reservoir rocks
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2021 ◽  
Vol 54 (2F) ◽  
pp. 36-47
Author(s):  
Amel Nooralddin ◽  
Medhat Nasser ◽  
Aboosh Al-hadidy

The Upper Campanian Hartha Formation represents potential Cretaceous hydrocarbon-bearing reservoir rocks across the Y and J oilfields northwestern Zagros Basin, northern Iraq. The study objective is depositional environment which affects reservoir properties by tool, lithofacies, core, thin section, and logs, using petrel (V.2016) and strat software, facies distribution, grains, and diagenetic processes control and enhance reservoir properties which can plan platform production and minimize risks in choosing production wells location at two fields scale The current study is concerned with lithofacies and microfacies of the Hartha Formation within two fields in northern Iraq. Several subsurface well-log data, core, and cutting samples have been used in order to prepare thin sections that were subjected to sedimentological (lithofacies, and grain-size) examination. The petrography investigation revealed five rock-units including Hr. 1, 2, 3, 4, and 5, the thickness of 89 m in the Y-A field and increasing to up to 140 m in the J-B field might be due to erosion or tectonic uplift of the topography in Y subbasin. Which is locally sub-basin within study fields western banks of Tigris river as gentle slope ramp depositional condition with Spectrum microfacies from lime-mudstone to packstone texture with rudest and benthic debris enhances by diagenesis, dolomitization, dissolution moldic porosity, fracture; dolostone is more effective in the upper section of the formation in A than B Wells. Many factors, such as cementation, compaction, and pore-filling autogenic minerals, decrease reservoir quality, and their effects are similar in wells A and B.


Author(s):  
V. Е. Kosarev ◽  
◽  
E. R. Ziganshin ◽  
I. P. Novikov ◽  
A. N. Dautov ◽  
...  

Laboratory studies of the geomechanical properties of rocks are an important and integral part in building a geomechanical model. This study resulted in a set of data on geomechanical and elastic properties of the rocks that compose the lower part of the Middle Carboniferous section of the Ivinskoye oilfield (Russia). Relationships between various elastic parameters were also established. The distribution of geomechanical properties correlates with structural/textural features of the rocks under study and their lithological type. This information can be used as a basis for geomechanical modeling and in preparation for hydraulic fracturing. Keywords: geomechanics; elastic properties; carbonate rock; laboratory core studies.


Author(s):  
O. P. Abramova ◽  
◽  
D. S. Filippova ◽  

Taking into account the world and domestic experience of studying the ontogenesis of lithospheric hydrogen a combination of coupled hydrochemical, geochemical and microbiological factors of the accumulation of this natural gas together with methane in the terrigenous formations of the sedimentary cover is justified. It is predicted that various hydrochemical and microbiological processes that cause the development of carbon dioxide and sulfate corrosion of engineering structures, as well as cement of reservoir rocks and tires, can occur together with methane at industrial facilities of underground storage of hydrogen. The risks of reducing the volume of injected hydrogen in underground storage in addition to diffusion losses can be associated with geobiological factors, including the conversion of hydrogen into CH4 and H2S due to microbial activity, chemical interaction of hydrogen with minerals of reservoirs and tires, accompanied by changes in filtration-capacity and geomechanical properties, hydrogen embrittlement of metal structures of ground and underground well equipment. Keywords: geobiology; hydrogen; methane; underground storage; methanogenesis; acetogenesis; sulfate reduction.


2021 ◽  
pp. 57-68
Author(s):  
N. Yu. Moskalenkо

The relevance of the article is associated with the importance of the object of the research. Dozens of unique and giant oil and gas fields, such as Urengoyskoye, Medvezhye, Yamburgskoye, Vyngapurovskoye, Messoyakhskoye, Nakhodkinskoye, Russkoye, have been identified within the Cenomanian complex. The main feature of Cenomanian rocks is their slow rock cementation. This leads to significant difficulties in core sampling and the following studies of it; that is the direct and most informative source of data on the composition and properties of rocks that create a geological section.The identification of the factors, which determine the slow rock cementation of reservoir rocks, allows establishing a certain order in sampling and laboratory core studies. Consequently, reliable data on the reservoir and estimation of hydrocarbon reserves both of discovered and exploited fields and newly discovered fields that are being developed on the territory of the Gydan peninsula and the Bolshekhetskaya depression will be obtained. This study is also important for the exploration and development of hydrocarbon resources of the continental shelf in the waters of the Arctic seas of Russia as one of the most promising areas.As a result of the analysis, it was found that the formation of rocks of the PK1-3 Cenomanian age of the Bolshekhetskaya depression happened under conditions of normal compaction of terrigenous sedimentary rocks that are located in the West Siberian basin. Slow rock cementation of reservoir rocks is associated with relatively low thermobaric conditions of their occurrence, as well as the low content of clay and absence of carbonate cements. Their lithological and petrophysical characteristics are close to the analogous Cenomanian deposits of the northern fields of Western Siberia and can be applied to other unconsolidated rocks studied areas.


2021 ◽  
Vol 12 (1) ◽  
pp. 131
Author(s):  
Mohsen Faramarzi-Palangar ◽  
Abouzar Mirzaei-Paiaman ◽  
Seyyed Ali Ghoreishi ◽  
Behzad Ghanbarian

Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.


Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8559
Author(s):  
Evgenii Riabokon ◽  
Mikhail Turbakov ◽  
Nikita Popov ◽  
Evgenii Kozhevnikov ◽  
Vladimir Poplygin ◽  
...  

The paper presents the results of the experimental investigation of carbonate reservoir rocks subjected to quasistatic and nonlinear dynamic loads. During the quasistatic loading the zones of linear elasticity were determined. Dynamic loading of samples was performed at several frequencies and load amplitudes using a testing system. There were two zones found in which the elastic modulus changes nonlinearly in terms of dynamic load frequency. While the frequency of the dynamic load increases from 0 to 10 Hz the dynamic elastic modulus rises according to logarithmic law; while the frequency increases from 10 to 60 Hz elastic modulus rises according to a power law for each load amplitude. The amplitude of the longitudinal strain and phase shift decreases with increasing frequency of the dynamic load. Under the higher strain rates the rock gets stiffer in comparison with rock subjected to smaller strain rate dynamic loading. Saturation of rock samples with distilled water flattening the dependencies of dynamic Young’s modulus on frequency.


2021 ◽  
Author(s):  
Małgorzata Uliasz

A workover fluid is a type of special liquids used at the end of borehole drilling, i.e. during well operation or during reconstruction works. Such works, carried out at various stages of borehole operation, are aimed at maintaining or increasing the production of a specific well and at maintaining its proper technical condition. They may be carried out only after injecting the workover fluid into the borehole, which should generate counterpressure on the reservoir, preventing the inflow of reservoir media into the borehole, and should enable the maintaining of the hydraulic conductivity of the reservoir rock. To ensure that the basic requirements are satisfied by the workover fluid injected into the borehole, its physical and chemical properties must correspond to the geological and reservoir conditions of the specified level of reservoir rocks. Due to this, the composition of the workover fluid should be determined based on the reservoir pressure gradient, mineralogical composition of reservoir rocks and of their binder, as well as the chemical composition of reservoir waters. These are the basic criteria for selection of the composition and evaluation of the quality of the workover fluid, which enable control of the physicochemical processes occurring within the borehole zone, such as clogging of the porous space of rocks, hydration of clay minerals, capillary effects and changes in the surface tension at the interface, as well as the interaction of fluid with reservoir waters. Limitation of the intensity of occurrence of such processes, which affect the degree of damage to the permeability of the reservoir rocks in horizons featuring normal or reduced reservoir pressure, largely depends on the type of workover fluid used, i.e. brine without a solid phase and brine containing a solid phase or a liquid with density below 1.0 kg/dm3. The composition and technological properties of the workover fluid, properly selected to the specific geological and reservoir conditions, allow one to maintain the productivity of the well to a degree that does not require application of additional treatment, such as acid-treatment, fracturing and reperforations. The aim of the monograph is to show the role of a workover fluid in the conducted reconstruction treatments, as well as the importance of its technological properties in limiting damage to the permeability of reservoir rocks within the borehole zone. The presented issues comprise: • causes and threats to the deterioration of reservoir rock permeability resulting from the application of an improperly selected workover fluid; • tasks of the workover fluid and methods to improve its technological properties in terms of protecting the hydraulic conductivity of reservoir rocks; • types of workover fluids developed, the methodology for determination and assessment of their technological properties, as well as usability under reservoir conditions. The monograph also includes a short description of other special liquids used in the preparation of a well for exploitation. These are: washing and cleaning liquids, packer fluids and those used for perforation, as well as buffers for rope operations and pipe cleaning prior to packer fluid injection. The presented issue is a synthesis of a wide range of research and development works carried out at the INiG - PIB. It has been prepared based on the obtained results of laboratory tests carried out for geological and reservoir conditions existing in the productive horizons of the Carpathian Foredeep, as well as of the Carpathians and the Polish Lowlands. Keywords: borehole reconstruction, geological and reservoir conditions, workover fluid tasks, workover fluid properties, chemicals, blockers, permeability


2021 ◽  
Author(s):  
Abdelwahab Noufal ◽  
Ibrahim Altameemi ◽  
Abdulla Shehab ◽  
Hamda Al Shehhi

Abstract The rock properties in the reservoir rocks represent stiffness and strength properties, while the unexpected variation in the dense intervals varies with the fabric and other sedimentological and rock types. The purpose of this paper is to present the mechanical rock testing parameters of Lower Cretaceous reservoirs, including the tight intervals in a giant field of Abu Dhabi. In order to enable the evaluation of the mechanical parameters, there is a need to assess the reservoir rocks, as well as the stress configuration around and away from the wells. This paper introduces a workflow that integrates multidisciplinary data to develop a geomechanical model aiming to reduce drilling risks and optimizing reservoir appraisal. Cores, wireline logs, CT scans, SEM and thin sections were used to characterize the fracture systems and build the robust seismic driven geomechanical model. A conceptual model has been firstly developed, where reservoir heterogeneity has been quantitatively described in relation to tectonic deformation events, followed by incorporating a 1D-MEM's (Mechanical Earth Model), which used to calibrate the seismic based elastic properties. Results indicate good correlations developed between dynamic and static Young's Modulus, Biot's coefficient, Friction Angle and Unconfined Compressive Strength by incorporating the results of rock mechanics testing, leading to create a dynamic YME-driven correlation. Good correlations were also obtained between Effective Porosity, and Static Young's modulus, Biot's coefficient, Friction angle and Unconfined compressive strength, leading to create a Porosity-driven correlation. In addition, friction angle correlation increases if proper data is considered, making feasible to build a correlation in both dynamic YME and Effective Porosity. Finally, the presence of several partially conductive fracture sets within the reservoir, including both sub-vertical and moderately dipping conjugate sets, with gently dipping/bed-parallel fractures. They have been developed under a predominant strike-slip regime that swaps a normal faulting stress regime at depth. Fracture porosity is related to micro- and meso-scale fractures, and fracture permeability is more significant compared to the storage capacity of the matrix porosity. Rock fabrics are varied in different zones, which likely explains differences in the mechanical behaviour.


2021 ◽  
Vol 18 (6) ◽  
pp. 970-983
Author(s):  
Jing Ba ◽  
Peng Hu ◽  
Wenhui Tan ◽  
Tobias M Müller ◽  
Li-Yun Fu

Abstract The reservoir rocks from Chang-7 member of Yanchang Formation of Ordos Basin are characterised with heterogeneous fabric structures at the pore scale, and low porosity/permeability is exhibited at the macro scale. Precise prediction of reservoir brittleness is of great significance to oil production. Ultrasonic experiments are performed on tight sandstones collected from the target formation. A rock-physics model (RPM) is presented based on the Voigt–Reuss–Hill average (VRH), self-consistent approximation (SCA) and differential effective medium (DEM) theory. The brittleness characteristics relying on mineral composition, porosity and microcrack properties are explored by using the RPM. The Young's modulus increases and Poisson ratio decreases with increasing quartz content. Based on experimental, log and seismic data, brittle mineral analysis of rock physical model is performed at multiple scales. The model accuracy is verified by experimental data and well log data. The brittleness distribution is predicted on the basis of log and seismic data, which can be instructive for the reservoir rock fracturing in actual engineering operations.


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