Carbonate Reservoir Characterization
Chapters (9)
The principal goal of reservoir characterization is to construct three- and fourdimensional images of petrophysical properties. The purpose of this chapter is to review basic definitions and laboratory measurements of the petrophysical properties porosity, permeability, relative permeability, capillarity, and saturation. Pore-size distribution is presented as the common link between these properties.
The goal of reservoir characterization is to describe the spatial distribution of petrophysical parameters such as porosity, permeability, and saturation. Wireline logs, core analyses, production data, pressure buildups, and tracer tests provide quantitative measurements of petrophysical parameters in the vicinity of the wellbore. This wellbore data must be integrated with a geologic model to display the petrophysical properties in three-dimensional space. Studies that relate rock fabric to pore-size distribution, and thus to petrophysical properties, are key to quantification of geologic models in numerical terms for input into computer simulators (Fig. 1).
Petrophysical measurements and rock-fabric descriptions provide a basis for quantifying geological descriptions with petrophysical properties but represent point data. Point data are expanded in one dimension by detailed sampling of core material, and the vertical sequence of rock fabrics is used to extrapolate the petrophysical data laterally, as will be discussed in a later chapter. Core samples are normally available from only a few wells, whereas wireline logs are available from most wells. Therefore, most geological as well as petrophysical information must be derived from wireline logs.
Petrophysical properties can best be distributed in the interwell space if constrained by a chronostratigraphic framework.
The three-dimensional spatial distribution of petrophysical properties is controlled by the spatial distribution of geologic processes, processes that can be separated into depositional and diagenetic. In Chapter 4 we discussed depositional processes and focused on (1) the origin of depositional textures, (2) the relationship between porosity, permeability, and depositional texture, (3) the vertical and lateral distribution of depositional textures related to topography, current energy, biologic activity, and eustatical controlled cyclicity, and (4) the fundamentals of sequence stratigraphy. The importance of chronostratigraphic surfaces was emphasized as the fundamental element in constructing a geological framework within which petrophysically-significant depositional textures can be systematically distributed.
In Chapter 5 we stated the basic premise that the three-dimensional spatial distribution of petrophysical properties is controlled by the spatial distribution of geological processes, processes that can be separated into depositional and diagenetic. In Chapter 4 we discussed depositional processes and the relationship between the spatial distribution of depositional textures and petrophysical properties. Reservoir studies have made it abundantly clear that the petrophysical properties found in carbonate reservoirs are significantly different from those of Holocene carbonate sediments due to various diagenetic processes.
A key question in mapping diagenetic effects is the degree of conformance between diagenetic products and depositional patterns. As discussed in Chapter 5, the products of cementation, compaction, and selective dissolution can normally be linked to depositional textures because the transport of material in and out of the system is not an important factor in producing the diagenetic product. However, if the transport of ions in and out of the system by fluid flow is required to produce the diagenetic product, then the product may not conform to depositional patterns. In this case, knowledge of the geochemical, hydrological system may be required to map the diagenetic products, including the source of the fluid and the direction of fluid flow.
Reservoir characterization is defined as the construction of realistic three-dimensional images of petrophysical properties to be used to predict reservoir performance. A key element in constructing reservoir models is modeling the high and low permeabilities. In the past, these images have been prepared by several different methods including (1) the layered reservoir method, (2) the continuous pay method, and (3) the facies method (Fig. 1). In the layered reservoir method, the reservoir is divided into pay zones using correlations based on gamma ray logs, and the net feet of porosity (net pay maps) or the porositytimes-oil-saturation (SoPhiH maps) isopached for each layer. The layers commonly lump several petrophysical rock types, and the average petrophysical values do not characterize the flow properties of the reservoir.
... In this function (Eq. 1), J is a function of lithofacies, rock fabrics (Lucia 2007), and pore structures. Both IFT ( ) and contact angles ( Â ) for given fluid/rock systems depend on reservoir pressure, temperature, and mineral types. ...
... Capillary Pressure Scaling and Fitting. Lucia (2007) reported considerable measurements of capillary pressure curves for consistent sets of carbonate microfacies (i.e., mudstone, wackstone, packstone, and grainstone). We selected several representative measurements and used them here for our analysis. ...
... This appendix shows the fitting of air/water drainage capillary pressure data (Lucia 2007) based on the Brooks-Corey model. The R 2 is acceptable for the fitting. ...
Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale.
Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin.
We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one.
We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.
... vuggy and mouldic) in carbonates can make these rocks stiffer and stronger than those dominated by, for example, interparticle porosity, such as clastic rocks. Even though fracture pore space barely ranges between 0% and 4% of the total porosity, but their impact on carbonates reservoir quality and their elastic behaviour is much more than many other parameters (Lønøy, 2006;Lucia, 2007;Murray, 1960). However, due to the difficulties in measuring actual pore types in carbonate rocks, the application of rock physics models for reservoirs with different pore types is challenging (Avseth et al., 2005;Lubis & Harith, 2014;Ma et al., 2021;Sayers, 2008;Xu & Payne, 2009). ...
... Various types of pores have been studied in sedimentary rocks (especially carbonate) and been classified based on their facies, depositional origin, and petrophysical properties (Archie, 1952;Choquette & Pray, 1970;Lønøy, 2006;Lucia, 2007;Murray, 1960). For example, Lucia (2007) classified stiff pores into separate vugs and touching vugs for application in the petrophysical study. ...
... Various types of pores have been studied in sedimentary rocks (especially carbonate) and been classified based on their facies, depositional origin, and petrophysical properties (Archie, 1952;Choquette & Pray, 1970;Lønøy, 2006;Lucia, 2007;Murray, 1960). For example, Lucia (2007) classified stiff pores into separate vugs and touching vugs for application in the petrophysical study. He showed that intra-fossil, grain moulds, and intra-grain microporosity are examples of intraparticle, fabric-selective separate vugs. ...
The quality of carbonate reservoirs is linked to their rock properties and surrounding stress settings which can play a vital role in their production optimization and development programs. Imposing various stresses can increase porosity and permeability by creating joints and cracks across the rock mass. Therefore, developing methods to identify and accurately evaluate fractures in carbonate reservoirs is very significant in reservoir characterization. To deal with this necessity, we developed a fracture porosity estimation method using empirical and analytical solutions based on the wireline data considering stress conditions. The proposed methodology was applied to a carbonate reservoir as the case study. As fracture porosity is sensitive to stress, experimental tests were conducted on the core samples using triaxial hydrostatic tests. These tests are needed to simulate reservoir conditions to investigate the relationships between fracture volume fraction and the applied stress. A substantial porosity loss was observed during the hydrostatic test, which can be linked to the crack porosity closure. The reliability of our results was validated by thin section, CT‐Scan images, velocity deviation method, elastic boundary laws, and image logs. Eventually, we introduced an equation to estimate in‐situ fracture porosity from the relationship between porosity and effective confining pressure. We verified the repeatability and generality of our proposed methodology using a blind well, and the results indicate a comparable level of accuracy. Our findings are applicable for estimating crack porosity for rock physics modelling purposes of detecting fracture zones in the absence of image logs and core data. Also, by calibrating and optimizing the constant parameters in our proposed relationship, one may further estimate crack density in any other given carbonate reservoirs. This article is protected by copyright. All rights reserved
... Because of variability in reservoir quality and facies patterns, it is necessary to discriminate different platform types (with diverse characteristics) to evaluate hydrocarbon-bearing units. Reservoir geometry is mainly controlled by platform type, while reservoir quality is determined by environmental conditions of various facies [2,3] and later diagenetic impacts. In turn, platform geometry and type, along with the facies successions and patterns, control depositional facies and sequence stratigraphic framework [2][3][4][5]. ...
... Reservoir geometry is mainly controlled by platform type, while reservoir quality is determined by environmental conditions of various facies [2,3] and later diagenetic impacts. In turn, platform geometry and type, along with the facies successions and patterns, control depositional facies and sequence stratigraphic framework [2][3][4][5]. ...
In the Cenomanian, the southern passive margin of the Neotethys Ocean was dominated by a giant carbonate factory. This succession is known as Sarvak Formation, a significant reservoir in Iran. This study focuses on a detailed analysis of facies variations and paleoenvironmental reconstruction, including the interpretation of the platform types, during this time interval. Based on field observations and petrographical studies, 12 facies have been recognized and ascribed to six facies belts on a carbonate ramp. Sub-environments include the outer ramp and basin (distal open marine), talus and channel (mid-ramp) and lagoon and shoal (inner-ramp). The frequency of the facies and isochore maps indicate the paleoenvironmental conditions and their spatial variations in the study area. Based on all data and analyses, the suggested conceptual model for the Sarvak Formation in the Lurestan Zone is an isolated platform surrounded by two ramps. The upwind and downwind parts of these ramps were located in the central and northern sub-zones of the Lurestan Zone. This model can be used as a template for isolated platforms worldwide.
... Over the past decades, much research has been conducted to comprehend carbonate rock properties and their spatial distributions (e.g. porosity, permeability and seismic properties; Clerke et al., 2008;Eberli et al., 2003;Fournier et al., 2011;Fournier & Borgomano, 2009;Lambert et al., 2006;Lucia, 1999;Moradi et al., 2019;De Periere, 2011;Teillet et al., 2020). The Arabian/Persian Gulf (named 'Gulf' in this paper) is recognised as a modern, albeit miniature, analogue to numerous Cretaceous and Jurassic carbonate sequences of Middle East reservoirs. ...
In numerous carbonate reservoirs in the Middle East, peloidal packstone‐grainstones are rock types with excellent pore storage potential in micritised microporous grains. However, the origin of the micro‐porosity and associated micro‐spar remains unclear, and one hypothesis is that both micro‐spar and porosity originate from early marine micritisation and were later altered during subsequent diagenesis (i.e. cementation recrystallisation). The south‐eastern coast of the Arabian Gulf is recognised as a modern, albeit miniature, depositional setting analogue to Mesozoic carbonate sequences that form the supergiant reservoirs of the Middle East. Using optical microscopy, backscattered scanning electron microscopy and carbon and oxygen stable isotope analysis the present study aims to document the nature of internal microstructures of micritic envelopes and peloids from the surface sediments of various sub‐environments of the Abu Dhabi Lagoon. Results highlight a high degree of diversity and heterogeneities of most micritic envelopes and peloids observed across the sub‐environments. First, carbonate grains from ooid and bioclastic shoals show the simpler micritic envelopes. Here, micritic envelopes and peloids show sparse microborings filled with banded radial aragonite cement, a pattern of production of cryptocrystalline texture (e.g. micritisation) that is similar to the sequence of micritisation observed in the modern sediment of the Great Bahama Bank. Conversely, in the subtidal and intertidal zones with mangroves or seagrass, the micritic envelopes and peloids are much more complex and show multiple generations of microborings that are either empty or filled with carbonate materials of varying types (i.e. various cements, fragments, etc.).
... The assembly of lithofacies and pore types is also used to classify carbonate reservoirs (Zhang, 1992;Nabawy et al., 2023). In addition, there are classification methods based on pore structure (Aqrawi et al., 1998;Ausbrooks, 1999;Clerke, 2003;Aqrawi et al., 2010;Burrowes et al., 2010), conventional logging methods (Ross et al., 1995), nearest neighbor (Folk, 1959;Embry, 1971), nuclear magnetic resonance (Folk, 1962;Frank, 2005;Lucia, 2007;Kharrat et al., 2009;Gunter et al., 2014). In general, reservoir classification methods are mostly geological genesis or pore-structure based, and there is no combination of the geological genesis type and petrophysical facies. ...
Rock types with similar lithological components and pore structures form the basic units of porous limestone reservoirs; this influences the reservoir evaluation efficiency and water injection development. As the main oil and gas pay zone in central Iraq, the Cretaceous Khasib Formation reservoirs are influenced by deposition, dissolution, and cementation. There is strong vertical heterogeneity in the most important zone of the Kh2 layer, with diverse rock types and complex pore structures. Based on core observation and casting thin-section identification, the Kh2 layer in the study area was divided into eight lithofacies types as argillaceous bioclastic wackestone, planktic foraminiferium wackestone, lamellar bioclastic wackestone, intraclastic–bioclastic packstone, patchy green algae packstone, green algae and pelletoid packstone, benthic foraminiferium–bioclastic packstone, and intraclastic grainstone. Along with the reservoir void space types of the lithofacies, capillary pressure curves are used to quantitatively analyze the throat and pore features of the different lithofacies. From the porosity–permeability cross-plot characteristics and distribution of pore types, 14 petrophysical facies are obtained. Finally, based on the differences between the lithofacies and petrophysical facies, the Kh2 member is divided into 13 rock types with different geological origins and petrophysical characteristics. Among these, the rock type RT1-8-14 has the best and rock type RT1-1-1 has the worst physical properties among the reservoir rock types. This study provides an optimization method for carbonate reservoir evaluation and is expected to be beneficial for efficient development of similar carbonate reservoirs.
... Because it is located along the hanging wall of the Main Boundary Thrust (MBT) and in the active tectonic regime of the Himalayan Orogeny, the KF − UC is extensively fractured. Furthermore, extensional movements and natural hydraulic fracturing can result in microfractures (Longman 1985;Lucia 1999). In summary, tectonics has caused fracture porosity, which has increased the reservoir potential. ...
Tight carbonate reservoirs are complicated by their vast heterogeneity, which is attributed to diagenetic and depositional processes. The new discovery of natural gas in the tight carbonate reservoir of the Upper Cretaceous Kawagarh Formation (KF− UC) in Pakistan makes it crucial to study the factors controlling reservoir properties. This study investigated the sedimentology and reservoir characteristics of KF− UC using integrated petrography, scanning electron microscopy and energy-dispersive X-ray spectroscopy (SEM-EDS), and petrophysical techniques. The microfacies analysis of KF− UC indicates mudstone and wackestone, identified in the proximal and distal outer ramp settings of the homoclinal carbonate ramp. Diagenetic processes such as compaction, micritization, dolomitization, cementation, neomorphism, and dissolution, which represent meteoric and marine phreatic mixing zones and burial diagenetic settings, have modified the reservoir characteristics of KF− UC. The net porosity of KF− UC could be enhanced by dolomitization, dissolution, and fracturing, making it a better petroleum reservoir. With an average porosity of 2.3%, microporosities such as intercrystalline/interparticle, intracrystalline/intraparticle, vuggy, and fracture were identified in KF− UC, designating it as a tight carbonate reservoir. The outcrop and well data exhibit excellent correlation; nevertheless, the well’s net pay is inadequate due to the influence of complex tectonic structures along significant faults within the study area. Furthermore, the results of this study were compared with the Gurpi Formation of Zagros Basin, Iran, and the Aruma Formation of Central Saudi Arabia, highlighting similar sedimentological characteristics, thus emphasizing the need to initiate such projects in other regions with similar settings to further strengthen petroleum exploration.
... In carbonates, rock fabric is affected by several factors including postdepositional processes, interplay of diagenesis, multiscale pores, and complex mineral composition (Skalinski et al., 2015). Incorporating spatial variations in pore structure, mineralogy, grain size, and type (represented as rock components in this paper) in heterogeneous carbonates is important in identifying rock classes with similar petrophysical properties for enhanced reservoir characterization (Lucia 1995;Jennings and Lucia 2003;Lucia 2007). Capturing spatial variations in textural properties of rock components is challenging at the resolution of conventional well logs. ...
Reliable rock classification is important for estimating petrophysical properties and making informed production decisions. High-resolution image data (e.g., image logs, core photos, and CT-scan images) can enhance rock classification by incorporating rock fabric (i.e., spatial variations of rock components) information. The additional value that image data contributes to enhancing formation evaluation is essential to assess for making informed decisions on acquiring expensive image data. Recently developed methods have been proven successful for image-based rock classification mainly in siliciclastic formations. However, the reliability of image-based rock classifications in heterogeneous carbonate formations comprising complex depositional sequences has yet to be investigated. The objectives of this paper are (a) extracting rock textural features to obtain image-based rock classes from high-resolution images that capture changes in depositional sequences of complex carbonate formations, (b) assessing the impact of different sources of image data on the enhancement of rock classification, and (c) evaluating the reliability of rock classes identified by integrating well logs and image data and its impact on formation evaluation. First, we conduct conventional well-log interpretation and preprocess the image data (i.e., CT-scan images, core photos, and image logs) using the image masking techniques to remove artifacts and noise from the available images. Then, we extract textural features from wellbore/core image data using a gray-level co-occurrence matrix (GLCM) algorithm that captures the spatial relationship of pixel intensity values in images to quantify rock fabric. Next, we adopt an unsupervised algorithm to detect rock classes using the extracted features. We perform and compare rock classification through three different methods taking as inputs: (a) only conventional well logs, (b) different sources of image data (i.e., image logs, core photos, and CT-scan images), and (c) the integration of conventional well logs and image data. Finally, we compare the outcomes of these three methods and their impact on assessing petrophysical properties. We applied the proposed workflow on image data (i.e., CT-scan images, core photos, and image logs) and well logs in a pre-salt carbonate formation having a complex syn-depositional rock texture and pore system altered by a diagenetic process. The rock classes obtained by high-resolution core photos were more successful in detecting the post-depositional features in heterogeneous carbonates than rock classification using other sources of image or well-log data. The contribution of image data was more measurable in rock classes with higher levels of heterogeneity and spatial variations of rock fabric. The outcomes of this work are (a) to capture changes in depositional sequences of heterogeneous carbonate formations in rock classification, (b) to assess the impact of different sources of image data (i.e., CT-scan images, core photos, and image logs) on rock classification efforts of complex carbonate formations, and (c) to enable taking decisions on the optimum type of image(s) for image-based rock classification that best captures rock fabric information in a given formation.
... According to Xu and Payne (2009), I herein used velocity-stress relationships for estimating crack-related porosity (ϕ crack ). The Wyllie time-average equation (Wyllie et al., 1956) and Lucia (1999) were used to distinguish between interparticle vuggy and non-vuggy pore systems. Details of pore type quantification using well-log and thin sections were based on the works by Weger et al. (2009), Zhao et al. (2013) and Sharifi et al. (2018), with the results presented in this work. ...
Since many years ago, ultrasonic velocity has been used to investigate the physical and mechanical behaviour of rocks, thereby playing an important role in reservoir characterization and seismic interpretation. In order to develop the knowledge of ultrasonic tools, I performed a noble analysis on the ultrasonic behaviour of rocks under confining stress and evaluated a distinctive property of porous media that is measured as the area under the stress–velocity curve (here defined as S*). I further investigated its relationship with elastic and mechanical behaviours of rock. To validate the theoretical framework developed in this work, 20 core plugs from various rock units with complex microstructures were subjected to triaxial compressional tests to calculate their area under the curve. Calculations were made for crack-closing, elastic and post-elastic stages (e.g. pore collapse) along the ultrasonic velocity–stress curve. Moreover, the selected samples had their microstructure investigated by thin-section studies to quantify their porosity and pore type. The results were analysed to check for the effect of pore type on S* in different stages of the stress–velocity curve. Based on the outputs of the analysis of variance and Pearson's correlation coefficient analysis, the curve had its shape and underlying area closely related to the porosity and pore geometry. Indeed, the results showed that the shale and sandstone with micro cracks and carbonate with stiff pores correspond to smaller and larger areas under the curve in crack-closing and inelastic stages, respectively. Cross-correlating the results to compressibility (inverse of bulk modulus), it was figured out that the calculated area under curve was well consistent with the compressibility. In addition, S* represents both static and dynamic behaviours of the rock, and the results revealed that the shape and curvature of the stress–velocity curve give valuable information about the rock microstructure. Another finding was the fact that the type of fluid and wave velocity seemingly affect the S*. Our findings can help interpret wave velocity behaviour in reservoir rocks and other stressful porous media.
... Sandstones bear intermediate m values up to 2.2, depending on the degree of cementation (Schön 2015). The presence of fracture porosity is typically characterized by reduced cementation factors < 1.8 that can be as low as 1.1 to 1.3 (shown for fractured carbonates by Lucia 2007;Schön 2015). ...
In petrophysics, physical rock properties are typically established through laboratory measurements of individual samples. These measurements predominantly relate to the specific sample and can be challenging to associate with the rock as a whole since the physical attributes are heavily reliant on the microstructure, which can vary significantly in different areas. Thus, the obtained values have limited applicability to the entirety of the original rock mass. To examine the dependence of petrophysical measurements based on the variable microstructure, we generate sets of random 2D microstructure representations for a sample, taking into account macroscopic parameters such as porosity and mean grain size. For each microstructure produced, we assess the electrical conductivity and evaluate how it is dependent on the microstructure's variability. The developed workflow including microstructure modelling, finite element simulation of electrical conductivity as well as statistical and petrophysical evaluation of the results is presented. We show that the methodology can adequately mimic the physical behaviour of real rocks, showing consistent emulation of the dependence of electrical conductivity on connected porosity according to Archie's law across different types of pore space (micro-fracture, inter-granular, and vuggy, oomoldic pore space). Furthermore, properties such as the internal surface area and its fractal dimension as well as the electrical tortuosity are accessible for the random microstructures and show reasonable behaviour. Finally, the possibilities, challenges and meshing strategies for extending the methodology to 3D microstructures are discussed.
... Carbonate reservoirs exhibit diverse heterogeneity styles controlled by variable combinations of stratigraphic architecture, the pore-scale products of original depositional fabrics modified by diagenesis, and tectonic features such as fractures and stylolites (Roehl and Choquette 1985;Tucker and Wright 1990;Chilingarian et al. 1992Chilingarian et al. , 1996Lucia 1999Lucia , 2007Ahr 2008;Burchette 2012). Such heterogeneities exert a profound control on hydrocarbon recovery and the economics of field development, but for various reasons they are often overlooked during the early stages of reservoir exploitation. ...
Middle Eastern carbonate petroleum reservoirs exhibit a range of heterogeneities which consist of variable combinations of primary stratigraphic and secondary diagenetic and structural characteristics. These produce diverse permeability architectures which can exert a profound influence on reservoir performance during secondary recovery. Of particular importance are laterally persistent discrete zones of elevated permeability (DZEP) that typically make up a volumetrically minor proportion of the reservoir yet show disproportionately high fluid inflow or outflow. The stratigraphic, diagenetic, and structural origins of elevated permeability in Middle Eastern carbonate reservoirs are considered here and the consequences of such features for reservoir performance are discussed.
The term DZEP denotes geological sources of elevated permeability at least an order of magnitude greater than background reservoir properties. Stratigraphically organised DZEP comprise coarse-grained layers, event beds or parasequence tops or bases in neritic or platform interior settings. Other origins include bioturbated layers, grainy clinothems, and bed-scale, grain-size variations in shoal deposits. Diagenetic DZEP are typically dissolution horizons with mouldic and touching-vug pore networks or dolomitized intervals which often overprint stratigraphic DZEP. Structural DZEP include individual faults, fracture corridors, and fracture concentrations related to mechanical stratigraphy.
During production through natural pressure depletion, DZEP may dominate well productivity. Under secondary recovery, the same intervals may dominate inter-well fluid flow, causing flood conformance issues, cross-zone fluid movement, bypassed pay, and earlier-than-expected water or gas breakthrough to production wells. Optimisation of production and ultimate recovery relies on collecting the correct kinds of data at a sufficiently early stage in the reservoir characterisation process to permit their inclusion in static and dynamic reservoir models.
... These reservoirs are characterized by heterogeneous and complex pore networks resulting from wide variability both in the conditions prevailing in the depositional environment (such as depositional energy, water depth, climate, and tectonism) and in the diagenetic processes involved (i.e. fluid-rock interactions such as micritization, calcite cementations, dolomitization, mechanical and chemical compaction, dissolution and karstification), which can lead to either enhanced or deteriorated reservoir properties (Goodner et al., 2020;Lucia, 1983Lucia, , 1995Lucia, , 1999Moore, 1989Moore, , 2001Ronchi et al., 2010). These pore-space heterogeneities result in highly variable reservoir permeabilities, that represent a challenge for prospection in carbonate systems. ...
... The anhydrite facies align with deposition in a restricted coastal lagoon or exposed tidal flat/sabkha environment ( Contrary to their common contribution to poor reservoir quality, some studies by Lucia, ;Lucia, (1999); Lucia & Ruppel, (1996), have documented that a significant presence of anhydrite in some cases might not necessarily affect its quality, and even in some instances may improve the quality of the reservoir. ...
The Lower Clear Fork from Tex-Mex, S.E. Field on the Central Basin Platform is a typical complex reservoir that displays high heterogeneity in lithological and petrophysical properties. The unit represents a producing reservoir succession of Leonardian platform carbonates deposited in shallow marine water during the Early Permian. The sediment of the Lower Clear Fork is composed of a mixed succession of dolomite interbedded with anhydrite, minor clay minerals, and siliciclastics. The high heterolithic nature of the reservoir makes efficient recovery of hydrocarbons difficult. This situation requires an understanding of the variability in depositional facies in terms of mineralogy, depositional textures and structures, and an assessment of its petrophysical properties. As of December 2023, cumulative production of hydrocarbon from the Tex-Mex, S.E. Field reached about 88,308 barrels of oil equivalent.
The study at Tex-Mex, S.E. Field utilized 338.9 ft (103.3 m) of Lower Clear Fork cored sample, core data, and wireline data from a key well. Key data utilized included core descriptions, wireline logs, routine core analysis data, petrographic thin sections, and whole rock mineralogical data from X-ray Diffraction. These data helped to (1) determine the paleoenvironments under which the Lower Clear Fork sediments were deposited, (2) build a core-calibrated petrophysical mineral model of the Lower Clear Fork from wireline logs and XRD mineralogy, and (3) assess the petrophysical properties of the Lower Clear Fork reservoir.
The integration of core/log analysis, XRD data, routine core data, and petrographic observations revealed seven (7) facies regrouped into four (4) major facies associations each representing the mineralogy, sedimentary textures, pore characteristics, and paleodepositional environment. The Lower Clear Fork, a second-order Leonardian sequence represents facies transitioning from dolomitized inner to ramp crest facies (skeletal/peloidal wackestone to grain-dominated packstone) in the lower part, to dolomitized restricted lagoon and tidal flats/sabkha facies (dolomudstone/anhydrite) in the upper part. The petrophysical characteristics of the Lower Clear Fork reservoir were dominantly controlled by post-depositional processes that altered the primary carbonate mineralogy and pore development. The principal diagenetic processes included reflux dolomitization, gypsum precipitation (later transformed into anhydrite), and dissolution of anhydrite and dolomite cement.
Mineralogical results revealed the dominance of dolomite, anhydrite with minor amounts of clay, and siliciclastics. Calibrated porosity values within the interval vary from 0.5% to 10%, while Klinkenberg permeability was in the range of 10-4 mD to 17.6 mD. The Lower Clear Fork facies showed dominance of high water saturation values, reaching up to 95.4%, and comparatively low oil saturation levels, peaking at a value of 14.4% in the dolopackstone facies. Overall, the Lower Clear Fork reservoir is of low quality, however, the grain-rich dolopackstone facies offered the most favorable reservoir properties when compared with other facies in the interval.
... The Eocene limestone unit possesses complicated pore networks and facies distributions (Chandra et al., 2015;Mondal and Singh, 2022a); however, the significance of different pore types and pore connectivity is not very well characterised in terms of an experimental framework. To establish better reservoir models, the types and distributions of interconnected pores must be characterised within the pore network of carbonates (Eberli et al., 2003;Lucia, 2007;Brigaud et al., 2014). Advanced petrophysical analysis must be combined across multiple scales to facilitate the identification of heterogeneities in carbonate rocks . ...
Carbonate rocks exhibit complex and heterogeneous pore structures; such heterogeneity is manifested by the occurrence of a wide variety of pore types with different sizes and geometries as a result of depositional and diagenetic processes. These complications substantially increase the uncertainty of predicted rock hydraulic parameters because samples with comparable porosities might have very different permeability values. In this study, small-scale characterisation of porosity and permeability in heterogeneous Eocene limestone samples from the Bassein Formation of the B-X structure of the MK Field in Mumbai Offshore Basin, India, was carried out, employing an integrated framework that incorporates thin-section petrography, routine core analysis, mercury injection capillary pressure and nuclear magnetic resonance data. The pore characteristics of these carbonates range from poor to excellent. The studied samples exhibited large ranges of porosity, permeability and other associated petrophysical attributes. The pore types, as well as their orientations and connectivity, are the primary factors causing the heterogeneity. Because of the complexity of the pore networks, a simple lithofacies classification alone would have been insufficient to link porosity and permeability. The reservoir characteristics in the study area are strongly linked to the development and/or destruction of reservoir porosity–permeability during different phases of diagenesis. Twenty-four carbonate core samples from the limestone unit were studied and classified into microfacies and pore type classes, producing an accurate assessment of reservoir attributes. The comprehensive workflow incorporates the pore volume distributions and pore throat attributes for each rock type. Three carbonate microfacies were identified by petrographic analysis and their petrophysical characteristics, such as porosity, permeability, pore throat size, pore volume and fluid flow factors, were measured. The study demonstrates how macroporosity, mesoporosity and microporosity are associated with various rock types and how they affect permeability and cementation exponents. The results of this study provide a comprehensive experimental framework for geological and geophysical interpretation that can be applied to identify potential reservoir facies and strengthen our understanding of heterogeneous carbonates. The framework can also be used to guide reservoir evaluation of similar heterogeneous formations in other areas.
... The relative contributions of these elements to the total gamma ray (GR) log profile of a borehole can be differentiated by a spectral GR logging tool, and such patterns are commonly examined in hydrocarbon exploration wells as a means of estimating mineralogy, differentiating depositional environments, and recognizing significant stratigraphic surfaces (Davies & Elliott, 1996;North & Boering, 1999;Serra, 1984). Scarce studies documenting spectral GR significance are available to date for carbonate strata, although there appears to be a widespread appreciation that K and Th reflect clastic content, whereas U is determined by diagenetic processes involving oxidation state changes (Lucia, 1999). Most of the published carbonate spectral GR assessments ascribe localized U enrichment to late diagenetic fluid movements (Fertl & Rieke, 1980;Hassan et al., 1976;Luczaj, 1998). ...
Non-marine carbonates are not fully understood from several points of view, including facies and petrophysics (porosity and permeability), as well as their controlling processes The Hard Cap of the Mupe Member in the Purbeck Limestone Group of the Wessex Basin contains thrombolites presenting varying porosity degrees. This paper aims to carry out a multi-scale characterization, focusing on Mupe Member petrophysical properties and providing insights into its depositional environ- ments and diagenetic history. Non-marine carbonates are characteristically heterogeneous, and their components are highly diverse, comprising various types of primary micrites, bioclasts and other particles, as well as different types of cement precipitated at different diagenetic stages. These components display distinct geochemistry and petrophysics signatures. This study integrates microtomography, petrographic, geochemistry, and petrophysics data from Hard Cap Purbeck sam- ples obtained from a block store at the Bowers Quarry in Portland (50°32′49.4ʺ N, 2°26′53.1ʺ W), with the aim of better understanding these challenging reservoirs. Hard Cap porosity is predominantly the result of bioturbation and dissolution. Organisms such as ostracods and gastropods are believed to have played a key role in porosity development, as their activity resulted in sediment mixing and the development of pore spaces. Carbonate mineral dissolution also contributed to porosity development, with the most significant dissolution occurring during periods of increased groundwater flow. A stable isotope analysis indicated that dissolution was likely the result of acidic groundwater, which can dissolve carbonate minerals present in the limestone. The Hard Cap cementation process is the primary cause of its low porosity and permeability. The analysis also revealed that the Hard Cap was deposited in a shallow environment with alternating subaerial exposure and inundation periods. The paleo controls concerning Hard Cap porosity development were found to be largely associated to lake level and climate changes. During high lake level periods, the Hard Cap was submerged and subject to increased sedimentation, reducing porosity development. Conversely, during low lake level periods, the Hard Cap was exposed to increased ground- water flow, promoting dissolution and porosity development. Overall, this study provides important insights into the porosity origin of the Mupe Member Hard Cap and the paleo controls that influenced its development. These findings may be useful in the exploration and development of hydrocarbon reservoirs located in similar geological settings.
... A composite image of all the roughness, shapes, pores, and phenomena caused by water corrosion, above and below the surface, in various soluble geological formations, is karst (Ford, 2007;LaMoreaux, 2001). Various factors are involved in the formation and spread of this diagenetic phenomenon, such as the type and degree of solubility of rocks, the physicochemical properties of running and submerging waters, climate, geomorphology, hydrologic and hydrogeological conditions, joints and fractures density and tectonic dynamics (Daoxian, 1997;Yu, 2016;Kaufmann, 2016;Lucia, 2007). The study and management of karst areas have long been the focus of geologists, hydrologists, geomorphologists, hydrogeologists, environmentalists, and even eco and geotourists (LaMoreaux, 2001;Dafny, 2015). ...
This study focuses on identifying zones and karstic phenomena using the RS & GIS method along with Fuzzy logic integration and the Hierarchical Analysis Process (AHP) in part of Neka catchment in Mazandaran province in the north of Iran. In this research, eight lithological factors, density and distance from the fractured lineaments, density and distance from the drainages, topographic slope, precipitation and vegetation status, were extracted from satellite and archival data as well as field data. Then these factors which affect karst formation and development are fuzzy and are weighted by the AHP method and integrated with T-norm, T-conorm (S-norm) and Compromise Operators. The results were processed by using software such as ArcGIS, ENVI, RockWorks, IDRISI, Expert Choice and PCI Geomatica, which were evaluated based on fieldwork. The results of this study show that most karst developments occurred in Lar Formation with the upper Jurassic. According to field visits, the best and most appropriate output for fuzzy layers integration are the use of a compromise operator in the range of 0.9 to 0.95. In spite of the suitable ability of Landsat 8 bands to extract lineaments due to vegetation status and other environmental conditions, the use of DEM was also necessary. This study shows that the use of new remote sensing and GIS technology, combined with Fuzzy logic and AHP, increases accuracy and speed and reduces cost in karst studies.
... Previous studies argued that the formation of anhydrite fabrics has occurred in different sedimentary basins and under special conditions, summarizing the following: a) crystallization from a saturated solution in the capillary zone beneath the sabkha surface under an arid climate (e.g. West et al., 1979;Butler et al., 1982;Einsele, 2000;Gündogan et al., 2005;Aleali et al., 2013), b) direct or indirect precipitation in shallow subaqueous settings such as coastal and lagoonal regions (Schreiber, 1988;Rouchy et al., 1994;Sarg, 2001), c) a sharp drop in sea level, long-term exposure of sediments, and widespread meteoric diagenesis in the isolated large evaporite basins (Gill, 1977;Kendal, 1989;Betzler and Pawellek, 2014), d) the displacive and replacive growth within the molds of former gypsum crystal in mesogenic realms (Rahimpour-Bonab and Kalantarzadeh, 2005;Lucia, 2007), and e) the product of diagenetic processes, dissolution, and mineral interactions during progressive burial by sulfate-rich waters (Machel, 2013;Warren, 2016;Mohammed-Sajed and Glover, 2022). ...
... The petrographic features of the depositional setting, e.g. the variety of carbonate grains and variations in the diagenesis, influence the complex system of porosity and, thereby, the permeability of rocks resulting in the petrophysical heterogeneity and anisotropy (Lucia 1999;Lønøy 2006). In this sense, a large number of researchers and authors (e.g. ...
... Porosity and permeability are the primary petrophysical parameters that define the reservoir characteristics of sedimentary rock. However, carbonates have a very heterogeneous porosity at various scales, ranging from micro-pores to large vuggs; this makes it difficult to construct petrophysical models (Hartmann and Beaumont, 1999;Lucia, 1999). Carbonate reservoirs have a multiple-porosity system (Lai, 2019) that is entirely different from sandstone reservoirs, and this has a heterogeneous impact on the petrophysical parameters of reservoirs (Wang et al., 2016;Muzzullo, 1992). ...
The early Eocene carbonate reservoir, Sui Main Limestone (SML), is the largest gas reservoir in Pakistan. In the Qadirpur area, more than 30 wells have been drilled, some of which have been declared dry or abandoned due to poor reservoir characteristics or facies variation. The aim of this work is to re-evaluate the reservoir characteristics and facies identification of Sui Main Limestone by using petrophysical analysis and rock physics modeling in the Qadirpur field in the Middle Indus Basin of Pakistan. The reservoir characterization of carbonate rocks is difficult because of their complex pore networking. The well data on five exploratory wells drilled in this gas field are used. The log-derived porosity varies in a very large range of 2%–36%, with an average of 14%–34%. The average porosity of the clean carbonate intervals is 10%–14% and thus has the capacity to accumulate hydrocarbon. The high porosity value indicates the presence of micro-fractures in Sui Main Limestone. These micro-fractures and secondary pores are well interconnected and allow the pore fluids to communicate. The secondary porosity is mainly due to the presence of vuggs and fractures in Sui Main Limestone. The volume of shale varies from 11%–38% in the wells. The net pay zones have hydrocarbon saturation in the range of 40%–70%, which is mainly gas. Using wireline log response, the formation is divided into three facies: limestone, shale, and shaly limestone. This comprehensive work may help improve the prediction of the reservoir quality in heterogeneous carbonate reservoirs and optimize field development.
... A better understanding of the spatial distribution of the facies and oil-prone intervals of the carbonate platforms is crucial. The spatial distribution of reservoir zones with petrophysical attributes of interest are controlled by facies association in the depositional setting (Lucia, 2007;Ahr, 2008), and investigating the evolution of the platform can further enhance our understanding of sea level changes and depositional environment (Schlager, 2005;Bonvallet et al., 2019). ...
The Sarvak Formation is a carbonate interval (as part of the Bangestan Group) deposited during the Cretaceous (late Albian-late Turonian), which hosts considerable hydrocarbon reserves. We logged five surface sections west of the Zagros Basin to depict the depositional environment and sequence stratigraphy of the Sarvak Formation. The formation comprises five 3rd order depositional sequences, including six facies belts deposited on a carbonate platform. The lower part of the formation comprises two depositional sequences (late Albian -early Cenomanian) deposited on a ramp. In contrast, the rest of the formation (Cenomanian to early Turonian), composed of three depositional sequences, was deposited on a rimmed shelf. The shift from ramp to the shelf was presumably due to changes in the tectonic regime of the Arabian Plate from passive to active margin, and in part due to the obduction of the Neotethys’ ocean crust during the late Middle Cretaceous, accompanied by the development of shoal complex and rudistic reefs. This resulted in the development of some isolated carbonate platforms bordered by intrashelf basins, particularly in the Lurestan Zone. Active basement faults caused the exhumation of the platform and the development of unconformity on the Cenomanian-Turonian boundary. The five depositional sequences we studied were mainly controlled by eustatic change(s) during Albian, mid-Cenomanian to Turonian.
This chapter delves into the core principles of petro-physical properties and rock physics, forming the foundation for advanced reservoir characterization and seismic interpretation. By examining the elastic properties of rocks—such as Young’s modulus, shear modulus, bulk modulus, and Poisson’s ratio—the chapter explains how rocks respond to seismic waves and stress. Additionally, key properties like porosity, permeability, and fluid saturation are explored for their critical roles in predicting reservoir behavior, essential for energy exploration and production. The chapter also introduces rock physics models, including Gassmann’s equations for fluid substitution and Biot’s theory of poroelasticity. These models enhance seismic interpretation and inform practical applications, from lithology prediction to reservoir management. A section on Carbon Capture, Utilization, and Storage (CCUS) underscores the importance of petro-physical properties in identifying storage sites and monitoring CO2 sequestration. Finally, the chapter addresses unique geological settings—such as deltas, salt domes, and clastic reservoirs—illustrating how petro-physical properties shape exploration strategies. Emphasizing the convergence of rock physics and seismic interpretation, the chapter advocates for continued innovation and collaboration between academia and industry to meet the dynamic challenges of the energy sector.
The Asmari succession is among the greatest productive hydrocarbon-bearing rock units in the Middle East. This paper examines the biostratigraphy, sedimentary environment, and depositional sequence of the Asmari reservoir in the Haft-Kel Field. This succession in the Haft-Kel Field contains limestones, dolostones, anhydrites, and argillaceous limestones and is bounded between the Pabdeh and Gachsaran formations. Paleontological research has led to the creation of three assemblage zones in this region. These zones present an age range from the late Oligocene (Chattian) to the early Miocene (Aquitanian). Also, detailed petrographic examinations and facies analysis led to the recognition of 14 types of microfacies, ranging from open marine environments to intertidal and supratidal systems. The distribution and association of recognized microfacies proposed carbonate ramp-type platform deposition for the Asmari Formation. In addition, three third-order depositional sequences (sequences 1, 2, and 3) have been recognized through the Asmari Formation in the Haft-Kel Oil field that is well correlated with sequences IV, V, and VI proposed by van Buchem et al. (2010), respectively. Using the Hydraulic Flow Unit (HFU) concept, six rock types have been identified for the Asmari reservoir. Finally, three reservoir zones, comprising none, moderate, and good reservoir zones, were introduced for the Asmari reservoir in Haft-Kel Field. No reservoir zones are visited in the lower part of the formation in depositional sequence 1 and to some extent in the Low Stand Systems Tract (LST) part of depositional sequence 2 and 3, while moderate to good reservoir zones are developed in the upper intervals of the formation, especially in the High Stand Systems Tract (HST) parts of depositional sequence 2 and 3.
Sedimentological investigation of 150 m drill cores and well log analyses, including gamma-ray, resistivity, sonic, neutron, density logs, were conducted to constrain the impact of depositional facies on reservoir quality distribution in limestone succession of the Yamama Formation (Early Cretaceous), Nasiriya Oilfield, southern Iraq. Understanding the factors controlling reservoir heterogeneity in carbonate reservoirs is crucial for developing geological and reservoir models. Nine microfacies were identified: peloidal oncoidal grainstones-rudstones, skeletal cortoids packstones, skeletal dasyclads wackestones, pelletal packstones-grainstones, cortoidal peloidal grainstones, ooidal peloidal grainstones, skeletal grainstones, bioturbated dolomitic wackestones, and spiculitic skeletal mudstones-wackestones. The formation was deposited in open-marine shallow-water carbonate ramp, ranging from the intertidal to outer-ramp during the Berriasian-Valanginian. The depositional ramp was characterized by grainstones shoal barriers in the distal inner-ramp. Sea level fluctuations significantly influenced the vertical facies and reservoir quality distribution. The grain-supported, distal inner-ramp shoal facies formed the reservoir units, while the mud-supported, middle-outer-ramp facies are impervious units. Diagenetic processes, including dissolution of skeletal allochems, physical and chemical compaction, dolomitization, and cementation, have variably affected reservoir quality. Dissolution enhanced porosity by creating vuggs, while compaction and cementation often reduced porosity. Nevertheless, early diagenetic circumgranular calcite and small amount of scattered equant and syntaxial calcite overgrowths helped protecting the grain-supported limestones from physical compaction and thus preserved interparticle pores (≤ 22%) at depth (>3100 m). Conversely, equant calcite cement, which occurs in substantial amounts, has reduced porosity by filling the interparticle and moldic pores. Reservoir heterogeneity of the formation is attributed to depositional facies, which control the texture of the sediments, and to various types of diagenetic alterations.
In this work, numerical modeling was performed using a dynamic self-consistent (SC) anisotropic micromechanics approach. This study examines how porosity, pore aspect ratio, and seismic anisotropy affect the velocity dispersion and attenuation patterns of P-waves and polarized S-waves (SH and SV) traveling through oil- and brine-saturated carbonate rocks (3D body) at seismic, sonic, and ultrasonic frequencies. Here, the carbonate rock was idealized as a mineral carbonate matrix embedded with aligned ellipsoidal fluid inclusions of aspect ratio . These ellipsoidal inclusions represent the porosity , which is saturated with fluid. The studied rock was assumed to have a vertical axis of symmetry that is perpendicular to the plane of alignment and therefore will show vertical transverse isotropy (VTI). Wave velocities were modeled considering a variety of porosities (5, 10, 15, and 20%), aspect ratios (ranging from to ), and angles of incidence ( , , and ), where is the angle between the symmetry axis and the direction of wave propagation through the rock. Overall, results showed that the largest changes in P- and SH-wave velocities are due to variations in (up to 15%), followed by changes in (up to 6%), and then by changes in (up to 4.3%). By contrast, for SV-wave velocities the order changes in the last two parameters. Finally, the variations in P- and S-wave velocity dispersion and their maximum attenuation are greater for oblate ellipsoids than for prolate ellipsoids, regardless of porosity, angle of incidence, and aspect ratio.
Permeability is one of the most significant and challenging parameters to estimate when characterizing an oil reservoir. Several empirical methods with geophysical borehole logs have been employed to estimate it indirectly. They include the Timur model, which uses conventional logs, and the Timur–Coates model, which uses the nuclear magnetic resonance log. The first goal of this study was to evaluate porosity, because it directly impacts permeability estimates. Deterministic and stochastic inversions were then carried out, as the main objective of this work was to estimate the permeability in a carbonate reservoir of the Campos Basin, Southeastern Brazil. The ridge regression scheme was used to invert the Timur and Timur–Coates equations deterministically. The stochastic inversion was later solved using fuzzy logic as the forward problem, and the Monte Carlo method was utilized to assess uncertainty. The goodness of fit for the estimations was all checked with porosity and permeability laboratory data using the Pearson correlation coefficient (R), root mean square error (RMSE), mean absolute error (MAE), and Willmott’s agreement index (d). The results for the Timur model were R = 0.41; RMSE = 333.28; MAE = 95.56; and d = 0.55. These values were worse for the Timur–Coates model, with R = 0.39; RMSE = 355.28; MAE = 79.35; and d = 0.51. The Timur model with flow zones had R = 0.55; RMSE = 210.88; MAE = 116.66; and d = 0.84, which outperformed the other two models. The deterministic inversion showed, thus, little ability to adapt to the significant variations of the permeability values along the well, as can be seen from comparing these three approaches. However, the stochastic inversion using three bins had R = 0.35; RMSE = 320.27; MAE = 190.93; and d = 0.73, looking worse than the deterministic inversion. In the meantime, the stochastic inversion with six bins successfully adjusted the set of laboratory observations, because it provides R = 0.87; RMSE = 156.81; MAE = 74.60; and d = 0.92. This way, the last approach has proven it can produce a reliable solution with consistent parameters and an accurate permeability estimation.
This paper explores the innovative application of machine learning and neural network algorithms to predict pore types incarbonate rocks using experimental acoustic properties under ambient pressure conditions. Carbonate reservoirs, crucial forhydrocarbon storage and extraction, present a challenge due to their complex pore structures influenced by diverse depositionalenvironments and diagenetic processes. Traditional petrographic methods for identifying pore types, though accurate, are time-consuming and destructive. Recent approaches leverage log and core-measured compressional wave velocities and porosity,yet variability in data remains an issue. Addressing the challenge, this study distinguishes itself by employing high-resolutionphysical rock samples from the early Miocene dam formation, eastern province of Saudi Arabia. Through meticulous datapreparation, feature engineering, and the evaluation of logistic regression, random forest classifier, gradient boosting classifier,and support vector classifier models, we have developed an advanced model capable of predicting pore types with significantaccuracy. Our findings reveal that logistic regression achieves the highest accuracy (71%) among the models, effectivelycapturing t he inherent patterns within our dataset. A detailed analysis using principal component analysis underscored thediscriminative power of these models, particularly in identifying interparticle–intraparticle and moldic pore types. This study’sinnovative approach, leveraging experimental measurements and machine learning techniques, offers a robust framework foraccurately predicting pore types in carbonate rocks. While challenges such as data size and feature limitations persist, thepotential implications of our findings for reservoir modeling and efficient hydrocarbon extraction are significant, providing afoundation for future research to build upon.
Previous attempts to classify flow units in Iranian carbonate reservoirs, based on porosity and permeability, have faced challenges in correlating the rock's pore size distribution with the capillary pressure profile. The innovation of this study highlights the role of clustering techniques, such as Discrete Rock Type, Probability, Global Hydraulic Element, and Winland's Standard Chart in enhancing the reservoir's rock categorization. These techniques are integrated with established flow unit classification methods. They include Lucia, FZI, FZI*, Winland R35, and the improved stratigraphic modified Lorenz plot. The research accurately links diverse pore geometries to characteristic capillary pressure profiles, addressing heterogeneity in intricate reservoirs. The findings indicate that clustering methods can identify specific flow units, but do not significantly improve their classification. The effectiveness of these techniques varies depending on the flow unit classification method employed. For instance, probability-based methods yield surpassing results for low-porosity rocks when utilizing the FZI* approach. The discrete technique generates the highest number of flow unit classes but provides the worst result. Not all clustering techniques reveal discernible advantages when integrated with the FZI method. In the second part, the study creatively suggests that rock classification can be achieved by concurrently clustering irreducible water saturation (SWIR) and porosity in unsuccessful flow unit delineation cases. The SWIR log was estimated by establishing a smart correlation between porosity and SWIR in the pay zone, where water saturation and SWIR match. Then, the estimated saturation was dispersed throughout the reservoir. Subsequently, the neural network technique was employed to cluster and propagate the three finalized flow units. This methodology is an effective recommendation when conventional flow unit methods fail. The study also investigates influential factors causing the failure of flow unit classification methods, including pore geometry, oil wettability, and saturation in heterogeneous reservoirs.
Petrophysical analysis plays a vital role in reservoirs characterization, providing parameters to evaluate the economic potential of the field. This study was performed in a fractured carbonate reservoir of Quissamã Formation, Campos Basin, mostly composed of calcarenites and calcirudites of Quissamã Formation, which it was named B Field. This reservoir is essentially microporous, characterized by medium to high porosity (15-25%) and, in general, low matrix permeability (0.1-10 mD). The petrophysical relationships can be considerably complex in carbonate reservoirs, due to the greater heterogeneity in facies and porosity distribution of these rocks. The complexity became even higher in particular case of fractured reservoirs. It was developed in this thesis a general workflow for petrophysical characterization of this Albian carbonate reservoir, using well log data and plugs samples. The goals of this paper were to identify different flow behaviors and to define areas of the field with possible intergranular flow contribution. It is extremely important therefore to understand the relationship between the geological controls and the dynamic behavior of the reservoir. The petrophysical analysis of matrix properties enabled to recognize two reservoir zones with distinct flow behaviors, directly influenced by the porous system heterogeneity. In the southern area it was found very low matrix permeability, due to the large occurrence of microporosity. In the northern area it were found the best matrix permeability values of B Field, related to the contribution of intergranular flow due to the original macroporosity preservation. The high initial production rates obtained from production data of wells located in the southern portion indicate the presence of fractures. The fracture system has a small impact on the percentage of total reservoir porosity, but it has a large contribution to the flow domain, playing an important role in the commercial production of the field. It was also investigated the impact associated with Archie‟s parameters - Cementation Factor (m) and Saturation Exponent (n) - in the determination of water saturation (Sw) in this fractured carbonate reservoir. To investigate this impact, four Sw scenarios were generated by applying different m and n values and compared with one another. Three main analyses were performed according to m and n variations: (I) the average values of Sw and Hydrocarbon Pore
Volume Height (HPhiSo) were compared for each scenario. The results showed a considerable variation in the average values for both. (II) The second analysis was based on the cut-off and Net Pay values. The results showed that cut-off values must be changed according to the variation given by a water saturation curve, whatever the Sw scenario, in order to keep the same Net Pay values. (III) The differences between global and individual cut-offs on Net Pay thickness were analyzed for all wells for the scenario C2. Insignificant variations indicate that a global cutoff value is acceptable for this field. The results show that inaccurate values of Archie's parameters can lead to gross errors in reserves evaluation.
The Early Triassic Kangan Formation in southern Iran and Persian Gulf, equivalent to the Upper Khuff Formation in the neighboring Arab countries hosts vast natural gas resources in the Persian Gulf. The current study discusses sedimentary facies, diagenesis, depositional setting and reservoir characteristics of the Triassic Kangan Formation within a sequence stratigraphic framework across a section passing from the central to northern Persian Gulf. For this purpose, a comprehensive analysis was conducted using well logs, cores and thin sections from four wells. In this respect, fifteen microfacies representing four facies’ belts ranging from peritidal to lagoon and barrier (shoal) settings of a shallow marine carbonate ramp environment were identified. The Kangan Formation has undergone marine, meteoric and burial diagenesis severely impacting its reservoir quality through dolomitization, dissolution and cementation. Analysis of sedimentological and petrophysical characteristics enabled the recognition of three third-order and seven fourth-order depositional sequences. This unit’s persistent and complex diagenetic history, spanning since the Lower Triassic, has significantly altered reservoir quality by reshaping pore types, size and geometry. Dolomitization and dissolution have notably improved the reservoir quality of the Kangan Formation in the central Persian Gulf. However, towards the northern Persian Gulf, the presence of anhydrite in the form of cement, nodules and interbeds has adversely affected reservoir quality. Consequently, the Kangan Formation behaves as a tight gas carbonate reservoir in the Coastal Fars structural zone of Zagros. Therefore, the Coastal Fars and the northern Persian Gulf can be conceptualized as the inner part of a large-scale paleo-ramp environment (inner ramp), whereas the central Persian Gulf lies within its mid-ramp and basin environment.
Kohat Plateau has huge hydrocarbon potential and most of the reservoirs are structurally controlled. Panoba Anticline is among the largest anticlines in Kohat Plateau consists of Paleocene to Eocene sequence. In this research petrophysical properties (density, porosity and permeability of the fractures) of reservoir formations esposed in the Panoba Anticline are analyzed. The main and regional compressional stresses on Panoba Anticline are north-south oriented and the other stresses are might be its derivatives. Based on petrophysical properties the formations of Panoba Anticline are analyzed for reservoir potentiality. Petrophysical properties varies from formation to formation as well as within a same formation because of the fractures behaviors. The reservoir types were assigned to reservoir formation by comparing the results on qualitative basis with Nelson (2001) naturally fractured reservoir (NFR) system. The reservoir character of Kohat Formation is Type 4 to Type 2; Shekhan Formation Type 3 to Type 1; Patala formation Type 4 to Type 3, while the Lockhart Formation has Type 3 to Type 1 reservoir character. In conclusion the petrophysical analysis of Panoba anticline offers a valuable insight into the formations reservoir potentiality which contributes a better understanding of the hydrocarbon prospects in the Kohat Plateau.
The naturally fractured carbonate gas reservoir of Majiagou formation in Ordos Basin is characterized by mixed mineralogy. Since mineralogy determines acid-rock reaction rate, mineral distribution has significant effect on the fracture surface etching profile. Therefore, it is necessary to investigate effect of mixed mineralogy on etching profile and fracture conductivity.
In this paper we conducted the research from two aspects: experiment and numerical modeling. In the experiment, we firstly measured mineral distribution by hyperspectral scanning on the core slabs, then did acid flooding, next did 3D scanning to get etching profile, and finally measured acid fracture conductivity, based on which an acid fracture conductivity correlation was built. In numerical modeling, based on mass conservation principle, acid-rock reaction kinetics, and momentum theorem, a 3D acid flow, acid-rock reaction, surface etching model was developed. Mineral distribution on the surfaces was coupled as boundary conditions. Experimentally measured mineral distribution on the slab surface are coupled into the numerical simulation. The model is validated by the experimental results. Based on the model, extensive numerical simulation was conducted to analyze mineral distribution, acid-rock contact time, and temperature on the surface etching pattern and acid concentration distribution. By combining the experimental results and numerical simulation, how the mineral distribution affect etching profile, facture conductivity, and acid concentration distribution is analyzed.
The study shows that for mixed mineralogy carbonate, the distribution of mineral is strongly spatially correlated instead of random distribution. Mineral stripes are observed from the mineralogy scanning of core slabs. Due to reaction rate contrast of different minerals and strong spatially correlated distribution, the surface etching profiles are rough, and the channel is obvious. The channels resulted from multiple mineral distribution contributes remarkably to the fracture conductivity. With the similar amount of rock dissolved, the fracture with channels has a much higher conductivity. Temperature has remarkable effect on etching profile. At a high temperature (e.g. 90°C), the difference of overall reaction rate for limestone and dolomite is small, and the etching discrepancy for calcite and dolomite is less. At a low temperature (e.g. 60°C), the difference of overall reaction rate is large, so the etching discrepancy is more distinct. Dolomite surface has an apparent higher acid concentration than limestone at a low temperature, while surface acid concentration is close for calcite and dolomite at a high temperature. The impurities such as quartz, clay, gypsum, etc. are not dissolved by the acid. Even small amount of impurities contributes to the differential etching on the surfaces. In the lab scale, the acid concentration inside the fracture has identifiable decrease from the inlet to the outlet.
Volume V: Reservoir Engineering and Petrophysics is an essential reference for reservoir engineers. Learn how to acquire and interpret data that describe reservoir rock and fluid properties; understand and predict fluid flow in the reservoir; estimate reserves and calculate project economics; simulate reservoir performance; and measure the effectiveness of a reservoir management system.
Despite declining production rates, existing reservoirs in the United States contain large quantities of remaining oil and gas that constitute an enormous target for improved diagnosis and imaging of reservoir properties. The resource target is especially large in carbonate reservoirs, where con entional data and methodologies are normally insufficient to resolve critical scales of reservoir heterogeneity. The objectives of the research described in this volume were to develop and test such methodologies for improvedimaging, measurement, modeling, and prediction of reservoir properties in carbonate hydrocarbon reservoirs. The focus of the study is the Permian Fullerton Clear Fork reservoir of the Permian Basin of west Texas. This reservoir is an especially appropriate choice because the Permian Basin is the la gest oil-bearing basin in the United States and, as a play, Clear Fork reservoirs have exhibited the lowest recovery efficiencies of all carbonate reservoirs in the Permian Basin.
Despite declining production rates, existing reservoirs in the United States contain large quantities of remaining oil and gas that constitute an enormous target for improved diagnosis and imaging of reservoir properties. The resource target is especially large in carbonate reservoirs, where con entional data and methodologies are normally insufficient to resolve critical scales of reservoir heterogeneity. The objectives of the research described in this volume were to develop and test such methodologies for improvedimaging, measurement, modeling, and prediction of reservoir properties in carbonate hydrocarbon reservoirs. The focus of the study is the Permian Fullerton Clear Fork reservoir of the Permian Basin of west Texas. This reservoir is an especially appropriate choice because the Permian Basin is the la gest oil-bearing basin in the United States and, as a play, Clear Fork reservoirs have exhibited the lowest recovery efficiencies of all carbonate reservoirs in the Permian Basin.
The Upper Messinian reservoirs located in the Salma Field of the Nile Delta area contain variable facies. The key reservoir interval of the Abu Madi Formation was deposited in fluvial to deltaic environments. These fine-grained facies form significant reservoir heterogeneity within the reservoir intervals. The main challenges in this study are reservoir characterizing and predicting the change in reservoir water saturation (SW) with time, while reservoir production life based on the change in reservoir capillary pressure (Pc). This work applies petrophysical analysis to enable the definition and calculation of the hydrocarbon reserves within the key reservoir units. Mapping of SW away from the wellbores within geo-models represents a significant challenge. The rock types and flow unit analysis indicate that the reservoir is dominated by four hydraulic flow units. HFU#1 represents the highest flow zone indicator (FZI) value. Core analysis has been completed to better understand the relationship between SW and the reservoir capillary pressure above the fluid contact and free water level (FWL), which is used to perform saturation height function (SHF) analysis. The calculated SW values that are obtained from logs are affected by formation water resistivity (Rw) and log true resistivity (RT), which are influenced by the volume of clay content and mud salinity. This study introduces an integrated approach, including evaluation of core measurements, well log analysis covering cored and non-cored intervals, neural analysis techniques (K-mode algorithm), and permeability prediction in non-cored intervals. The empirical formula was predicted for direct calculation of dynamic SW profiles and predicted within the reservoir above the FWL based on the change in reservoir pressure.
Hydrocarbon reserves are commonly estimated from electrical logs based on the Archie’s law. Therefore, understanding the concepts and precise determination of Archie’s parameters play an essential role in reservoir studies. The electrical properties of carbonates are affected by both microstructures and wetting characteristics of these heterogeneous rocks. Understanding of these effects and prediction of Archie’s parameters are significant theoretical and experimental challenges. In this paper, these effects were analyzed separately using rocks with various lithologies including limestone, dolomitic limestone and dolostones. Samples with different sedimentary textures (grainstones and packstones), porosities and pore types were also considered under different laboratory conditions. For microstructure effects analysis, 16 heterogeneous carbonate samples having a wide range of microstructures were selected. To decrease wetting effect, the washed samples were tested in air–brine injection system at ambient conditions to measure saturation exponent. Subsequently, in order to investigate the influence of the wetting characteristics on this exponent, 25 homogeneous limestone samples were employed for water–oil injection under reservoir conditions. The porous plate was used as a standard technique to determine the saturation exponent as an electrical index. The results showed that pore connectivity and wettability are the main factors affecting the saturation exponent. Heterogeneity, including the presence of large pores and bimodal texture, is another effective factor that complicates the relationship between saturation exponent and wettability. Furthermore, results indicate variation of the saturation exponent with fluid saturation. Finally, equations were obtained to interpret and calculate the saturation exponent using capillary pressure data by mercury injection method. The derived equations clearly demonstrate the significant impact of the studied parameters on the saturation exponent in carbonate rocks.
The porous systems of carbonate reservoirs show a great diversity of pore types and high heterogeneity that can reflect the interplay of several elements including physical, chemical, and biological depositional processes, intense diagenesis, fracturing, and hydrothermal alterations. All these factors combine in the Aptian Barra Velha Formation carbonates from Santos Basin, SE offshore Brazil, which comprises the most prolific hydrocarbon reservoirs from Brazil. The geological complexity of this formation has represented a major challenge for oil forecast, recovery and production. The absence of outcrops, proper analogs and the limited access to core samples of this deep formation adds to the challenges involved in the geological and petrophysical characterization of such reservoirs. In this context, X-ray computed tomography (CT) can become a key technique applied for non-destructive quantitative analyses and 3D visualization of different rock structures. The present article reports the results obtained from X-ray CT images applying digital rock analysis to characterize the complex pore networks and mineral phases of the Barra Velha Formation reservoir. Multi-resolution CT-scan petrophysics was combined with detailed petrography and petrology, aiming to understand the geological factors controlling porosity distribution. Mineral segmentation was split into three mineral phases: carbonate, undefined (microporosity and diagenetic material) and dense minerals. The high percentage of undefined phase was commonly associated with intense dolomitic cementation and related to low permeabilities. Shrubstone and Intraclastic rudstone lithologies showed the best reservoir properties, mainly when the dominant growth framework and interparticle porosity, was associated with dissolution, enhancing the pore connectivity. Pore network analysis revealed the tendency of larger pores to be associated with higher coordination numbers, presenting greater pore connectivity. This study aims to contribute to future work on Brazilian pre-salt carbonates’ pore type and multi-scale characterization, providing new insights into the characteristics and factors related to the samples’ connectivity.
This paper provides an updated understanding of the reservoir stratigraphy, sedimentology, palaeogeography and diagenesis of the Upper Permian Hauptdolomit Formation of the Zechstein Supergroup (“Hauptdolomit”) in a study area on the southern margin of the Mid North Sea High. The paper is based on the examination and description of core and cuttings data from 25 wells which were integrated with observations based on existing and new 3D seismic.
Based on thin-section petrography of cuttings and core from the wells studied, it is evident that Hauptdolomit microfacies are distributed in a relatively predictable way, and well-defined platform interior, platform margin, slope and basin settings can be distinguished. Platform margins are typically characterised by the development of ooid shoals and, to a lesser-extent, by microbial build-ups. High-energy back-shoal settings are characterised by a
more complex combination of peloid grainstones, thrombolitic and microbial build-ups, and fine crystalline dolomites. Lower energy lagoons which developed further behind the platform margin are characterised by a variety of microfacies types; fine crystalline dolomites are common in this setting as well as peloidal facies and local microbial build-ups. Intertidal and supratidal settings are typified by increased proportions of anhydrite and the development of laminated microbial bindstones (stromatolites). Platform margins are in general relatively steep and pass into slope and basinal settings. Only a few wells have penetrated Hauptdolomit successions deposited in a slope setting, and these successions are characterised by a range of resedimented shallow-water facies together with low-energy laminated dolomicrites and fine crystalline dolomites. Slope zones in the study area are interpreted from seismic data to be typically 1-1.5 km in width. Basinal Hauptdolomit deposits have been strongly affected by post-depositional diagenesis and are dedolomitised to variable degrees. The original depositional facies are rarely preserved.
Diagenetic studies show that dolomitisation has affected almost the entire Hauptdolomit Formation throughout the study area in both basinal and platform settings. The dolomite is considered to result from seepage-reflux processes and is an early diagenetic phase. Mouldic porosity is present in many facies types as a result of dissolution, especially in ooid grainstones, thrombolitic build-ups and peloidal facies. The dissolution cannot be associated with any one diagenetic phase but was most likely a result of the dolomitisation process itself. Stable isotope analyses indicate that all dolomites were precipitated from Permian marine derived
pore fluids. Fluid inclusion analyses of dolomite cements indicate that cementation continued into the burial realm. Anhydrite cementation occurs in two phases: early anhydrite precipitation was associated with dolomitisation, and can be distinguished from a later, pore-filling cement which is highly detrimental to
reservoir quality.
The Hauptdolomit succession in basinal wells (and in some slope wells) in the study area has undergone significant dedolomitisation. Dedolomitisation was a shallow burial process which affected precursor dolomites, whereby excess calcium from the transition of gypsum to anhydrite during burial combined with CO2 and organic acids derived from basinal sediments. The process was triggered by excess calcium reacting with excess
carbonate ions from dissolution.
3D seismic volumes supplemented by numerous 2D lines were available in the study area and allowed an interpretation to be made of Hauptdolomit gross depositional settings; platform margins and base of-slope polygons were mapped, with the greatest confidence in areas of 3D seismic. The basin, slope
and platform settings were distinguished using seismic data integrated with the results of micro-facies analysis and incorporating seismic-to-well ties. The data shows that large parts of the study area are characterised by the presence of polyhalites within the overlying (Z2) Stassfurt Halite Formation, which may create particular seismic geometries at the Hauptdolomit slope. These are interpreted to be intra-Stassfurt Halite features, providing an alternative model to the thickened,
prograded Hauptdolomit which has been suggested in previous publications.
Because few wells drilled in the study area had the Hauptdolomit as the primary target, cores were limited but significant data was obtained from cuttings analyses. More than 400 thin sections were evaluated, allowing depositional models based on microfacies observations to be developed, verifying the seismic-scale observations.
Microstructural features control the petrophysical properties of rocks. Of these, pore size is particularly sensitive when non-wetting fluids saturate the reservoir. The pore networks and physical properties (helium, water and mercury saturation porosity, bulk density, nitrogen permeability, P-wave velocity and thermal conductivity) of different rock types from a productive Upper Cretaceous (Coniacian) reservoir in the tunisian offshore are measured on hydrocarbon-washed samples. The facies sampled of Douleb Member are wackestone, packstone and grainstone textures as well as dolostone, dolomitized packstone and anhydrite textures. Based mainly on the results obtained by mercury injection, the porous facies of the Coniacian Douleb Member are characterized by a complex pore system with a large morphological and pore size variability in the rock. Porosity values range from 0.3 to 23.6%, bulk densities vary from 2.05 to 2.92 g.cm⁻³. The permeability is variable from 3760 mD to values below 0.01 mD (measurement limit of the device). P-wave propagation velocity values range from 2060 to 6084 m.s⁻¹ and thermal conductivity varies from 1.43 to 3.77 W.m⁻¹.K⁻¹. The oil-impregnated facies with the best petrophysical characteristics are mainly the rudist-rich limestones and dolomites of the first unit (U1) of the Douleb Member. The well-sorted grainstones with small rudist debris and peloids have the best reservoir qualities. Porosity is the first order characteristic that controls petrophysical properties. The variability of permeability values around this first-order relationship is attributed to variations in the size of the pore access thresholds and connectivity. The variability in velocities is due to the shape of the voids, while the variability in thermal conductivity measurements is due to the nature of the contacts between the grains.
The development of unconventional resources in the Uinta basin requires more investigation. Petrophysical characterization is the key to identifying different rock types to optimize hydrocarbon production. Rock-typing can be performed using wireline measurements, such as triple combo and special logs; however, this identification needs to be verified using laboratory characterization to enhance the accuracy of rock-typing prediction models.
In this work, we implement an integrated characterization workflow for 600 ft of the core interval, including total organic carbon, source rock analysis, elemental (X-ray Fluorescence) and mineral (Fourier- transform Infrared Spectroscopy) composition, total porosity (High-pressure pycnometer, Nuclear Magnetic Resonance), pore throat size distribution (Mercury Injection Capillary Pressure), elastic moduli (Ultrasonic velocity and nanoindentation) and microstructure (Scanning Electron Microscopy). Wireline measurements include the triple combo and the sonic logs. Principal Component Analysis and K-means (as unsupervised machine learning algorithms) were applied to both datasets to cluster and classify different rock types. In parallel, the petrophysical systematic for each rock type was evaluated.
The Uinta group is vastly diverse, having a wide range of porosity (2-18%) and TOC (0.5-10%). Three main rock types were identified type 1-siliceous rich, type 2-calcite rich, and type 3-dolomite rich. The relative contribution of types 1, 2, and 3 is 47, 31, and 22 %, respectively. The top section of the analyzed core is dominated by rock type 1, which generally has the highest porosity and relatively higher TOC. Most of the bottom section is carbonate-rich rock types, in which calcite-rich and dolomite-rich layers are interbedded; SEM analyses suggest that a fraction of the porosity is associated with organic matter. Between rock types 3 and 2, further studies indicate that the high dolomite rock type tends to have higher porosity, larger pore size, and better-sorted grains, while the high calcite rock type has lower porosity and small pore size. There is a fair agreement in rock type identification between using core-derived and log- derived models.
The Uinta basin leads the hydrocarbon production in Utah. The study provides a comprehensive core analysis dataset highlighting the vertical complexity of the Uinta group. The agreement in rock-typing using core and wireline inputs suggests that log-derived rock-typing can be utilized to identify sweet zones.
Carbonate rocks have a wide variety of pore shapes and different types of grains, which greatly affect the elastic properties and characteristics of the reservoir. This causes certain difficulties in petroelastic modeling. One of the problems is the scale of the input data, which is then used to build the rock physics model. The paper presents the results of studying three core samples of carbonate rocks of the Upper Devonian and Lower Carboniferous age, which are located in the South Tatar arch (Volga-Ural oil and gas basin (Russia)). To evaluate the structural characteristics of the pore space, the effective medium theory is used. The input data are the results of laboratory studies that include measurements of the velocities of longitudinal and transverse waves, porosity, and thin section and computed tomography analysis. When using the computed tomography, the core samples are analyzed at different resolution (12-37 µm/voxel). The tomography studies of pore space at different scales provide rather different values of porosity and pore aspect ratio. The tomography-based porosity estimations also differ from the experimentally measured porosity (up to 10%). The pore space characteristics provided by different datasets are used to build a rock physics model for the studied rocks that helps to estimate the elastic wave velocities with three different methods of effective medium theory (self-consistent approximation, differential effective medium (DEM), and the Kuster-Toksöz method). A comparison of the velocity estimations with their experimental analogs for dry rocks may indicate the presence of microcracks whose size is beyond the tomography resolution. Improved rock physics models incorporating both pores and microcracks are then used to predict the elastic wave velocities of fluid-saturated rock in a wide porosity range. It is demonstrated that the predicted values significantly differ (up to 30%) from those provided by the rock physics (RP) models constructed without the support of the tomography results. Moreover, other types of models are considered in which the difference in experimental and theoretical velocities is attributed to changes in the host matrix properties as compared to the calcite polycrystal, which are caused by various reasons.
Unconventional geo-resources are critical due to their important contributions to energy production. In this energy transition and sustainability era, there is an increased focus on CO2-enhanced oil recovery (CO2-EOR) and geological CO2 storage (GCS) in unconventional hydrocarbon reservoirs, and the extraction of hot fluid for energy through enhanced geothermal systems. However, these energy solutions can only be achieved through efficient stimulation to develop a complex fracture network and pore structure in the host rocks to extract heat and hydrocarbon, or for CO2 storage. Using Bakken formation well data and rock physics models, this study aimed to identify the post-depositional effect of pore structure on seismic velocity, elastic moduli, and formation fluid; and further predict the best lithofacies interval for well landing, and the implications for fluid (gas, oil, and water) recovery in naturally- and often systematically-fractured geosystems. The KT and DEM models' predictions show distinct formation intervals exhibiting needle-like pores and having higher seismic velocities (Vp and Vs) and elastic moduli (K and µ), relative to other formation intervals that exhibit moldic pores. At the same fluid concentration, the needle-like pores (small aspect ratios) have a higher impact on elastic moduli, Vp, and Vs than on the moldic spherical pores with all other parameters held constant. Vp is affected more than Vs by the properties of the saturating fluid (gas, oil, or water) with Vp being greater in Bakken formation when it is water-saturated than when it is gas-saturated. Vs exhibit the reverse behavior, with Vs greater in the gas-saturated case than in the water-saturated case. Further, analyses suggest that the middle Bakken formation will have a higher susceptibility to fracturing and faulting, and hence will achieve greater fluid (oil and water) recovery. Our findings in this study provide insights that are relevant for fluid production and geo-storage in unconventional reservoirs.
Article highlights
Integrated well log data and rock physics models.
Investigated the effect of changes in pore structure on elastic properties and fluid flow in shale.
Increase in porosity causes a reduction in elastic moduli and seismic velocities.
Vp is more affected by pore geometry than Vs depending on density and properties of saturating fluid.
Lithofacies with needle−like pores are more susceptible to fracturing than lithofacies with intragranular pores.
Seawater injection is an EOR success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state, this process is triggered by the difference in composition between injection and formation water. "Smart Water" with optimized ionic composition can be easily made under laboratory conditions to improve oil recovery beyond that of seawater, however, in the field, its preparation may require specific water treatment processes, e.g., desalination, nano-filtration or addition of specific salts. In this work, a naturally occurring salt called polysulphate (PS) is investigated as an additive to produce Smart Water.
Outcrop chalk from Stevns Klint, consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the polysulphate brines to alter wettability in chalk. Solubility of polysulphate in seawater and de-ionized water and brine stability at high temperatures were measured. Energy Dispersive X-Ray and ion chromatography were used to determine the composition of the polysulphate salt and EOR-solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition, for evaluating wettability alteration, of polysulphate brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of formation water and seawater.
The solubility tests showed that the salt was easily soluble in both de-ionized water and seawater with less than 5% solid residue. The de-ionized polysulphate brine contained sulphate and calcium ion concentration of 31.5 millimolar (mM) and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The seawater polysulphate brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared to ordinary seawater this brine has the potential for improved wettability alteration in chalk due to increased sulphate content.
Ion chromatography revealed that the sulphate adsorbed when polysulphate brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection, the reactivity was also enhanced by increasing the temperature from 25 to 90 °C. Finally, the oil recovery tests by spontaneous imbibition showed that polysulphate brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by formation water injection. The difference in oil recovery between ordinary seawater and seawater polysulphate injection was smaller due to the already favorable composition of seawater.
Polysulphate brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additives for easy and on-site preparation of Smart Water brines for carbonate oil reservoirs. Polysulphate salt, added to the EOR-solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which EOR effects can be achieved.
This paper systematically analyzes the organic geochemical, petrophysical, and petrographical properties combined with bulk kinetics modeling of the Abu Roash (F) organic-rich carbonate rocks in the Abu El Gharadig Field. The Abu Roash (F) carbonate-rich samples exhibit high organic content with total organic matter (TOC) values up to 3.04 wt. %, and mainly Type II kerogen and a slight gradient to Type II/III and III kerogens, reaching good to very good oil generation potential. This finding of hydrogen-rich kerogen and oil generation potential was also demonstrated by the abundance of fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter (OM) as established via ultra violet (UV) light microscopy. The maturity indicators demonstrate that most of the examined Abu Roash (F) carbonate-rich samples from the studied wells, with a deep burial depth of more than 3000 m, are thermally mature, thus is defining an early mature to moderate-mature. The kinetic models suggest that the Abu Roash (F) carbonate-rich rocks in the deepest burial depth, with calculated vitrinite reflectance (%VR) values in the range of 0.72–0.83%, reached kerogen transformation (TR) ratio (TR) in the range of 10–55%, indicating a high probability of oil production. This finding is confirmed by the presence of the oil crossover in these rocks with an oil saturation index (OSI) of more than 100 mg HC/ g rock. The Abu Roash (F) organic-rich carbonates are intractable rocks as implied by low porosities (up to 2.33%) and poor permeability in the range of 0.0017-0.0039 mD. The pores in these carbonate-rich rocks widely range in size, including interparticle, fracture, and pores on the organic matter (OM) pores, as recognized and observed in the thin section and scanning electron microscopy (SEM). The development of these pore types and their quality is mainly controlled by high mineralogical brittleness (i.e., carbonates) together with the high OM inputs. Based on the above characteristics, the Abu Roash (F) carbonate-rich rocks in the Abu El Gharadig Field are a candidate for unconventional tight oil reservoir potential, which typically require a form of hydraulic fracturing for possible commercial oil production at deeper burial depths.
The geophysical characterization of Upper Jurassic carbonate rocks in the Bavarian Molasse Basin of Southern Germany, which holds a large reservoir of thermal water, especially below Munich, is an ongoing subject of scientific studies due to their complex heterogeneity. As part of the BMWi-funded GeoMaRe project, the data of six deep geothermal boreholes at the Schäftlarnstraße site (SLS), operated by Stadtwerke München (SWM), were comprehensively interpreted for their petrophysical, geological and hydraulical characteristics. In particular, an extended borehole logging program, including outstanding measurements such as sidewall coring and fiber-optics, increased the level of knowledge to a high extent. Additionally, the use of resistivity measurements for porosity interpretation could be further secured by correlation with porosity measurements on rock cores as well as acoustic and NMR logging interpretation. The extensive flowmeter measurements in five boreholes also contributed to deepening the knowledge of hydraulically active zones within the stratigraphic layers Purbeck and Malm. The results show that karst zones, localized in the Purbeck and upper Malm, dominate the inflow by more than 90% in some wells. This interpretation could be corroborated by permanent, spatially distributed temperature measurements using a fiber optic cable deployment installed as part of the Geothermal Alliance Bavaria (GAB 1.0) and described by Schoelderle et al. (2021). The geophysical and hydrochemical knowledge gained together with trends in porosity, fracture frequency, karst zones and hydrochemistry, which could be interpreted and observed on a small scale, can be followed well beyond Munich in large areas. In the GAB 1.0 project, geothermal and hydrocarbon wells from the entire Molasse Basin were (re-)interpreted. Distinctive trends observed in these wells contribute to a deeper reservoir understanding of porosity development, fracture frequency and hydraulically active zones, and suggest a link to the productivity or non-discovery of wells. This leads to a better understanding of the heterogeneous aquifer, which in turn leads to increased reliability of predictions in feasibility studies and hydraulic models.
In karstic-fractured carbonate reservoirs, most of the oil resources are hosted in vugs. Connecting as many vugs as possible by hydraulic fracturing is the key to achieving effective development. However, the interaction mechanism between vugs and hydraulic fractures is complicated and has not been fully revealed. In this study, both experimental and numerical simulations were implemented to investigate the interaction between vugs and hydraulic fractures. Key factors, such as vug size, horizontal stress difference, and the internal pressure of the vug, were considered. The results showed that the vug played an important role in the propagation of hydraulic fractures. Three interaction modes of vugs and hydraulic fractures were observed: crossing, arresting, and bypassing. Owing to the variation of the stress concentration existing around the vug, the hydraulic fracture could be arrested by a small vug but would bypass a vug with a larger size. Whether the hydraulic fracture could communicate with the vug was mainly controlled by the horizontal stress difference. Under large horizontal stress differences (≥20 MPa), the hydraulic fracture could cross and connect multiple vugs. The difference between the horizontal minimum stress and the internal pressure of the vug was also particularly significant for fracture propagation. The smaller the difference, the easier the fracture communicated with the vug. The above findings would be valuable and constructive for the optimal design of field hydraulic fracturing in karstic-fractured carbonate reservoirs.
ResearchGate has not been able to resolve any references for this publication.