneous carbonate sequence and a direct analogue to a part of the prolific Arab D reservoir sequence in the subsurface towards the east. Four main lithofacies types were identified with a general shoaling upwards trend, varying from nodular bioturbated peloidal mudstone/wackestone facies to sharp-based intraclast-peloidal, skeletal rudstone/floatstone facies. The mineralogy in the upper section of the well cores is predominantly calcite, while the lower section is also comprised of some dolomite and quartz. Stratiform dedolomitization as a telogenetic overprint is only evident in the upper 18 m of the core and controlled by vertical flow of meteoric fluids. The core plug porosity distribution is lower than that of the subsurface equivalent reservoir zones, and is attributed to meteoric cementation. Thalassinoides burrow features in mudstone and wackestone facies in the upper sections of the core control horizontal permeability distribution at the centimeter to meter-scale. Micrite morphology and dedolomitization appear to be key controls on plug permeability, rock strength and sonic velocity. Based on the trends observed in compressive rock strength, p-wave velocity and plug porosity distributions, the cored section was divided into five main rock mechanical layers. Despite reduced porosity, the average compressive rock strength in the outcrop core is lower than that of the Arab-D subsurface equivalent rocks, indicating overall ‘weakening’ of the rock due to telogenetic processes and surface weathering.

Nanopetrophysical characterization of the Mancos Shale Formation in the San Juan Basin of northwestern New Mexico, USA

The Mancos Shale of the San Juan Basin has been an important resource for the exploration and development of oil and gas. However, as with most unconventional plays, the shales have low porosity and extremely low permeability with predominantly nanometer-sized pores. Thus, it is critical to understand the nanopetrophysical properties of the reservoir so a proper assessment of the reservoir quality can be made. Working with three as-received core samples from three different wells of the Tacito Marine Bar and Offshore Mancos play types, we have developed an initial understanding of the nanopetrophysical properties of the pore structure as well as fluid-rock interactions in these tight reservoirs. We have performed a suite of integrated tests, such as mercury intrusion porosimetry (MIP), low-pressure nitrogen physisorption, core plug porosity and permeability, scanning electron microscopy imaging, water immersion porosimetry after vacuum pulling, contact angle, and fluid imbibition. In addition, we obtained supplementary data for total organic carbon, X-ray diffraction, and pyrolysis to further evaluate reservoir quality. The Mancos Shale samples exhibit petrophysical characteristics that are controlled by a predominant presence of nanometer-sized pore space, with 56%–96% pore volumes present as 3.4–50 nm in pore-throat sizes, as shown by the MIP approach. Contact angle and fluid imbibition tests demonstrate that samples are oil wet to mixed wet, with a tendency of pore networks to imbibe oil over water. The findings from integrated pore structure and wettability studies provide a database and some insights, from the perspectives of nanopetrophysical characterization, into the reservoir quality of the Mancos Shale.

Porosity evolution and diagenetic history of the Upper Jurassic Mozduran Formation, eastern Kopet-Dagh Basin, NE Iran

The Upper Jurassic carbonates of the eastern part of the Kopet-Dagh Basin, with thickness of 470 m, are the major gas-bearing reservoir in NE Iran. The objectives of this study are recognition of diagenetic history and estimation of porosity related to dolomitization. Based on field and laboratory study, four carbonate facies associations have been identified at the Mazdavand outcrop. Most of the carbonate rocks were deposited in an open marine, tidal channel and barrier, lagoon and tidal flat setting. Using petrographic and CL analyses, the main diagenetic processes that affected these rocks are micritization, cementation, compaction, fracturing, dissolution, neomorphism, silicification, and dolomitization. Dissolution of grains and calcite cement generated secondary porosity, whereas compaction and cementation are the primary cause of porosity reduction. The average porosity of core plugs is 15.78% and match well with two-dimensional estimates from thin sections. The more porous samples are either highly fractured or contain interparticle and intercrystalline porosity, within the lower strata that contain more dolostone.

Insights into deep, onshore Gulf of Mexico Wilcox sandstone pore networks and reservoir quality through the integration of petrographic, porosity and permeability, and mercury injection capillary pressure analyses

In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.

Microfacies and diagenetic studies of the early Eocene Sakesar Limestone, Potwar Plateau, Pakistan: approach of reservoir evaluation using outcrop analogue

The early Eocene Sakesar Limestone of the Salt Range has been investigated in detail for microfacies analysis, depositional modeling, diagenesis and reservoir characterization. This research work was comprised of two outcrop sections, i.e., Nilawahan Gorge Section (NGS) and Katas Temple Sections (KTS) of the Sakesar Limestone, central and eastern Salt Range, Potwar Plateau. This work is mainly concentrated on investigating and evaluating the reservoir quality through depositional and diagenetic fabrics. The depositional, diagenetic and deformational processes are controlling factors of porosity and permeability distribution. On the basis of relative estimated ratio of allochemical constituents and micrite, five microfacies have been recognized. These microfacies are: Benthonic Foraminiferal wackestone, Foraminiferal-Algal wackestone–packstone, Miliolidal-Algal wackestone–packstone, Nummulitic-Assilina Packstone and Alveolina-Algal packstone. On the basis of relative abundance of biota, their associations and the presence of micritic matrix in various microfacies, the Sakesar Limestone is interpreted to be deposited in the proximal inner ramp to middle ramp settings. The Sakesar Limestone is largely affected and modified by various diagenetic events which have destroyed primary nature of reservoir and developed it as prolific secondary reservoir. The paragenetic sequence includes micritization, cementation, dissolution, neomorphism, nodularity, silicification, mechanical compaction, stylolitization, fractures and veins formation. The identified porosity types include intraparticle, intercrystalline, moldic, cavernous and fracture. The visually estimated average micro porosities of the Sakesar Limestone vary between 0.5 and 2.1% in the NGS and KTS. The core plug porosity and permeability of outcrop samples vary between 0.9 and 2.9%. The relation of core plug porosity and permeability has moderate positive correlation coefficient. The fractures and dissolution on microscopic and macroscopic level are the dominant factors that enhance the reservoir potentiality of the Sakesar Limestone.

High-resolution sequence stratigraphy, sedimentology and reservoir quality evaluation of the Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China

Delta-front sand bodies with large remaining hydrocarbon reserves are widespread in the Upper Cretaceous Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China. High-resolution sequence stratigraphy and sedimentology are performed based on core observations, well logs, and seismic profile interpretations. An evaluation of the reservoir quality of the Yaojia Formation is critical for further petroleum exploration and development. The Yaojia Formation is interpreted as a third-order sequence, comprising a transgressive systems tract (TST) and a regressive systems tract (RST), which spans 4.5 Myr during the Late Cretaceous. Within this third-order sequence, nine fourth-order sequences (FS9–FS1) are recognized. The average duration of a fourth-order sequence is approximately 0.5 Myr. The TST (FS9–FS5) mostly comprises subaqueous distributary channel fills, mouth bars, and distal bars, which pass upward into shallow-lake facies of the TST top (FS5). The RST (FS4–FS1) mainly contains subaqueous distributary-channel and interdistributary-bay deposits. Based on thin-sections, X-ray diffraction (XRD), scanning electron microscope (SEM) and high-pressure mercury-intrusion (HPMI) analyses, a petrographic study is conducted to explore the impact of the sedimentary cyclicity and facies changes on reservoir quality. The Yaojia sandstones are mainly composed of lithic arkoses and feldspathic litharenites. The sandstone cements mostly include calcite, illite, chlorite, and secondary quartz, occurring as grain coating or filling pores. The Yaojia sandstones have average core plug porosity of 18.55% and permeability of 100.77 × 10−3 μm2, which results from abundant intergranular pores and dissolved pores with good connectivity. Due to the relatively coarser sediments and abundant dissolved pores in the feldspars, the FS4–FS1 sandstones have better reservoir quality than the FS9–FS5 sandstones, developing relatively higher porosity and permeability, especially the FS1 and FS2 sandstones. The source–reservoir–cap-rock assemblages were formed with the adjoining semi-deep lake mudstones that were developed in the Nenjiang and Qingshankou Formations. This study reveals the deposition and distribution of the delta-front sand bodies of the Yaojia Formation within a sequence stratigraphic framework as well as the factors controlling the Yaojia sandstones reservoir quality. The research is of great significance for the further exploration of the Yaojia Formation in the Longxi area, as well as in other similar lacustrine contexts.

Impact of sequence stratigraphy, depositional facies and diagenesis on reservoir quality: A case study on the Pennsylvanian Taiyuan sandstones, northeastern Ordos Basin, China

The Pennsylvanian Taiyuan Formation of the Shenmu Field in the northeastern Ordos Basin of China contains tight sandstone reservoirs that have recently been commercially produced. An evaluation of the reservoir quality of the Taiyuan sandstones will play a critical role in the development of the field. An investigation was conducted to explore possible effects of the sequence stratigraphy, depositional facies and diagenetic alterations on the reservoir quality of the Taiyuan sandstones based on core descriptions, the examination of thin-sections, and core plug and scanning electron microscope analyses. The Taiyuan Formation consists of lowstand system tracts (LST), transgressive system tracts (TST) and highstand system tracts (HST). The LST sandstones are principally medium-to coarse-grained and are interpreted to have been deposited in the dominant distributary channels of a delta plain. The early TST fine-to coarse-grained sandstones were largely deposited in the underwater distributary channel and mouth bar of a delta front, and the middle TST fine-to medium-grained sandstones were deposited in the shoreface to foreshore environment. The HST silt to medium-grained sandstones were mostly deposited in the mouth bar of a delta front and shoreface to foreshore. The Taiyuan sandstones, which are composed of sublitharenites, quartzarenites and litharenites, suffered from extensive compaction that resulted in a large loss of intergranular porosity before the sandstones were further cemented severely. The sandstone cements are mostly composed of illite, ankerite, calcite and quartz. The Taiyuan sandstones have a particularly low average core plug porosity of 7.41% and horizontal permeability of 0.916 mD, which results from that most of the pores of the sandstones are micropores and secondary pores with poor connectivity. The LST dominant distributary channel, early TST underwater distributary channel and proximal mouth bar, and HST shoreface to foreshore sandstones with relatively coarser grain sizes (mostly medium-to coarse-grained) have relatively higher porosities and permeabilities than the sandstones with relatively finer grain size, which is ascribed to a widespread early dissolution by meteor water leaching and lower content of cements within the coarser-grained sandstones. However, the LST dominant distributary channel sandstones had undergone a more effectively early dissolution and less carbonate cementation than the TST underwater distributary channel and proximal mouth bar and HST shoreface and foreshore sandstones had, which lead to the relatively best reservoir quality of the LST dominant distributary channel sandstones among the Taiyuan sandstones. The study revealed that the reservoir quality of the tight Taiyuan sandstones was controlled by sequence stratigraphy framework, depositional facies, grain size and diagenetic alterations together. The sequence stratigraphy framework played a key role in controlling the reservoir quality of the Taiyuan sandstones by governing the depositional facies and corresponding diagenetic products while the grain size affected the reservoir quality of the sandstones by controlling the content of cement within the sandstones.

How sandstone porosity and permeability vary with diagenetic minerals in the Scotian Basin, offshore eastern Canada: Implications for reservoir quality

The Scotian Basin is an under-explored offshore basin that has produced gas and minor oil from Jurassic–Cretaceous deltaic sandstones. Reservoir quality is an important exploration risk in the basin. This study evaluates whether there are systematic stratigraphic or geographic variations in diagenetic mineral assemblage control of reservoir porosity and permeability. Three data sets are used: a compilation of all available core-plug porosity and permeability measurements (3271 in total), a subset of 577 corresponding to thin sections with lithofacies assignments, and a subset of 35 thin sections principally from reservoir sandstones, in which modal abundance of diagenetic minerals has been determined by image analysis of scanning electron microscope backscattered electron images. Abundances above a 4% threshold of diagenetic kaolinite, calcite and ankerite correlate inversely with permeability, but chlorite and possibly siderite correlate positively. Diagenetic assemblages show no systematic variation with stratigraphy or geography, both of which may involve variable detrital supply. Permeability shows the well-known variation with grain size and depth of burial, but after correcting for these effects it is greatest in estuarine channel and river-mouth turbidite sandstones. This is because these facies preferentially develop chlorite rims on detrital quartz grains and are also the sites of enhanced flow of late basinal fluids resulting in secondary porosity. Local effects such as facies distribution, architecture of channel sandstones, fluid pathways related to complex salt tectonics, and the effects of overpressure are more important than predictable basin-wide effects in controlling sandstone reservoir quality.

High-resolution ultrasonic measurements as proxies to resolve clastic reservoir heterogeneity in a salt-cemented gas reservoir

Petrophysical properties and their heterogeneity within sandstone bodies are key parameters in the evaluation of hydrocarbon and geothermal reservoirs. However, common tools applied to constrain the porosity distribution pattern in borehole cores are commonly time consuming and destructive, or suffer from a resolution limited to the meter to decimeter scale. We examine the applicability of nondestructive high-resolution sonic (HRS) logging of well core sections in the ultrasonic frequency range as a method providing porosity proxy data at the centimeter scale in a clastic sedimentary sequence. The middle Solling Sandstone Member, a gas-bearing reservoir offshore from the Netherlands, is used as a test sample. It consists almost entirely of clean, cross-bedded to massive eolian dune and dry sand-flat deposits that are salt plugged to variable degrees. Plots of HRS logging data versus core-plug porosity values show a positive linear relationship that develops the highest coefficient of determination (R2 = 0.86) in structureless eolian dune sands, most probably caused by the lack of bedding-related anisotropies there. Once calibrated for a particular facies type, this correlation enables the calculation of porosity proxy data from sonic transit time values, acquired at centimetric steps. High-resolution sonic logging thus contributes a reliable and time-efficient, highly spatially resolving quantification of reservoir heterogeneities at centimeter scale and turns out to be a suitable tool for the nondestructive in-situ detection of high-porosity zones in otherwise uniform sandstone successions. Moreover, plots of closely spaced HRS logging–derived porosity proxy data significantly improve interpolation between single, wider spaced core-plug porosity data points.

Carbon Dioxide Storage Capacity of Organic-Rich Shales

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134583, ’Carbon Dioxide Storage Capacity of Organic-Rich Shales,’ by S.M. Kang, SPE, E. Fathi, SPE, R.J. Ambrose, SPE, I.Y. Akkutlu, SPE, and R.F. Sigal, SPE, University of Oklahoma, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has been peer reviewed for SPE Journal. An experimental study was performed on the ability of Barnett-shale core samples to store carbon dioxide (CO2). A new analytical methodology was developed that allows interpreting pressure/volume data in terms of measurements in total porosity and Langmuir parameters of core plugs. The method considers pore-volume compressibility and sorption effects and allows small gas-leakage adjustments at high pressures. Organic shale has the ability to store significant amounts of gas permanently by trapping the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen). Introduction A primary consideration in subsurface sequestration of anthropogenic CO2 is knowledge of gas storability of the geological formations. At first thought, a high-pore-volume formation would seem to be a good candidate for the purpose. However, not all high-porosity formations are suitable for permanent storage of the gas. Some formations lack a physical mechanism for trapping gas. In the absence of a trapping mechanism, a free-gas cap is created in the formation artificially, which may not warrant long-term storage of the injected gas. Needed trapping is associated with fluid/fluid or fluid/solid interactions in porous media such as dissolution, physical adsorption, or some homogeneous and heterogeneous reactions. Depleted oil reservoirs, for example, could be considered acceptable targets. These reservoirs can trap CO2 that is not dissolved in reservoir brine to the extent that their seals for hydrocarbons also form a capillary seal for CO2. A second trapping mechanism is absorption of the injected gas by the immobile residual oil. This can be accomplished through multiple-contact (dynamic) miscibility, which involves simultaneous phase-change and mass-transport phenomena. Saline aquifers, on the other hand, allow aqueous-phase precipitation reactions as well as absorption by the formation water. The dissolved gas promotes density-driven natural convection of water and the related hydrodynamic instabilities. However, the injected gas could be transported and dispersed over large distances, leading to uncertainties concerning its fate. Coalbeds and naturally occurring gas-hydrate reservoirs have been proposed as economically feasible choices because the injected CO2 could be sequestered in sorbed states (adsorbed on microporous coal material surfaces and absorbed into organic macromolecular openings in coal and in water) and could aid enhanced recovery of natural gas by an in-situ molecular-swapping mechanism that promotes release and displacement of methane as a free gas. Introduction of greenhouse gases into these formations, however, is a difficult field operation with a significant or complete loss in well injectivity.

Carbon Dioxide Storage Capacity of Organic-Rich Shales

Summary This paper presents an experimental study on the ability of organic-rich-shale core samples to store carbon dioxide (CO2). An apparatus has been built for precise measurements of gas pressure and volumes at constant temperature. A new analytical methodology is developed allowing interpretation of the pressure/volume data in terms of measurements of total porosity and Langmuir parameters of core plugs. The method considers pore-volume compressibility and sorption effects and allows small gas-leakage adjustments at high pressures. Total gas-storage capacity for pure CO2 is measured at supercritical conditions as a function of pore pressure under constant reservoir-confining pressure. It is shown that, although widely known as an impermeable sedimentary rock with low porosity, organic shale has the ability to store significant amount of gas permanently because of trapping of the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen). The latter is a nanoporous material with mainly micropores (< 2 nm) and mesopores (2-50 nm). Storage in organic-rich shale has added advantages because the organic matter acts as a molecular sieve, allowing CO2—with linear molecular geometry—to reside in small pores that the other naturally occurring gases cannot access. In addition, the molecular-interaction energy between the organics and CO2 molecules is different, which leads to enhanced adsorption of CO2. Hence, affinity of shale to CO2 is partly because of steric and thermodynamic effects similar to those of coals that are being considered for enhanced coalbed-methane recovery. Mass-transport paths and the mechanisms of gas uptake are unlike those of coals, however. Once at the fracture/matrix interface, the injected gas faces a geomechanically strong porous medium with a dual (organic/inorganic) pore system and, therefore, has choices of path for its flow and transport into the matrix: the gas molecules (1) dissolve into the organic material and diffuse through a nanopore network and (2) enter the inorganic material and flow through a network of irregularly shaped voids. Although gas could reach the organic pores deep in the shale formation following both paths, the application of the continua approximation requires that the gas-flow system be near or beyond the percolation threshold for a consistent theoretical framework. Here, using gas permeation experiments and history matching pressure-pulse decay, we show that a large portion of the injected gas reaches the organic pores through the inorganic matrix. This is consistent with scanning-electron-microscope (SEM) images that do not show connectivity of the organic material on scales larger than tens of microns. It indicates an in-series coupling of the dual continua in shale. The inorganic matrix permeability, therefore, is predicted to be less, typically on the order of 10 nd. More importantly, although transport in the inorganic matrix is viscous (Darcy) flow, transport in the organic pores is not due to flow but mainly to molecular transport mechanisms: pore and surface diffusion.

DEPOSITIONAL ENVIRONMENTS AND SEQUENCE STRATIGRAPHY OF THE EARLY TRIASSIC KANGAN FORMATION IN THE NORTHERN PART OF THE PERSIAN GULF: IMPLICATIONS FOR RESERVOIR CHARACTERISTICS

The Early Triassic Kangan Formation is the main reservoir for natural gas in SW Iran and the northern Persian Gulf and is equivalent to the Upper Khuff Formation. Analyses of the formation at the offshore Salman and Minab oilfields indicate that it is composed of 14 facies deposited in tidal flat, lagoon and oolitic barrier settings in the inner part of a carbonate ramp or platform. Vertical variations of microfacies and gamma‐ray log profiles show that the formation consists of three depositional sequences (KG1–3), each consisting of transgressive and highstand systems tracts and each bounded above by a type 2 unconformity. Porosity in the Kangan Formation is dominated by fracture and intercrystalline pore types in highstand systems tract deposits.From a study of core plug porosity and permeability, ten flow units were recognized. Flow units GF1, GF5 and GF8 represent zones with similar flow and storage capacities. Flow units GF3, GF7 and GF9 were attributed to zones of higher flow capacity, and units GF2, GF4, GF6 and GF10 were interpreted as zones with higher storage capacities. In general, flow units which correspond to highstand systems tracts with grain‐supported facies have enhanced reservoir qualities. These flow units are GF10, GF9, GF8 and GF7, together with the upper parts of GF5 and GF4. The best reservoir quality occurs in flow unit GF9 which is located in the HST of sequence KG3. Flow units GF1 and GF2 from sequence KG1, comprising lagoonal and tidal flat facies, have relatively poor reservoir qualities.

Characterization of a Complex Carbonate Heavy-Oil Reservoir

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120423, ’Characterization of Complex Carbonate Heavy Oil Reservoir - A Case Study,’ by Afzal Iqbal,John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al-Yami, Saudi Arabian Chevron; W. Scott Meddaugh, Chevron Energy Technology Company; Mansoor A. Rampurawala, SPE, Bingjian Li, SPE, and Ihsan Gok, SPE, Schlumberger Oilfield Services; and Talal Al Enazi, Kuwait Gulf Oil Company, originally prepared for the 2009 SPE Middle East Oil and Gas Show and Conference, Bahrain, 15-18 March. The First Eocene reservoir is the shallowest producing interval of the Wafra field in the partitioned Neutral Zone between Saudi Arabia and Kuwait. Characterization of this heavy-oil reservoir is challenging because of observed variations in oil viscosity, heterogeneity related to complex mineralogy, a possible dual-porosity system, and the presence of fractures of varing scales. The full-length paper presents several aspects of an integrated approach to characterize the reservoir. Introduction Currently, a large-scale steamflood pilot (LSP) consisting of sixteen 2.5-acre inverted-5-spot patterns is being installed. This will be the first multipattern steamflood of a carbonate reservoir in the Middle East. Oil was discovered in the First Eocene in 1954, and full-scale development began in 1956. The First Eocene has produced only 4% of original oil in place (OOIP), and primary recovery is not expected to exceed 10%. The oil gravity in this heavy-oil reservoir varies from 14 to 20ºAPI. The First Eocene is a depletion-drive reservoir with partial solution-gas drive and limited aquifer support. The estimated gross OOIP within the currently delineated field limit is more than 10 billion reservoir bbl. The reservoir mainly consists of dolomitized packstones and grainstones deposited under arid-to-semiarid conditions on a shallow, very gently dipping, low- to moderate-energy inner shelf or ramp setting in a gently dipping, restricted ramp environment. The presence of minor interbedded evaporites suggests restriction was occasionally sufficient for the development of hypersaline lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds, and exposure surfaces. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well-log and core-plug porosity values greater than 50% are common, and measured permeability values range up to 5,000 md. The First Eocene reservoir has an average depth of approximately 1,000 ft and a gross thickness of approximately 750 ft. Three wells were used in the study to demonstrate the approach of integrating log and core data to evaluate reservoir heterogeneity.

Improved Halbach sensor for NMR scanning of drill cores

A lightweight Halbach magnet system for use in nuclear magnetic resonance (NMR) studies on drill cores was designed and built. It features an improved homogeneous magnetic field with a strength of 0.22 T and a maximum accessible sensitive volume. Additionally, it is furnished with a sliding table for automatic scans of cylindrical samples. This device is optimized for nondestructive online measurements of porosity and pore size distributions of water-saturated full cylindrical and split semicylindrical drill cores of different diameters. The porosity of core plugs with diameters from 20 to 80 mm can be measured routinely using exchangeable radiofrequency coils. Advanced NMR techniques that provide 2D T(1)-T(2) correlations with an average measurement time of 30 min and permeability estimates can be performed with a special insert suitable for small core plugs with diameter and length of 20 mm.