Reservoir Rock Types Research Articles

Unsupervised machine learning using 3D seismic data applied to reservoir evaluation and rock type identification

Net reservoir discrimination and rock type identification play vital roles in determining reservoir quality, distribution, and identification of stratigraphic baffles for optimizing drilling plans and economic petroleum recovery. Although it is challenging to discriminate small changes in reservoir properties or identify thin stratigraphic barriers below seismic resolution from conventional seismic amplitude data, we have found that seismic attributes aid in defining the reservoir architecture, properties, and stratigraphic baffles. However, analyzing numerous individual attributes is a time-consuming process and may have limitations for revealing small petrophysical changes within a reservoir. Using the Maui 3D seismic data acquired in offshore Taranaki Basin, New Zealand, we generate typical instantaneous and spectral decomposition seismic attributes that are sensitive to lithologic variations and changes in reservoir properties. Using the most common petrophysical and rock typing classification methods, the rock quality and heterogeneity of the C1 Sand reservoir are studied for four wells located within the 3D seismic volume. We find that integrating the geologic content of a combination of eight spectral instantaneous attribute volumes using an unsupervised machine-learning algorithm (self-organizing maps [SOMs]) results in a classification volume that can highlight reservoir distribution and identify stratigraphic baffles by correlating the SOM clusters with discrete net reservoir and flow-unit logs. We find that SOM classification of natural clusters of multiattribute samples in the attribute space is sensitive to subtle changes within the reservoir’s petrophysical properties. We find that SOM clusters appear to be more sensitive to porosity variations compared with lithologic changes within the reservoir. Thus, this method helps us to understand reservoir quality and heterogeneity in addition to illuminating thin reservoirs and stratigraphic baffles.

Simulation Study of Nanoparticle Transport in Porous Media: Effects of Salinity and Reservoir Parameters

Although experimental studies confirmed the effectiveness of nanoparticles in enhanced oil recovery applications, no comprehensive investigation has been carried out to reveal the effect of different subsurface factors on this improvement. Proper application of nanoparticles mainly depends on their ability to travel long distances within a reservoir without agglomeration, retention and blocking the pore throats. This study strengthens our understanding about the effect of the main subsurface factors on the nanofluid-assisted enhanced oil recovery. For doing so, a transport approach utilizing kinetic Langmuir model is developed and validated using experimental data. Thereafter, the effect of reservoir rock type and its properties (clay content and grain size), salinity of injected fluid, and reservoir temperature on the transport and retention of nanoparticles in porous media in relation to enhanced oil recovery methods is investigated. Since the amount of nanoparticles in the injected fluid and on the rock surface (as deposited) control the mobility and wettability alteration, the effect of subsurface factors and salinity of injected fluid on this deposition is also analyzed. The results showed that the rock type and its properties significantly affect the transport and retention of nanoparticles in porous media. It was also found that the brine salinity has the greatest impact on the amount of nanoparticles deposited on the rock surface. The surface covered by NPs increased from 10 to 82 % after changing salinity from 3 weight percent NaCl to API brine.

Dissolution of Different Reservoir Rocks by Organic Acids in Laboratory Simulations: Implications for the Effect of Alteration on Deep Reservoirs

Organic acids are important agents in the alteration of deep reservoirs. It is difficult, however, to assess the impact of organic acid alteration on deep reservoirs because different dissolution processes may occur during diagenesis. This study simulated the dissolution of three different types of reservoir rocks by acetic acid in a closed system and compared the mineral and elemental composition, surface morphology, pore structure, and water chemistry variations of the initial and altered samples. The study demonstrated that both micrite and sucrosic dolostone are strongly dissolved, losing about 20%–30% of their initial rock sample weights. Observation under SEM showed that the limestone dissolved homogenously, whereas the dolostone showed honeycomb-like dissolution. Both carbonate samples showed the development of large voids, including holes and cavities of micrometer scale, but nanopores of various sizes were blocked. In contrast, lithic arkose was heterogeneously altered, losing a weight proportion of about 13% by dissolution of calcite cement. These micrometer-scale microfissures were developed, but those nanometer-scale pores just varied in a narrow range of sizes. The volume increase in all three reservoir types is mainly attributed to the dissolution of carbonate minerals. In deep reservoirs, in situ generated organic acids can enlarge existing cavities in carbonates and develop microfissures in sandstones. The microfissure porosity in sandstone is limited but can increase through other geological processes such as overpressure. More importantly, these acids can maintain the acidity of pore waters, inhibit the precipitation of dissolved minerals, and help to preserve reservoir porosity. Although temperature plays an insignificant role in laboratory simulations, it influences both the generation and destruction processes of organic acids in deep reservoirs on geologic time scales and, thus, warrants further attention. The results provide a basis for recognizing the typical patterns of organic acid dissolution on different reservoir rocks and further suggest the potential role of organic acids in the formation and preservation of secondary porosity in deeply buried reservoirs.

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

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

Pre-salt regional structure and its control for hydrocarbon accumulation in Lower Congo Basin from seismic and gravity data

In the present work, we utilize the processing and interpretation of both seismic and gravity data to clarify pre-salt regional structure pattern and further guide pre-salt exploration in Lower Congo Basin. Combining other available geologic and lithology data sets as well as a tectonic model, we present a new understanding of the pre-salt uplift and depression pattern of Lower Congo Basin. The results show a clear E-W distribution of the first-class structural units, namely, the inner rift zone, central uplift zone and outer rift zone, where the latter two parts are separated by the Atlantic hinge zone. The outer rift zone is characterized by a "two convex and three concave" high and depression pattern. The patterns of the pre-salt structure control the distribution of source rocks, reservoir and cap rock types, and also affect the combination and model of hydrocarbon accumulation. The key exploration area can be placed in the shallow water area on the land side of both the inner rift zone and the outer rift zone. The favorable exploration targets should be focused on fault-controlled blocks of the structural high horst. This study can provide the geophysical support for a new interpretation of the pre-salt seismic sequence, the strategic selection of pre-salt hydrocarbon and the next exploration deployment.

Integrated petrophysical and petrographical studies for characterization of reservoirs: a case study of Muglad Basin, North Sudan

Petrography, scanning electron microscopy, X-ray diffraction, and both conventional and special core analyses are applied to precisely reservoir characterize the Lower Cretaceous Bentiu and Abu Gabra Formations of the Muglad Basin, which is among the largest hydrocarbon reservoirs in South Kordofan, SW North Sudan. Based on this integrated study, the Abu Gabra–Bentiu sequence comprises four petrographical microfacies, which consist of two reservoir rock types (RRTs). RRT1 is composed of quartz arenites and RRT2 is composed of quartz wackes. The greatest storage, flow capacities, and reservoir quality are assigned for RRT1 due to its good-to-excellent porosity (average ∅ = 26.7%), permeability (average k = 1365 md), reservoir quality index (RQI, average = 1.43 μm), flow zone indicator (FZI, average = 3.66 μm) and discrete rock type (DRT, average = 13). The relatively low-to-fair reservoir quality of the Abu Gabra Formation (average ∅ = 13.2%, average k = 14.7 md, average RQI = 0.17 μm, average FZI = 1.05 μm, and average DRT = 10) is due to authigenic kaolinite and siderite content, compaction and cementation by silica and clay patches.

The effect of subsurface factors on the performance of nanofluid-assisted enhanced oil recovery: Modeling and sensitivity analysis

Successful implementation of nanofluid-assisted enhanced oil recovery (EOR) operation mainly depends on proper determination of the main factors that control both transport and retention of nano-sized particles in porous media. In this study, a new transport scheme using the kinetic Langmuir model was first developed and validated by some experimental data from the literature. This model was then used to investigate the effect of reservoir rock type, clay content, grain size, brine type, and reservoir temperature on distribution of nanoparticles on the rock surface and in the injected fluid in relation to EOR methods. Moreover, a two-phase approach was derived to simulate the effect of these parameters on both wettability alteration and mobility control. Results confirmed that the deposition tendency of silica nanoparticles on limestone is higher than that on sandstone. By increasing clay content, both surface area and deposition sites increases and consequently more nanoparticles were found to retain. In the case of polyethylene glycol (PEG) stabilized silica nanoparticles, the amount of oil recovery increased by increasing the salinity of brine. Increasing the salinity of brine resulted in considerable deposition of silica nanoparticles on the rock surface and made them more water wet. These phenomena eventually increased the final recovery factor from 62% to 79%. Since the temperature simultaneously affects the deposition and detachment kinetics of nanoparticles and the reservoir fluid properties, its effect on oil recovery in nanoassisted-EOR technique cannot be generalized.

A Further Investigation on the Application of Critical Pore Size as an Approach for Reservoir Rock Typing

Abstract The correct definition of rock types plays a critical role in reservoir characterization, simulation, and field development planning. In this study, we use the critical pore size (linf) as an approach for reservoir rock typing. Two linf relations were separately derived based on two permeability prediction models and then merged together to drive a generalized linf relation. The proposed rock typing methodology includes two main parts: in the first part, we determine an appropriate constant coefficient, and in the second part, we perform reservoir rock typing based on two different scenarios. The first scenario is based on the forming groups of rocks using statistical analysis, and the second scenario is based on the forming groups of rocks with similar capillary pressure curves. This approach was applied to three data sets. In detail, two data sets were used to determine the constant coefficient, and one data set was used to show the applicability of the linf method in comparison with FZI for rock typing.

Applications of Artificial Neural Networks for Seismic Facies Classification

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200577, “Applications of Artificial Neural Networks for Seismic Facies Classification: A Case Study From the Mid-Cretaceous Reservoir in a Supergiant Oil Field,” by Ali Al-Ali, Karl Stephen, SPE, and Asghar Shams, Heriot-Watt University, prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Facies classification using data from sources such as wells and outcrops cannot capture all reservoir characterization in the interwell region. Therefore, as an alternative approach, seismic facies classification schemes are applied to reduce the uncertainties in the reservoir model. In this study, a machine-learning neural network was introduced to predict the lithology required for building a full-field Earth model for carbonate reservoirs in southern Iraq. The work and the methodology provide a significant improvement in facies classification and reveal the capability of a probabilistic neural network technique. Introduction The use of machine learning in seismic facies classification has increased gradually during the past decade in the interpretation of 3D and 4D seismic volumes and reservoir characterization work flows. The complete paper provides a literature review regarding this topic. Previously, seismic reservoir characterization has revealed the heterogeneity of the Mishrif reservoir and its distribution in terms of the pore system and the structural model. However, the main objective of this work is to classify and predict the heterogeneous facies of the carbonate Mishrif reservoir in a giant oil field using a multilayer feed-forward network (MLFN) and a probabilistic neural network (PNN) in nonlinear facies classification techniques. A related objective was to find any domain-specific causal relationships among input and output variables. These two methods have been applied to classify and predict the presence of different facies in Mishrif reservoir rock types. Case Study Reservoir and Data Set Description. The West Qurna field is a giant, multibillion-barrel oil field in the southern Mesopotamian Basin with multiple carbonate and clastic reservoirs. The overall structure of the field is a north/south trending anticline steep on the western flank and gentle on the eastern flank. Many producing reservoirs developed in this oil field; however, the Mid- Cretaceous Mishrif reservoir is the main producing reservoir. The reservoir consists of thick carbonate strata (roughly 250 m) deposited on a shallow water platform adjacent to more-distal, deeper-water nonreservoir carbonate facies developing into three stratigraphic sequence units in the second order. Mishrif facies are characterized by a porosity greater than 20% and large permeability contrast from grainstones to microporosity (10-1000 md). The first full-field 3D seismic data set was achieved over 500 km2 during 2012 and 2013 in order to plan the development of all field reservoirs. A de-tailed description of the reservoir has been determined from well logs and core and seismic data. This study is mainly based on facies log (22 wells) and high-resolution 3D seismic volume to generate seismic attributes as the input data for the training of the neural network model. The model is used to evaluate lithofacies in wells without core data but with appropriate facies logs. Also, testing was carried out in parallel with the core data to verify the results of facies classification.

Integrated sedimentological and petrophysical characterization for clastic reservoirs: A case study from New Zealand

The present study aims at characterizing the sedimentological and petrophysical properties of the Middle-Late Miocene Mt Messenger reservoir in Taranaki Basin, New Zealand. It is a detailed study based on availability of sedimentological (petrography, SEM and XRD), well log data (gamma ray, neutron, density, sonic, shallow and deep resistivity, PEF and RFT logs), in addition to conventional and special core analysis data for Mt Messenger reservoir.The Mt Messenger Formation is considered onshore fan units of low resistivity clastic rocks with high percentage of metamorphic lithic fragments. From the RFT logs, it is composed of two or three compartments partially separated from each other by some tight zones. The reservoir zones are represented by thin beds of well sorted very fine to silty-grained litharenite; sometimes is feldspathic, argillaceous and/or micaceous with very good intergranular porosity of average reaches to 25%. Petrographically and petrophysically four reservoir rock types (RRTs) or hydraulic flow units (HFUs) can be assigned, each with its diagnostic petrophysical properties and storage and flow capacities. The reservoir quality increases to the south at Ngatoro-2 well, where a total of gas- and oil-bearing 5 prospective thin beds are recognized, which are mostly composed of litharenite with very good porosity (21–27.8%) and permeability (63–368 md). Its reservoir quality index (RQI) and flow zone indicator (FZI) indicates fair to good reservoir quality (0.544 = RQI ≤ 1.151 μm, and 1.972 = FZI ≤ 3.049 μm). Presence of argillaceous and/or micaceous materials in addition to the silt-sized grains decreased the reservoir quality from RRT1 samples which are characterized by fair to good reservoir properties (homogeneous pore size distribution, 0.18 = R35 ≤ 1.32 μm) to the RRT4 samples which are considered slightly tight reservoir (slightly heterogeneous pore size distribution, 4.44 = R35 ≤ 9.97 μm).

Integrated sedimentological and petrophysical rock-typing of the Messinian Abu Madi formation in South Batra gas field, onshore Nile Delta, Egypt

The Messinian incised-valley fill (IVF) sediments of the Abu Madi Formation host the most prolific gas-bearing sandstones in the onshore Nile Delta, Egypt. This study provides the first integrated geological, geophysical and petrophysical approach in order to link the Abu Madi sandstones’ reservoir properties with their geological framework, and thereby optimize the predictability of the most prospective reservoir rock types (RRT). Sandstone-bearing reservoir levels are mostly associated with the fluvial-estuarine valley-fill sediments (Abu Madi levels II and III). The intergranular volume of some sandstones (e.g. arkoses) is occupied by compacted ductile argillaceous rock fragments (pseudomatrix), and therefore have dominantly microporosity with anisotropic, poorly-connected pore system.Three RRT were recognized in Abu Madi reservoir levels. RRTI has the best poro-perm characteristics with excellent capillary properties (e.g. megapores, lowest initial displacement pressure ~10 psi air/mercury and irreducible water saturation Swir below 20%). Pore system heterogeneity increases in RRTII and RRTIII. The latter contains dominant micropores and exhibits the highest initial displacement pressure ~500 psi air/mercury and Swir exceeding 50%. RRTI often comprises subarkoses associated with the cross-bedded, massive and cross-laminated lithofacies of the fluvial channel-fill and fluvial channel sand bars facies. Whilst RRTII and III mainly comprise the sandstone lithofacies deposited in the abandoned fluvial, estuarine and restricted marine successions. Excellent reservoir quality facies follows the depositional trend of the valley-fill fluvial channels and pinches-out where repeated avulsion and channel abandonment processes dominate. The spatial distribution of Abu Madi RRT highlights the paramount impact of syn-depositional attributes and canyon-floor relief on the sediments’ reservoir heterogeneity and productivity. Moreover, the present integrated RRT approach could serve as a model for exploration in analogues settings where autogenic processes induce widespread sedimentary heterogeneity, which largely impacts the reservoir quality.

ROCK QUALITY GROUPING IN SANDSTONE FORMATION USING A CRITICAL POROSITY APPROACH AT FORMATION PRESSURE CONDITIONS

The methods of grouping reservoir rock types based on the physical properties of rocks that have been studied by previous researchers still have a relatively large value of uncertainty. This uncertainty arises in conditions where rock type grouping is carried out in wells that do not have core sample data. Where we know that in the oil and gas field, not all wells in the field are subjected to rock sampling, either routine core analysis or special core analysis. From these problems, the authors feel the need to carry out this study to create a method for classifying reservoir rock types based on the physical properties of rocks that can be used in wells that do not have core sample data. The rock types in the wells that do not have core samples will be grouped based on the critical porosity value of the rock obtained from the vp value in the acoustic log data owned by these wells. By making an approach model through the critical porosity of rocks from wells that have core sample data, wells that only have acoustic log data can be grouped by using the critical porosity approach which is generated from the vp value of the acoustic log.

Eogenetic karst and its control on reservoirs in the Ordovician Majiagou Formation, eastern Sulige gas field, Ordos Basin, NW China

Abstract To further ascertain the origin of the Ordovician Majiagou Formation reservoirs in the Ordos Basin, the M54-M51 sub-members of the Ordovician Majiagou Formation in the eastern Sulige gasfield of Ordos Basin were taken as examples to analyze the vertical development characteristics of eogenetic karst and to discover the dissolution mechanism and its control on reservoirs through observation of a large number of cores and thin sections. According to detailed analysis of petrologic characteristics, the reservoir rock types include micritic dolomite, grain dolomite and microbialite which have mainly moldic pore, intergranular (dissolved) pore, and (dissolved) residual framework pore as main reservoir space respectively. The study area developed upward-shallowing sequences, with an exposure surface at the top of a single upward-shallowing sequence. The karst systems under the exposure surface had typical exposure characteristics of early dissolution and filling, indicating these reservoirs were related to the facies-controlled eogenetic karstification. With the increase of karstification intensity, the reservoirs became worse in physical properties.

Effect of Micropore Structure on Macroscopic Water Cut Changing Law in Strongly Heterogeneous Reservoirs

Reservoir rock type (RRT) classification is commonly used for the fine characterization of strongly heterogeneous reservoirs. Many research focused on proposing different RRT methods, while few studies focused on the relationship between micropore structure and macroscopic seepage law of fluid transporting through different types of formation. Considering the different diagenesis degrees of rock types in different sedimentary facies, the quadrant unit method and FZI method were applied to classify and evaluate the strongly heterogeneous reservoirs. The corresponding capillary pressure curves and relative permeability curves for different rock types could be obtained. A set of theoretical models that could describe the macroscopic seepage law are proposed, and numerical simulation case studies were carried out to explore the superimposed seepage law in reservoirs under different degrees of heterogeneity. Results show that water cut rises faster in poor-property RRT formation than in good-property RRT formation, with a lower recovery factor under the same conditions. The water cut rising rate increases firstly and then decreases with water cut and recovery degree increasing. The poorer the rock property is, the earlier and higher the peak value of water cut rising rate is. Also, based on numerical simulation case studies, the superimposed seepage law is close to that in the poor-property formation as the heterogeneity degree strengthens. The newly proposed method not only could provide a reference for rock type classification based on micropore structure but also could expound the influence of micropore structure on the change law of macroscopic water cut and elaborates the macroscopic change law after the superposition of different types of reservoirs. The conventional normalization of relative permeability curves is only applicable to relatively homogeneous reservoirs and not applicable to strongly heterogeneous reservoirs, especially when the permeability variation is higher than 0.7. The newly proposed approach is capable of analyzing the effect of micropore structure on macroscopic seepage law and improving the prediction accuracy of the production profile.

Differential diagenetic evolution and hydrocarbon charging of the tight limestone reservoir of the Da’anzhai Member in the central Sichuan Basin, China

The tight lacustrine carbonate reservoir of the Da’anzhai Member, Lower Jurassic Ziliujing Formation, in the central Sichuan Basin is a typical tight oil reservoir, and it is one of the crucial petroleum exploration targets in the Sichuan Basin. The porosity of the limestone ranges from 0.5% to 2%, and the permeability ranges from 0.001 to 1 mD. The Da’anzhai limestone experienced multiple diageneses, including compaction, cementation, dissolution, and recrystallization. Different diageneses occurred in the burial process due to the various fabrics and depositional environments, eventually forming distinct rock types; therefore, the pore evolution and hydrocarbon charging characteristics are inconsistent. In our research, there are two stages of major maturation and hydrocarbon expulsion in the source rocks of the Da’anzhai Member. The first large-scale expulsion of hydrocarbon is oil-based and gas-supplemented, whereas the second expulsion is dominated by gas. Hydrocarbon-filling characteristics are different in different types of reservoir rocks. Compared with the bioclastic grainstone and crystalline limestone, we have considered that the argillaceous shell packstone and bioclastic packstone deposited in the shallow and semideep lake environment still contain residual intergranular pores, which have not become fully compacted and are partly filled with hydrocarbons. The presence of hydrocarbon fluid hindered the secondary porosity reduction and was helpful for reserve space preservation.

Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

Formation evaluation and reservoir characteristics of the Messinian Abu Madi sandstones in Faraskour Gas Field, onshore Nile Delta, Egypt

The Messinian Abu Madi Formation represents the most prospective reservoir target in the Nile Delta. Hydrocarbon exploration endeavors in Nile Delta over the last few decades highlighted some uncertainties related to the predictability and distribution of the Abu Madi best reservoir quality facies. Therefore, this study aims at delineating the factors controlling the petrophysical heterogeneity of the Abu Madi reservoir facies in Faraskour Field, northeastern onshore part of the Nile Delta. This work provides the very first investigation on the reservoir properties of Abu Madi succession outside the main canyon system. In the study area, Abu Madi reservoir is subdivided into two sandstone units (lower fluvial and upper estuarine). Compositionally, quartzose sandstones (quartz > 65%) are more common in the fluvial unit, whereas the estuarine sandstones are often argillaceous (clays > 15%) and glauconitic (glauconite > 10%). The sandstones were classified into four reservoir rock types (RRTI, RRTII, RRTIII, and RRTIV) having different petrophysical characteristics and fluid flow properties. RRTI hosts the quartzose sandstones characterized by mega pore spaces (R35 > 45 µm) and a very well-connected, isotropic pore system. On the other side, RRTIV constitutes the lowest reservoir quality argillaceous sandstones containing meso- and micro-sized pores (R35 > 5 µm) and a pore system dominated by dead ends. Irreducible water saturation increases steadily from RRTI (Swir ~ 5%) to RRTIV (Swir > 20%). Additionally, the gas–water two-phase co-flowing characteristics decrease significantly from RRTI to RRTIV facies. The gaseous hydrocarbons will be able to flow in RRTI facies even at water saturation values exceeding 90%. On the other side, the gas will not be able to displace water in RRTIV sandstones even at water saturation values as low as 40%. Similarly, the influence of confining pressure on porosity and permeability destruction significantly increases from RRTI to RRTIV. Accordingly, RRTI facies are the best reservoir targets and have high potentiality for primary porosity preservation.

Characteristics and pore evolution of the tight sandstone reservoirs of the Chang-7 Member of the Yanchang Formation in the Xin’anbian area, Ordos basin

More than 100 million tons of tight oil reserves have been discovered in the Xin’anbian area of the Ordos basin in recent years, of which the main reservoir is the Chang-7 Member of the Yanchang Formation. To identify the characteristics of the tight sandstone reservoir and their the development of the Chang-7 Member in the study area, casting thin sections, scanning electron microscopy (SEM), high-pressure mercury injection, cathodoluminescence and other technical methods were used to analyze the reservoir rock types and their physical properties and pore structure. Based on reservoir diagenesis research and quantitative evaluations of reservoir pores, a reservoir pore evolution mode was established. The results showed that the main rock types in the tight sandstone reservoirs in the Chang-7 Member of the Xin’anbian area were lithic feldspathic sandstone and feldspathic detritus sandstone and that the reservoir space types were mainly feldspar dissolved pores, with a few residual intergranular pores, clay intercrystalline pores, and microfractures. The reservoirs were classified as having low porosity and low permeability and extra-low porosity and extra-low permeability. The porosity and permeability of the reservoirs were between 4 ~ 10% and 0.01 ~ 1 mD, respectively, and were mainly controlled by compaction, cementation, and dissolution. Compaction and cementation reduced the porosity and permeability, while dissolution increased the porosity and permeability. The Chang-7 Member reservoir mainly experienced weak-medium compaction, medium-strong cementation, and different degrees of dissolution. The average loss of porosity due to cementation was around 25%, while the average loss due to compaction was around 13%. This research determined four key stages in the porosity evolution of the Chang-7 Member in the study area: (1) the porosity was reduced to 26% from the Triassic to the Early Jurassic period, which was mainly due to compression compaction; (2) the reservoir was seriously damaged by cementation from the Middle Jurassic to Late Jurassic period, where the porosity decreased to 5%; (3) in the Early Cretaceous period, the porosity increased to 11% due to dissolution; and (4) the porosity was reduced to 7% from the late Early Cretaceous to early Late Cretaceous period, which was mainly due to cementation.

Reply to the discussion on “Influence of structures on drainage patterns in the Tushka region, SW Egypt. Journal of African Earth Sciences 136, 262–271 by C.A. Robinson, H. El-Kaliouby, E. Ghoneimˮ by B.S. Nabawy

The present study aims at conducting a detailed reservoir characterization of the Early Cretaceous Bentiu and Abu Gabra formations in Muglad basin which is one of the most prospective hydrocarbon basins in South Kordofan, SW Sudan. This can be achieved through integration between well logging (conventional), petrography (thin sections, and scanning electron microscopy SEM), and core data.Based on this integrated study, the Abu Gabra-Bentiu sequence is composed of two reservoir rock types (RRTs). RRT1 is composed of quartz arenite, whereas RRT2 is composed of quartz wacke. The best storage and flow capacities and the best reservoir quality are assigned for RRT1 due to its good to excellent porosity (20.0 ≤ ∅ ≤ 34.1%), permeability (138 ≤ k ≤ 4140 md), reservoir quality index (0.61 ≤ RQI ≤ 2.91 μm), and flow zone indicator (2.37 ≤ FZI ≤ 6.12 μm) values. This rock type is mostly assigned to two hydraulic flow units (HFU-1, and HFU-2) of Bentiu Formation which comprises 95% of the flow capacity of the sequence. The average reservoir parameters of the studied sequence, including shale volume, effective porosity and hydrocarbon saturation, equal to 31.6, 16.2 and 39.5%, respectively with 29.5 m as a total net-pay thickness.Petrographically, the relatively low contribution of the Abu Gabra Formation is due to its authigenic mineral content, compaction, and cementation.

Integrated reservoir characterization and quality analysis of the carbonate rock types, case study, southern Iraq

The reservoir characterization and rock typing is a significant tool in performance and prediction of the reservoirs and understanding reservoir architecture, the present work is reservoir characterization and quality Analysis of Carbonate Rock-Types, Yamama carbonate reservoir within southern Iraq has been chosen. Yamama Formation has been affected by different digenesis processes, which impacted on the reservoir quality, where high positively affected were: dissolution and fractures have been improving porosity and permeability, and destructive affected were cementation and compaction, destroyed the porosity and permeability. Depositional reservoir rock types characterization has been identified depended on thin section analysis, where six main types of microfacies have been recognized were: packstone-grainstone, packstone, wackestone-packstone, wackestone, mudstone-wackestone, and mudstone. By using flow zone indicator, four groups have been defined within Yamama Formation, where the first type (FZI-1) represents the bad quality of the reservoir, the second type (FZI-2) is characterized by the intermediate quality of the reservoir, third type (FZI-3) is characterized by good reservoir quality, and the fourth type (FZI-4) is characterized by good reservoir quality. Six different rock types were identified by using cluster analysis technique, Rock type-1 represents the very good type and characterized by low water Saturation and high porosity, Rock type-2 represents the good rock type and characterized by low water saturation and medium–high porosity, Rock type-3 represents intermediate to good rock type and characterized by low-medium water saturation and medium porosity, Rock type-4 represents the intermediate rock type and characterized by medium water saturation and low–medium porosity, Rock type-5 represents intermediate to bad rock type and characterized by medium–high water saturation and medium–low porosity, and Rock type-6 represents bad rock type and characterized by high water saturation and low porosity. By using Lucia Rock class typing method, three types of rock type classes have been recognized, the first group is Grain-dominated Fabrics—grainstone, which represents a very good rock quality corresponds with (FZI-4) and classified as packstone-grainstone, the second group is Grain-dominated Fabrics—packstone, which corresponds with (FZI-3) and classified as packstone microfacies, the third group is Mud-dominated Fabrics—packstone, packstone, correspond with (FZI-1 and FZI-2) and classified as wackestone, mudstone-wackestone, and mudstone microfacies.