Showing papers on "Petroleum reservoir published in 2013"

Organic-rich Marcellus Shale lithofacies modeling and distribution pattern analysis in the Appalachian Basin

Abstract: The Marcellus Shale is considered to be the largest unconventional shale-gas resource in the United States. Two critical factors for unconventional shale reservoirs are the response of a unit to hydraulic fracture stimulation and gas content. The fracture attributes reflect the geomechanical properties of the rocks, which are partly related to rock mineralogy. The natural gas content of a shale reservoir rock is strongly linked to organic matter content, measured by total organic carbon (TOC). A mudstone lithofacies is a vertically and laterally continuous zone with similar mineral composition, rock geomechanical properties, and TOC content. Core, log, and seismic data were used to build a three-dimensional (3-D) mudrock lithofacies model from core to wells and, finally, to regional scale. An artificial neural network was used for lithofacies prediction. Eight petrophysical parameters derived from conventional logs were determined as critical inputs. Advanced logs, such as pulsed neutron spectroscopy, with log-determined mineral composition and TOC data were used to improve and confirm the quantitative relationship between conventional logs and lithofacies. Sequential indicator simulation performed well for 3-D modeling of Marcellus Shale lithofacies. The interplay of dilution by terrigenous detritus, organic matter productivity, and organic matter preservation and decomposition affected the distribution of Marcellus Shale lithofacies distribution, which may be attributed to water depth and the distance to shoreline. The trend of normalized average gas production rate from horizontal wells supported our approach to modeling Marcellus Shale lithofacies. The proposed 3-D modeling approach may be helpful for optimizing the design of horizontal well trajectories and hydraulic fracture stimulation strategies.

Carbon dioxide dissolution in structural and stratigraphic traps

Abstract: The geologic sequestration of carbon dioxide ( CO2) in structural and stratigraphic traps is a viable option to reduce anthropogenic emissions. While dissolution of the CO2 stored in these traps reduces the long-term leakage risk, the dissolution process remains poorly understood in systems that reflect the appropriate subsurface geometry. Here, we study dissolution in a porous layer that exhibits a feature relevant for CO2 storage in structural and stratigraphic traps: a finite CO2 source along the top boundary that extends only part way into the layer. This feature represents the finite extent of the interface between free-phase CO2 pooled in a trap and the underlying brine. Using theory and simulations, we describe the dissolution mechanisms in this system for a wide range of times and Rayleigh numbers, and classify the behaviour into seven regimes. For each regime, we quantify the dissolution flux numerically and model it analytically, with the goal of providing simple expressions to estimate the dissolution rate in real systems. We find that, at late times, the dissolution flux decreases relative to early times as the flow of unsaturated water to the CO2 source becomes constrained by a lateral exchange flow though the reservoir. Application of the models to several representative reservoirs indicates that dissolution is strongly affected by the reservoir properties; however, we find that reservoirs with high permeabilities ( Darcy) that are tens of metres thick and several kilometres wide could potentially dissolve hundreds of megatons of CO2 in tens of years.

Quantitative geophysical pore-type characterization and its geological implication in carbonate reservoirs

Abstract: This paper discusses and addresses two questions in carbonate reservoir characterization: how to characterize pore‐type distribution quantitatively from well observations and seismic data based on geologic understanding of the reservoir and what geological implications stand behind the pore‐type distribution in carbonate reservoirs. To answer these questions, three geophysical pore types (reference pores, stiff pores and cracks) are defined to represent the average elastic effective properties of complex pore structures. The variability of elastic properties in carbonates can be quantified using a rock physics scheme associated with different volume fractions of geophysical pore types. We also explore the likely geological processes in carbonates based on the proposed rock physics template. The pore‐type inversion result from well log data fits well with the pore geometry revealed by a FMI log and core information. Furthermore, the S‐wave prediction based on the pore‐type inversion result also shows better agreement than the Greensberg‐Castagna relationship, suggesting the potential of this rock physics scheme to characterize the porosity heterogeneity in carbonate reservoirs. We also apply an inversion technique to quantitatively map the geophysical pore‐type distribution from a 2D seismic data set in a carbonate reservoir offshore Brazil. The spatial distributions of the geophysical pore type contain clues about the geological history that overprinted these rocks. Therefore, we analyse how the likely geological processes redistribute pore space of the reservoir rock from the initial depositional porosity and in turn how they impact the reservoir quality.

Carbon dioxide dissolution in structural and stratigraphic traps

Abstract: The geologic sequestration of carbon dioxide (CO2) in structural and stratigraphic traps is a viable option to reduce anthropogenic emissions While dissolution of the CO2 stored in these traps reduces the long-term leakage risk, the dissolution process remains poorly understood in systems that reflect the appropriate subsurface geometry Here, we study dissolution in a porous layer that exhibits a feature relevant for CO2 storage in structural and stratigraphic traps: a finite CO2 source along the top boundary that extends only part way into the layer This feature represents the finite extent of the interface between free-phase CO2 pooled in a trap and the underlying brine Using theory and simulations, we describe the dissolution mechanisms in this system for a wide range of times and Rayleigh numbers, and classify the behaviour into seven regimes For each regime, we quantify the dissolution flux numerically and model it analytically, with the goal of providing simple expressions to estimate the dissolution rate in real systems We find that, at late times, the dissolution flux decreases relative to early times as the flow of unsaturated water to the CO2 source becomes constrained by a lateral exchange flow though the reservoir Application of the models to several representative reservoirs indicates that dissolution is strongly affected by the reservoir properties; however, we find that reservoirs with high permeabilities (k > 1 Darcy) that are tens of metres thick and several kilometres wide could potentially dissolve hundreds of megatons of CO2 in tens of years

A Study of Stress Change and Fault Slip in Producing Gas Reservoirs Overlain by Elastic and Viscoelastic Caprocks

Abstract: Geomechanical simulations were conducted to study the effects of reservoir depletion on the stability of internal and boundary faults in gas reservoirs overlain by elastic and viscoelastic salt caprocks. The numerical models were of a disk-shaped gas reservoir with idealized geometry; they mimic the structure of a gas field in the northern Netherlands which has experienced induced seismicity during gas production. The geomechanical simulations identified the area of the internal fault most sensitive to fault reactivation as coinciding with the epicenters of the largest seismic events associated with gas production. Depletion-induced shear slip is initiated at the depth of the reservoir, in the fault areas where the vertical fault throw ranges between 0.5 and 1.5 times the reservoir thickness. The extent of reactivated area differs depending on whether the caprock is viscoelastic or elastic: when it is viscoelastic, there is more down-dip shear displacement. High initial horizontal stresses in the rock salt and lower stresses in the elastic side-seal and the reservoir promote unloading of the internal and reservoir-bounding faults even before the reservoir is depleted. Particularly prone to fault reactivation are the fault zones along the interface between the reservoir rock and the salt caprock, which may already be critically stressed before depletion and are likely to be reactivated early during gas production. Stress relaxation and associated geomechanical changes affecting fault stability and ground surface deformation may continue long after production has ceased, due to the viscous behavior of the salt.

A review of permo‐triassic reservoir rocks in the zagros area, sw iran: influence of the qatar‐fars arch

Abstract: Four “supergiant” and numerous giant gasfields have been discovered in the Zagros area of SW Iran. The gasfields are concentrated in the eastern part of the foldbelt, in Fars Province and the adjacent offshore, and produce from Permo-Triassic carbonates equivalent to the Khuff Formation. The carbonates belong to the upper member of the Dalan Formation and the overlying Kangan Formation. Reservoir rock quality is strongly influenced by tectonic setting and depositional environment, and also by diagenesis. The highest quality reservoirs occur in oolitic shoal facies; fracturing (especially in onshore fields) and dolomitisation (in offshore fields) have also influenced reservoir quality. Anhydrite plugging is common in reservoirs in offshore fields, while calcite cementation is dominant in onshore reservoirs. Facies variations in the Dalan-Kangan Formations appear to correspond to syndepositional palaeohighs and depocentres. In the Eastern Zagros (Fars area), thickening of the Dalan Formation corresponds to a Mid-Late Permian depocentre referred to here as the Permian Fars Basin. As a result of sea level fall, this depocentre evolved into a hypersaline lagoon with evaporite deposition (Nar Member). In the Triassic, the depocentre evolved into a palaeohigh as indicated by thinning and facies changes in the Kangan Formation. The results of this study draw attention to variations in the reservoir quality of the Dalan-Kangan Formations. Much of this variation was due to the influence of the Qatar-Fars Arch.

Fundamentals of Petroleum Geology

Abstract: Origin of petroleum begins with the formation of organic matter, burial of organic matter in a basin maturation of the organic content with pressure temperature at burial depths. Petroleum system includes source rocks, reservoir rocks, reservoir traps, migration paths, seals etc. Hydrocarbons mature in source rocks migrate into reservoirs. Reservoir rocks are containers of hydrocarbons with sufficient interconnected pore spaces, these are sedimentary rocks clastic (sandstone shale), carbonate rocks. Migration pathways for matured hydrocarbons- migration is in separate phases from higher potential to a lower potential, from deepest to the shallowest. The hydrocarbons migrate into different types of petroleum traps such as anticlinal, fault, salt related stratigraphic traps. Reservoir seals are rocks with low permeability drapes hydrocarbons traps to ensure that entrapped fluids do not escape. Integration of disciplines geology, geophysics, petrophysics, is the key to predicting reservoir geometry, volume, in assessment of reserves.

Power transmission device

Abstract: A power transmission device includes a partition wall dividing an oil reservoir into a first oil reservoir in which a final gear is accommodated and a second oil reservoir in which the final gear is not accommodated, an oil passage passing a lubrication oil to a bearing of a rotor shaft, to a bearing of an input shaft and to a reduction mechanism, an oil pump connected to the oil passage via an outlet port, and communicated with the second oil reservoir via an inlet port, a third oil reservoir provided at a position lower than the rotor shaft and receiving the lubrication oil at a position upper than the second oil reservoir, and a gutter-shaped member tilted so as to communicate with the third oil reservoir at an upper end and the second oil reservoir at an lower end, and crossing through or over the partition wall.

Petrophysics of lower cretaceous platform carbonate outcrops in provence (se france): implications for carbonate reservoir characterisation

Abstract: High resolution petrophysical analyses were carried out on Urgonian (Lower Cretaceous) carbonates from outcrops in Provence, SE France. Porosity and permeability were measured on 541 plug samples selected from grain-supported carbonates analogous to those in the age-equivalent Shu'aiba and Kharaib Formation reservoirs in the eastern Arabian Plate. The sampling strategy allowed property heterogeneities from centimetre to kilometre scales to be investigated, as well as correlations between porosity and permeability in several different reservoir rock types. Property spatial modelling sensitivity analyses were also undertaken. The relative abundance of microporosity, grain size and sedimentary-diagenetic anisotropy were the main geological parameters which controlled the petrophysical characteristics of the grainstones studied. Increasing microporosity decreased permeability but resulted in an increase in the homogeneity of the reservoir rocks and therefore in their predictability. An increase in grain size, from fine sand to gravel, and in the amount of intergranular pores, enhanced permeability significantly but resulted in a decrease in the homogeneity (and therefore predictability) of the reservoir rock. At a plug scale, poro-perm relationships are very good and can be used predictively for fine grainstones dominated by microporosity; but relationships are moderate to weak for coarse rudstones with mixed pore types, including intraskeletal pores. In grainstone units, weak sedimentary anisotropy, such as decametre-scale cross-bedding, did not prevent the prediction of the horizontal property distribution from vertical data over a few hundreds of metres. In these units, the lateral correlation of rock properties follows periodic variograms with a 7 m wavelength. The lateral distribution of properties in coarse-grained and heterogeneous rudstones with complex pore types and intense sedimentary heterogeneities, such as channel structures, was however more difficult to predict from a vertical data set. Upscaling poroperm data from plug scale to reservoir scale is linear in the case of grainstones with intergranular microporosity, but is non-linear in the case of skeletal rudstones with coarser pore types including skeletal porosity.

Exploration Potential and Geological Conditions of Tight Oil in the Qaidam Basin

Abstract: There are geological conditions for the formation of tight oil in the Qaidam basin.The Middle and Lower Jurrasic semi-deep lacustrine facies mudstone and the Tertiary semi-deep lake facies to deep lake facies mudstone are widely distributed in the Qaidam basin,which constitutes a favorable relationship of source and reservoir coexistence for the formation of tight oil with bank to shallow lake facies sand body or carbonate rock which is interbeded with or situated near the source rocks.The Jurassic source rocks in the northern margin of the Qaidam basin have an average organic carbon value of 1.85,Ⅰ-Ⅱ2 organic types and a maturity range from mature stage to over mature stage with better oil generation potential.The Tertiary source rocks in the west of the Qaidam basin have a range of organic carbon from 0.4%to 1.2%,Ⅰ-Ⅱ1 organic types and a Ro value from 0.4% to 1.2% within an oil generation window.Compared to other Chinese basins,the degree of hydrocarbon inversion of the Tertiary source rocks is high.The clastic reservoir space is dominated by remained intergranular pores and corroded pores with porosity from 3.8% to 10.2% and permeability from 0.1×10-3μm2 to 2×10-3μm2.The reservoir rocks have characteristics of thinner single beds,vertical multilayer's superimposition,thicker accumulated thickness and many horizontal oil beds overlayed.The reservoir space of the carbonate rock is predominated by corroded pores and interbeded contracted cracks with porosity from 5% to 7% and permeability from 0.2×10-3μm2 to 0.7 ×10-3μm2.The reservoir rock is characterized by more single beds,thinner single beds,more sedimentary facies controlled and horizontal widely continuous oil beds.The groups of oil reservoir formation include four types,that is,inner source included group,upper source widely distributed model,lower source layered group,and beside source covered group,which are mainly controlled by source depressions.The tight oil in the Qaidam basin is enriched and has a great potential,being estimated the resource yield ranges from 8.16 to 10.46×108 Tons.After the analysis of reservoir forming conditions,we think that four favorable exploration areas,i.e.,Zhahaquan-Wunan,Xiaoliangshan-Nanyishan and Qigequan-Yaojin in the western Qaidam basin and Lenghu in the northern Qaidam basin,can be served as current exploration targets.

Structural development of the northern Sinai, Egypt and it's implications on the hydrocarbon prospectivity of the Mesozoic.

Abstract: The Sinai Peninsula is defined by the tensional Gulf of Suez rift to the west, the left-lateral Dead Sea - Gulf of Aqaba rift to the east, and the Mediterranean passive trailing margin to the north. Wrench tectonics, culminating in the Late Cretaceous (Laramide), has long been proposed as the dominant structural force in the Sinai; however, much evidence exists to suggest that north-south to northwest-southeast compression associated with the Late Cretaceous Syrian Arc tectonic event resulted in deformation which is dominantly compressive in nature, including thin-skinned thrusts, detached box-folded packages, southward-verging asymmetric folds, overturned beds, and basement-involved forced folds. The structural evolution of the Sinai was extremely complex, with most structures having formed from a mix of compressional and right-lateral shear forces, commonly superimposed on an earlier structural fabric of extensional and/or strike-slip origin. In general, the more northern structures are increasingly compressional while the influence of wrenching increases to the south. Recent geochemical and fluid inclusion analyses from the Halal-1 and Fallig-1 wells and three Gebel Maghara coal mine boreholes document two rich gas-to mixed oil and gas-prone Jurassic source rocks. The source interval, previously unidentified in the Sinai, correlates to the Middle Jurassic-Khatatba Formation in Egypt's northern Western Desert, where numerous recent self-sourcing, self-sealing gas/condensate discoveries have been made. The presence of adequate source and reservoir rock along with the presence of numerous large structures expressed in the surface, provide several of the main elements required for a hydrocarbon play. Depth of burial/migration and seal/trap remain unproven; however, these should all be present in the northernmost Sinai.

Control of Cambrian evaporites on fracturing in fault-related anticlines in the Zagros fold-and-thrust belt

Abstract: Orientation and distribution of fractures in the Oligocene–Early Miocene Asmari Formation (a major reservoir rock of the Zagros petroleum system) were investigated in two anticlines of the Zagros fold-and-thrust belt. The Sim and Kuh-e-Asmari anticlines developed in the areas of the Zagros characterized by the occurrence and absence of Cambrian evaporites at the bottom of the stratigraphic pile, respectively. The aim was to outline major differences in terms of fracture spacing and saturation. Organic matter maturity and clay minerals-based geothermometers suggest that the depth of deformation for the top of the Asmari Formation in the Kuh-e-Asmari anticline was in the range of 1.5–2.7 km assuming a geothermal gradient of 22.5 °C/km. The Asmari Formation in the Sim anticline probably experienced a slightly deeper sedimentary burial (maximum 3 km) with a geothermal gradient of 20 °C/km. The spacing of fractures is generally 2–3 times larger (i.e., strain accommodated by fracturing is smaller) in the Sim anticline than in the Kuh-e-Asmari anticline. This is consistent with regional geological studies, analogue, and numerical models that suggest that thrust faults geometry and related folds are markedly different in the absence or presence of a weak decollement (evaporites). The larger spacing in the Sim anticline is also consistent with higher temperature predicted for the Asmari Formation in this area. By contrast, the orientation of fractures with respect to the fold axes is the same in both anticlines. The fracture systems are rather immature in both anticlines. The amount and density of fractures in the twofolds are controlled by regional (occurrence/absence of salt and probably different burial), rather than local features (fold geometry).

Wettability Alteration of a Heavy Oil/Brine/Carbonate System with Temperature

Abstract: The wettability of reservoir rock is a crucial factor controlling displacement efficiency and ultimate oil recovery. In this study, the wettability of carbonate reservoir rocks as a function of temperature has been studied by measuring the Amott index to water using an X-ray computed tomography (CT) scanner. The cores for the Amott test were carefully prepared and aged at reservoir conditions to achieve restoration of reservoir wettability. The reservoir cores contain dolomite and chert based on the results of Fourier transform infrared spectroscopy (FT-IR) and energy dispersive X-ray spectroscopy (EDS). The porosity, permeability, and saturation profiles were measured with a core-flooding system and an X-ray CT scanner. The wettability test was carried out at reservoir temperature (70–80 °C) and elevated temperatures (130 °C, 170 °C). The rock components were dissolved at elevated temperature (170 °C) and resulted in a slight increase of porosity and absolute permeability. Also, OOIP and Amott water inde...

Integration of rock typing methods for carbonate reservoir characterization

Abstract: Reservoir rock typing is the most important part of all reservoir modelling. For integrated reservoir rock typing, static and dynamic properties need to be combined, but sometimes these two are incompatible. The failure is due to the misunderstanding of the crucial parameters that control the dynamic behaviour of the reservoir rock and thus selecting inappropriate methods for defining static rock types. In this study, rock types were defined by combining the SCAL data with the rock properties, particularly rock fabric and pore types. First, air-displacing-water capillary pressure curues were classified because they are representative of fluid saturation and behaviour under capillary forces. Next the most important rock properties which control the fluid flow and saturation behaviour (rock fabric and pore types) were combined with defined classes. Corresponding petrophysical properties were also attributed to reservoir rock types and eventually, defined rock types were compared with relative permeability curves. This study focused on representing the importance of the pore system, specifically pore types in fluid saturation and entrapment in the reservoir rock. The most common tests in static rock typing, such as electrofacies analysis and porosity–permeability correlation, were carried out and the results indicate that these are not appropriate approaches for reservoir rock typing in carbonate reservoirs with a complicated pore system.

Porosity and Permeability Prediction Based on Computational Intelligences as Artificial Neural Networks (ANNs) and Adaptive Neuro-Fuzzy Inference Systems (ANFIS) in Southern Carbonate Reservoir of Iran

Abstract: Reservoir characterization is a hard-to-do task because of the extremely heterogeneous nature of petroleum bearing formations. Studying different sources of data obtained from underground formations shows that abrupt changes in reservoir rock properties are very commonplace, especially in carbonate formations. Overcoming heterogeneity of reservoir is seemed to be impossible at least with current practices. In addition, obtaining reliable data from every foot for all wells is not feasible because of its high cost as well as being very time-consuming. Porosity and permeability distribution are essential reservoir rock properties to be determined in order to build a reservoir model with acceptable accuracy. Analyzing well test and core data are two reliable sources of porosity and permeability determination. Due to the additional time and cost, coring from all points of formation is not feasible. Therefore another way of defining porosity and permeability distribution should be sought in which a more availab...

Method and device for recovering oil and gas reservoir rock mechanics underground in-situ model

Abstract: The invention provides a method and a device for recovering an oil and gas reservoir rock mechanics underground in-situ model. The method comprises the following steps of: measuring rock mechanics parameters of an oil and gas reservoir; counting rock mechanics property influence parameters of the oil and gas reservoir; calculating the anisotropy strength of the rock mechanics parameters; obtaining a correlation between the rock mechanics parameters and the rock mechanics property influence parameters of the oil and gas reservoir; obtaining a correlation between the rock mechanics property influence parameters and the anisotropy strength; and recovering the oil and gas reservoir rock mechanics underground in-situ model by adopting the rock mechanics parameters, the anisotropy strength of the rock mechanics parameters, the correlation between the rock mechanics parameters and the rock mechanics property influence parameters of the oil and gas reservoir and the correlation of the rock mechanics property influence parameters and the anisotropy strength. By the method, the effectiveness and the accuracy for recovering the oil and gas reservoir rock mechanics underground in-situ model can be improved.

Fault-Fracture Networks and Related Fluid Flow and Sealing, Brushy Canyon Formation, West Texas

Abstract: We describe fault-fracture networks and associated cementation in excellent three-dimensional exposures of the Permian Brushy Canyon Formation in the central Delaware Mountains of west Texas. Faults and fractures are present in two main, nearly orthogonal sets (NNW and NE trending). A third set is present adjacent to some faults, or between two closely-spaced faults. Spacing of fault-parallel fractures decreases near some faults, in some cases parabolically. Fault core zones contain banded carbonate veins, complex breccias with banded vein clasts, and hydrocarbon material. Fault damage zones contain carbonate veins, and iron oxide and carbonate matrix alteration. These features are interpreted to record a complex history of slip, multiple fluid flow events and multiple cementation events along the fault-fracture network. Outcrop velocity probe data and porosity data suggest that matrix cementation halos have formed around the faults. The width of such halos controls the effectiveness of fault seals and the volume of reservoir rock that may be damaged by porosity occlusion. Fracture orientation and spacing are dissimilar in the hanging wall vs. footwall of some faults, suggesting that cementation-related fault sealing and reservoir damage may be asymmetric around such faults. Fracture-fault networks thus focused fluid flow at times, and were seals at times. In analogous reservoirs, open fractures would allow fracture-assisted production, and sealed fractures would compartmentalize the reservoir into semi-independent production zones.

Method and device for correcting dynamic and static rock mechanical parameters

Abstract: The invention provides a method and a device for correcting dynamic and static rock mechanical parameters The method includes: measuring rock mechanical parameters of a hydrocarbon reservoir; performing statistics on influencing parameters of rock mechanical properties of the hydrocarbon reservoir; acquiring correlations between the rock mechanical parameters of the hydrocarbon reservoir and the influencing parameters of the rock mechanical properties of the hydrocarbon reservoir; and recovering a hydrocarbon reservoir rock mechanical underground in-suit model, according to the rock mechanical parameters and the correlations between the rock mechanical parameters of the hydrocarbon reservoir and the influencing parameters of the rock mechanical properties of the hydrocarbon reservoir The method and the device can increase the validity and the accuracy of the recovery of the hydrocarbon reservoir rock mechanical underground in-suit model

Experimental investigations of variations in petrophysical rock properties due to carbon dioxide flooding in oil heterogeneous low permeability carbonate reservoirs

Abstract: Carbon dioxide has been successfully applied worldwide as an enhanced oil recovery process. Several important factors still have not been studied thoroughly. Therefore, this experimental study was carried out to investigate the variations in petrophysical reservoir rock properties of oil heterogeneous low permeability carbonate reservoirs. The main objectives of this experimental study are to investigate the effects of CO2 injection in tight limestone reservoir rocks on porosity, absolute and relative permeability, oil–water interfacial tension (IFT), reflective index, and reservoir water shielding phenomenon. Actual rock and fluid samples from an oil field in Abu Dhabi, UAE, are used to conduct this study at similar reservoir conditions of 4,000 psia and 250 °F. Oil recovery, permeability, porosity, and relative permeability were measured before and after the supercritical carbon dioxide (SC-CO2) flood to examine the effects of SC-CO2 flood on the variation in different oil and rock properties of tight composite limestone reservoir rocks. Detailed compositional analysis of initial and produced oil samples of core flood experiments were analyzed using gas chromatography to assess the mechanism of CO2 improved oil recovery. The results indicated that the application of SC-CO2 flooding under secondary and tertiary modes reduces porosity and permeability, alters relative permeability to a more water-wet condition, and reduces the oil/water IFT as a function of pore volume injected. Furthermore, the extracted components of the crude oil were also proven to be a function of injected CO2 pore volume. The applications of the attained results of this study provide much better understanding of different variation occurring in oil reservoirs under SC-CO2 injection and can be used effectively to validate and improve numerical simulation studies.

Thermal Shock in Reservoir Rock Enhances the Hydraulic Fracturing of Gas Shales

Abstract: prohibited. Summary Thermal shock occurs when a material’s temperature is changed over a short period of time such that constituent parts of the material deform by different amounts. The deformation of material due to thermal load can be manifested through strain and stress. As the temperature diffuses from hydraulic fracture into reservoir, the temperature changes with x coordinate and the stress/strain can be obtained from the Equation (6). Once the stress at any point exceeds the strength of material, the body fails in one of the three modes of tension, compression or shear. A thermal load on rock, results in the creation and extension of cracks, crushing the grains, or sliding the grain interfaces. In this paper we look into the possibility of stimulating the rock matrix beyond hydraulic fracturing stimulation by cooling down the rock. The physics of temperature reduction in a solid dictates that when a solid is laterally fixed and undergoes temperature reduction, a thermal stress gradient is induced in the solid body. In rock, this thermal stress gradient leads to a differential contraction of the rock, which in turn creates openings, referred to as thermal cracks. We numerically solve the nonlinear gas diffusivity equation, using finite element method and show that the thermal cracks in rock have the potential to improve the productivity of wells placed in tight formations by 20%.

Analytical method of sandstone diagenetic process and pore evolution

Abstract: The present invention relates to an analytical method of a sandstone diagenetic process and pore evolution. The method comprises the steps of: (1) detecting reservoir rock composition parameters, reservoir diagenetic fluid characteristic parameters, regional characteristic parameters and burial manners of a simulated region; (2) proportioning sandy mixed samples, muddy samples and diagenetic fluids for simulation according to the detection results in step (1); (3) placing the samples prepared in the step (2) in a reservoir diagenetic simulation device; (4) conducting simulation experiments; and (5) performing reservoir microscopic characteristic analysis for obtained simulation diagenetic samples, wherein the analysis includes: rock thin section authentication, rock sample scanning electron microscope analysis, X-ray diffraction quantitative analysis for the total amount of clay minerals in sedimentary rocks and common non-clay minerals, and analysis and evaluation of reservoir diagenetic evolution process based on results.