Development Of Hydrocarbon Reservoirs Research Articles

Modeling of cryogenic cracking behavior of tight sandstone under confinement

Stimulation is a must for commercial development of tight sandstone hydrocarbon reservoirs. Cryogenic fracturing using liquid nitrogen (LN) is a promising clean technique for efficiently stimulating reservoir rocks given its waterless nature. We developed a fully coupled thermo-mechanical (TM) model that incorporates strain-based damage theory for simulating LN cryogenic cracking in tight sandstone. Particularly, the compressive and tensile strengths, Young’s modulus, and thermal expansion coefficients and conductivity are designated as dynamic functions of the damage variable during the TM coupling process. Then the initiation, propagation, and cessation of multiple cracks from a borehole within a 2D heterogeneous tight sandstone plate were systematically scrutinized. Cryogenic cracks are found to emerge in short and long forms. In accordance with experiments, multiple long cracks emanate radially from the borehole along the maximum horizontal stress direction. In the investigated parameter ranges, the fracture morphology, including numbers, lengths, and coverage, is susceptible to changes in in-situ stress, Young's modulus, and thermal conductivity, but relatively insensitive to the variations of heat transfer coefficient and sandstone density. These results deepen our understanding of cryogenic shock on tight sandstone and provide a theoretical reference for designing cryogenic treatment operations.

A rheophysical study of the non-newtonian behavior of water flow in thin channels

The development of low-permeable hydrocarbon reservoirs is becoming an increasingly urgent task, and therefore, the study of the laws of fluid movement in subcapillary pores and microcracks is a crucial scientific and technical problem. The previous experimental studies revealed that a viscous liquid during flow in low-permeable reservoirs exhibits an anomalous non-Newtonian character, accompanied by a violation of the linearity of the filtration process, and, consequently, Darcy's law. It was also established that starting from a certain critical size of the opening of the crack, the flow of a Newtonian fluid (water, viscous oil) becomes non-Newtonian, with the manifestation of an initial pressure gradient and flow locking. In this research work, rheophysical aspects of the non-Newtonian behavior of water during flow in thin rectangular channels are considered experimentally. Using the microchannel model, it is established that the nonlinear rheological effect in the flow of water in micro-slits is mainly caused by the value of the electrokinetic potential of the system, by reducing of which it is possible to significantly weaken the non-Newtonian nature of the fluid. To regulate the electrokinetic potential of the fluid system, an antistatic additive was used, the optimal concentration of which was established experimentally. The optimal concentration is defined to be 0.006 %. Based on the Bingham model, the rheological parameters of water flow were estimated at different micro-slit clearances changed in the range of 10÷25 micrometers, in the absence and presence of an antistatic additive. It is also established that a reduction in the electrical potential of the fluid flow leads to a significant decrease in the yield shear stress during the flow of water in the microchannel

An Innovative Experimental Methodology for Testing Anisotropic Permeabilities of Formation Rocks

Abstract The permeability of reservoir rocks is a typical anisotropic property. Accurate testing and characterization of reservoir in situ anisotropic permeability is crucial for geo-energy applications including geothermal energy extraction, hydrocarbon reservoir development, coalbed methane production, and carbon dioxide geological sequestration. In this work, a novel experimental apparatus was designed to more precisely determine the permeability tensor of reservoir rocks. The device can independently apply stresses in different directions to simulate in situ reservoir stress conditions and reservoir temperatures. The experiment can accurately measure the principal components of the permeability tensor in three directions for rock samples while effectively avoiding experimental errors caused by internal structure damage during disassembly. Using the self-developed apparatus, anisotropic permeability tests were conducted on sandstone, shale, and coal samples. The results show that the three-dimensional permeability of rock samples under in situ reservoir stress conditions is lower than under isotropic stress conditions. However, the variation magnitude of the three-dimensional permeability differs between the three rock types because of lithological differences. This confirms the difference in data between the proposed anisotropic permeability test method and other traditional methods. We also observed that for rocks without distinct oriented internal structures like sandstone, anisotropic permeability is more sensitive to (normal) stress changes. In contrast, for rocks with oriented pore structures such as shale and coal, the degree of anisotropic permeability is less sensitive to (normal) stress changes. The proposed novel anisotropic permeability test method obtains more accurate and realistic data under simulated in situ stress conditions compared with existing methods. It can evaluate rock properties and optimize geothermal or hydrocarbon production well designs to improve production efficiency.

A multidisciplinary approach to facies evaluation at regional level using well log analysis, machine learning, and statistical methods

Geological facies evaluation is crucial for the exploration and development of hydrocarbon reservoirs. To achieve accurate predictions of litho-facies in wells, a multidisciplinary approach using well log analysis, machine learning, and statistical methods was proposed for the Lower Indus Basin. The study utilized five supervised machine learning techniques, including Random Forest (FR), Support Vector Machine (SVM), Artificial Neural Network (ANN), Extreme Gradient Boosting (XGB), and Multilayer Perceptron (MLP), to analyse gamma ray, resistivity, density, neutron porosity, acoustic, and photoelectric factor logs. The Concentration-Number (C-N) fractal model approach and log–log plots were also used to define geothermal features. In a study on machine learning models for classifying different rock types in the Sawan field of the Southern Indus Basin, it was discovered that sand (fine, medium and coarse) facies were most accurately classified (87–94%), followed by shale (70–85%) and siltstone facies (65–79%). The accuracy of the machine learning models was assessed using various statistical metrics, such as precision, recall, F1 score, and ROC curve. The study found that all five machine learning methods successfully predicted different litho-facies in the Lower Indus Basin. In particular, sand facies were most accurately classified, followed by shale and siltstone facies. The multilayer perceptron method performed the best overall. This multidisciplinary approach has the potential to save time and costs associated with traditional core analysis methods and enhance the efficiency of hydrocarbon exploration and development.

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Linking the sedimentary cyclicity with mechanical and physical properties of limestone and marl rocks, Dam Formation, Eastern Saudi Arabia: Implications for hydrocarbon exploration and reservoir development

Diagenesis and reservoir quality of Neoproterozoic dolomitized microbialites following multi-stage diagenetic fluid activity: a case study of the Sinian Dengying Formation, China

Neoproterozoic marine microbialites have been targets for exploration and hydrocarbon reservoir development. The original depositional fabric and diagenesis control the pore systems of microbialites, leading to the complicated origin of microbialite reservoirs. This study aimed to reveal the origin of microbialite reservoirs following multi-stage diagenetic fluid activity in the fourth Member of the Dengying Formation in the central Sichuan Basin in southwestern China. The fourth Member of the Sinian Dengying Formation developed dolomitized microbialites, mainly including stromatolites, laminates, and thrombolites. Based on the background of tectonic movement, petrology and geochemistry examinations were executed to analyze the origin of the microbialite reservoir. Based on the cathodoluminescence and the homogenization temperature of the brine inclusions, it is credible that there were four stages of diagenetic fluid activities in the burial diagenesis. In the first stage, the microbialite reservoir was charged by oil in the Silurian period, with evidence from residual asphalt around the pores. In the second stage, dolomite precipitated to incompletely fill the pore spaces. In the third stage, the silica-rich diagenetic fluid with high temperature resulted in the precipitation of authigenic quartz. In the last stage, the oil charged again during the Triassic period, followed by siliceous filling, with residual asphalt filling the pore spaces. There were two stages of subaerial emergence, which occurred in two episodes of the Sinian-Early Cambrian Tongwan movement. The evidence for the two tectonic events includes two phases of dolomites with meteoric water origin, two cycles of V, Sr, and Na element profiles, two instances of negative excursion δ18O isotope, and two cavity layers. By comparison, the karstification of reservoirs in the Tongwan III episode could generate a higher quality of reservoir than that in the Tongwan II episode. As a result, the quality of the microbialite reservoir from the fourth Member of the Dengying Formation was mainly improved by the subaerial exposure in the Tongwan III episode and then was partly destroyed by the siliceous filling. The identification of multi-staged diagenetic fluid charging can illustrate the evolution of the reservoir quality of Neoproterozoic microbialites.

Laboratory evaluation on oil-soluble resin as selective water shut-off agent in water control fracturing for low-permeability hydrocarbon reservoirs with bottom aquifer

During the development of low-permeability hydrocarbon reservoirs with bottom aquifer, hydraulic fracturing is essentially employed for commercial oil flow while increasing the potential risk of serious water production, thus water control hydraulic fracturing technology plays important role on addressing this challenge. In this work, a water control fracturing technique is developed to integrate fracture height containment with selective water shut-off. Specifically, oil-soluble resin is used as selective water shut-off agent and is injected with sinking agent simultaneously, carried by fracturing fluid at the fracture generation stage, to establish an improved artificial barrier. Afterwards, a modified fracture conductivity test equipment is designed and manufactured to measure the selective conductivity of the artificial barrier, its sensitivity to temperature, ratio of oil-soluble resin to sinking agent, two-phase flow are studied to evaluate the capability of selective water shut-off.The results demonstrated that 1) the occupation in porous space of sinking agent (0.212–0.425 mm) and the status change from glassy state to high elastic state of oil-soluble resin are mainly responsible for water shut-off; 2) The ratio of oil-soluble resin to sinking agent in 10 g: 70 g and temperature at 75 °C are two critical value to significantly reduce water conductivity in our experiments; 3) Fast dissolution of resin in oil results in oil conductivity over 5 to 100 times higher than water conductivity to achieve selective water shut-off. The results presented herein will provide important guidance on water control in low permeability reservoirs with active bottom aquifer and will promote the unconventional hydrocarbon recovery.

A Hybrid Oil Production Prediction Model Based on Artificial Intelligence Technology

Oil production prediction plays a significant role in designing programs for hydrocarbon reservoir development, adjusting production operations and making decisions. The prediction accuracy of oil production based on single methods is limited since more and more unconventional reservoirs are being exploited. Artificial intelligence technology and data decomposition are widely implemented in multi-step forecasting strategies. In this study, a hybrid prediction model was proposed based on two-stage decomposition, sample entropy reconstruction and long short-term memory neural network (LSTM) forecasts. The original oil production data were decomposed into several intrinsic mode functions (IMFs) by complete ensemble empirical mode decomposition with adaptive noise (CEEMDAN); then these IMFs with different sample entropy (SE) values were reconstructed based on subsequence reconstruction rules that determine the appropriate reconstruction numbers and modes. Following that, the highest-frequency reconstructed IMF was preferred to be decomposed again by variational mode decomposition (VMD), and subsequences of the secondary decomposition and the remaining reconstructed IMFs were fed into the corresponding LSTM predictors based on a hybrid architecture for forecasting. Finally, the prediction values of each subseries were integrated to achieve the result. The proposed model makes predictions for the well production rate of the JinLong volcanic reservoir, and comparative experiments show that it has higher forecasting accuracy than other methods, making it recognized as a potential approach for evaluating reservoirs and guiding oilfield management.

Production-induced pressure-depletion and stress anisotropy changes near hydraulically fractured wells: Implications for intra-well fracture interference and fracturing treatment efficacy

This study investigates the changes in the principal stress trajectories during development of hydrocarbon (and/or geothermal) reservoirs with hydraulically fractured wells. Our analysis indicates four phases in the well-life with typical stress states, i.e., Pre-fracturing Phase (Stress State 0): the natural stress state prior to the drilling intervention; Fracturing Phase (Stress State 1): stress state prevailing during fracturing treatment; Flowback Phase (Stress State 2): stress state prevailing during flowback; and Production Phase (Stress State 3): stress state prevailing during production. The various stress changes are computed and visualized using the Linear Superposition Method (LSM). Two episodes of stress trajectory alterations occur, a first one during the Fracturing Phase (transition from Stress State 0 to 1), and a second one during the Flowback Phase (transition from Stress States 1 to 2), with respectively positive and negative fracture net pressures. During the Production Phase (Stress State 3), the spatial advance of the pressure depletion around the fractured well system due to production was modeled using recently developed Gaussian pressure transient equations. Our new results show that the early stress reversals (Stress State 1) near the pressured fractures during fracturing treatment are short-lived. In addition, the residual stress change magnitude during flowback (Stress State 2) depends on the final fracture-width aperture. In any case, the local stress reversals due to engineering interventions are a short-term phenomenon and remain limited to the near-fracture regions. The regions with the reversed stress will increase when more stages are fractured, assuming the elevated fracture pressure is not fully released before the next stage is completed. Subsequently, the stress anisotropy decreases during production as a result of pressure depletion. Our improved analysis of the stress reversal phenomenon is important for optimizing drilling plans for infill wells, and for improving fracturing treatment designs.

Информационно-статистический прогноз нефтегазоносности в краевой части Корякско-Камчатской складчатой области

The decomposition components of geopotential fields and their calculated transformants in the Kolpakovsky through zone with established oil and gas content (western coast of Kamchatka) were studied. Gravity and magnetic survey data identified structure-forming faults and basement ruptures. Studies were continued to establish the similarity of the studied fragment of the Pustoretsky Trough, located in the marginal part of the Koryak-Kamchatka folded region, with the «reference» Kolpakovsky sedimentary depression. Zones of structural-forming influence of the basement fault-block tectonics on the sedimentary cover are distinguished. Using probabilistic-statistical methods within the limits of the studied fragment the prognostic and geophysical scheme of regional prerequisites of oil and gas bearing capacity was made. The prediction of local prerequisites of oil and gas bearing capacity associated with buried highs and elevations of basement, as well as with small positive forms of its relief was carried out. Prognostic and geophysical schemes with overlapping of local prerequisites of oil and gas bearing capacity were compiled. Oil and gas prospective areas of possible development of hydrocarbon reservoirs were localized with high probabilities. The correlation between the predicted prerequisites of oil and gas local features of structural surfaces fixed by seismic data was established.

A novel hybrid model for hydraulic fracture simulation based on peridynamic theory and extended finite element method

The development of subsurface hydrocarbon reservoirs is highly dependent on hydraulic fracturing technology, and it is of great significance to use numerical simulation approaches to explore the propagation characteristics of hydraulic fractures. A novel hybrid model for investigating the hydraulic fracturing problem is proposed in this paper, wherein the crack segment is described using the extended finite element method (XFEM), and the region of the crack tip and potential fracture propagation is described using peridynamic (PD) theory. The fluid flow is governed by the continuity equation and the momentum equation, and the permeability in the fracture is calculated by the cubic law. The proposed model takes advantage of the small computational complexity of XFEM, and uses the stretch in the PD theory to determine whether the bond is broken, avoiding the need to obtain the stress intensity factor. The importance of the hybrid model is the coupling strategy for the transition region from XFEM to PD. Then the model is validated against two classic problems with available analytical solutions. The issue of hydraulic fractures intersecting natural fractures is also addressed. Meanwhile, the mesh size and the coupling region size is studied in this work. The model proposed in this paper is of benefit to provide a new perspective for numerical simulation of hydraulic fracture.

Joint inversion of the unified pore geometry of tight sandstones based on elastic and electrical properties

The prediction of the pore geometrical properties is important in the exploration and development of tight-sandstone hydrocarbon reservoirs. To investigate this topic, we have measured the porosity, permeability, P- and S-wave velocities, electrical conductivity, and axial and radial strains as a function of differential (confining minus pore) pressure of tight-sandstone samples, collected from the Zhongjiang gas field of Sichuan, in West China. The results show that the closure of cracks with pressure highly affects these properties. Then, we propose a multiphase reformulated differential effective-medium (R-DEM) model that employs the unified pore geometry (the same pores or cracks with different aspect ratios and volume fractions) for both elastic and electrical modeling. The model gives the pressure-dependence of the P- and S-wave velocities and electrical conductivity, and the experimental porosity and static moduli are used as constraints to estimate the pore geometry. The model describes the elastic properties of sandstones saturated with nitrogen gas, and the electrical conductivity when the pore fluid is brine. The prediction of the wet-rock S-wave velocities is less accurate, due to the presence of shear stiffening and weakening effects. Furthermore, we compare the results with those of the joint elastic-electrical inversion by using the dynamic instead of the static stiffness modulus. The results show that the latter provides a better agreement between theory and experiment. Subsequently, we show that the pore geometry estimated from the elastic or the electrical measurements separately (unjoint inversion) present discrepancies, indicating that a joint inversion is required. The published experimental data are also used to illustrate the model, and the results are satisfactory.

The Control of Sea Level Change over the Development of Favorable Sand Bodies in the Pinghu Formation, Xihu Sag, East China Sea Shelf Basin

The Pinghu Formation consists primarily of marine-continental transitional deposits. The widely distributed fluvial and tidal transgressive sand bodies comprise the main reservoirs of the Baochu slope zone in the Xihu Sag in the East China Sea Shelf Basin. These sand bodies are deeply buried, laterally discontinuous, and are frequently interrupted by coal-bearing intervals, thereby making it extremely difficult for us to characterize their hydrocarbon potential quantitatively via seismic inversion techniques, such as multi-attribute seismic analysis and post-stack seismic inversion, hindering further hydrocarbon exploration in the Xihu Sag. Here, a prestack seismic inversion approach is applied to the regional seismic data to decipher the spatiotemporal distribution pattern of the sand bodies across the four sequences, i.e., SQ1, SQ2, SQ3, and SQ4, from bottom up, within the Pinghu Formation. In combination with detailed petrology, well log, and seismic facies analysis, the secular evolution of the sedimentary facies distribution pattern during the accumulation of the Pinghu Formation is derived from the sand body prediction results. It is concluded that the sedimentary facies and sand body distribution pattern rely on the interplay between the hydrodynamics of fluvial and tidal driving forces from the continent and open ocean, respectively. Drops in the sea level led to the gradual weakening of tidal driving forces and relative increases in riverine driving forces. The direction of the sand body distribution pattern evolves from NE–SW oriented to NW–SE oriented, and the dominant sand body changes from tidal facies to fluvial facies. In addition, the sea level drop led to the decrease in the water column salinity, redox condition, organic matter composition, and the development of coal seams, all of which directly influenced the quality of reservoir and source rocks. The sand bodies in SQ2 and SQ3 are favorable reservoirs in the Pinghu Formation due to their good reservoir properties and great thickness. The high-quality source rock in SQ1 could provide significant hydrocarbons and get preserved in the sand body within SQ2 and SQ3. This contribution provides an insight into the control of the sea level change over the development of hydrocarbon reservoirs in the petroleum system from marginal-marine environments such as the Xihu Sag.

Sequence Stratigraphy Variation and Its Implication in Shale Oil Exploration: A Case Study of the Eocene Dongying Depression, Eastern China

Organic matter (OM) and carbonate are the important organic and inorganic components, respectively, in the shales of the upper fourth member of the Eocene Shahejie Formation, Dongying Depression, Eastern China. Their enrichment affects the hydrocarbon generation capacity and reservoir development of shales. The development mechanism of sequence stratigraphy and the influence of sequence stratigraphy on OM enrichment and carbonate deposition are investigated in this study. Based on the petrological, mineralogical, and geochemical analyses, a third-order sequence is recognized, including the lowstand systems tract (LST), transgressive systems tract (TST), and highstand systems tract (HST). The total organic carbon (TOC) content is 0.11–9.05 wt% (average 2.2 wt%), and the carbonate content is 3–95 wt% (average 51 wt%). Organic matter and carbonate are enriched in TST and gradually reduced in HST and LST. The decrease in the relative lake level in LST results in the deposition of abundant siltstone, leading to both poor OM preservation and carbonate precipitation. The rapid rise in the relative lake level in TST may be triggered by marine transgression, promoting OM enrichment in terms of both production and preservation. Seawater input brought abundant Ca2+ and Mg2+, which facilitated the precipitation of carbonates. The enrichment of OM and carbonate improves the capacity of hydrocarbon generation and reservoir performance of shales in the TST. The decrease in the relative lake level in HST causes a slight increase in the terrigenous clastic content, which, on the one hand, accelerates the sedimentation rate and OM deposition and, on the other hand, reduces carbonate precipitation. This study not only explains the differential distribution of OM and carbonate but also helps to improve the accuracy of the evaluation of shale oil sweet spots.

Transition of seawater conditions favorable for development of microbial hydrocarbon source – Reservoir assemblage system in the Precambrian

Several commercial Precambrian petroleum systems have been discovered worldwide. The microorganisms found in the Precambrian successions play a significant role in the development of high-quality hydrocarbon source rocks and microbialites with a high reservoir porosity. Yet, it remains unclear regarding issue of environments in which microbial activities can lead to the development of organic-rich hydrocarbon source rocks or reservoirs, and how the microbial source rock and reservoir constitute an effective hydrocarbon source-reservoir assemblage system. During the Edicaran Doushantuo Formation period, high-quality black shale source rocks were widely developed, and the organic matter in the source rocks was mainly derived from microbes including bacteria and algae. The thickness of the source rocks is up to 200 m, and the total organic carbon (TOC) value is ∼ 17.9%. During the Dengying Formation period, thick-layered microbialites, including microbial stromatolite, thrombolite, and botryoidal dolomite were developed extensively, with the abundant primary framework and secondary dissolution pores. During the Precambrian evolution, the transition of the seawater environment controlled the development of microbial source rocks or microbialite reservoirs. In a deep, euxinic reducing seawater condition, microbial organic matter was well preserved and accumulated in fine-grain sediments, thus forming the high-quality microbial source rocks. Meanwhile, under such a reducing condition, a large amount of layered, nodular, granular, and strawberry pyrites were precipitated due to the effect of BSR reaction with extremely positive δ34S values (up to 39.0‰). Meanwhile, in a shallow turbulent high-energy oxidized seawater condition, especially in the intermittent “Dolomite Sea” environment, microbial dolomitization promoted the massive development of microbial dolomite mound/shoal frameworks, constituting the matrix for the development of large-scale microbialite reservoirs. During the later burial evolution processes, the oil and gas generated from the Doushantuo Formation source rocks migrated and accumulated into the overlying Dengying Formation microbialite reservoirs, which constituted an effective hydrocarbon source-reservoir assemblage system. Overall, the areas surrounding the Mianyang, west side of the Chengkou, and northwest side of the western Hubei troughs are considered to be the potentially favorable areas with microbial source rock-reservoir assemblage system. The microbial source-reservoir assemblages in these Precambrian strata worldwide are worth further exploring.

Depositional and structural controls on a fault‐related dolostone formation (Maestrat Basin, E Spain)

AbstractFault‐related dolomitisation is responsible for the development of numerous hydrocarbon reservoirs hosted in diagenetically‐altered carbonates and is therefore critical to hydrocarbon exploration, subsurface storage (i.e. CO2), the formation of associated mineralisation (i.e. MVT‐deposits) and for understanding the key controls on subsurface fluid flow. Multiple dolomitised outcrop analogues have been characterised in recent years, but uncertainty still remains as to the controls on dolomitisation in terms of dolostone geobody size and geometries, their distribution and how they impact reservoir quality. Late Tithonian shallow‐marine carbonates at Serra Esparreguera in the Maestrat Basin (E. Spain) were partially dolomitised on the seismic scale, resulting in a spectrum of geobodies with varying degrees of spatial connectivity. Dolostone predominantly replaces Polpís Fm wackestones and packstones, and bioclastic grainstones of the Bovalar Fm. Dolostone geobodies transition through vertical stratigraphy from being massive and spatially extensive to localised stratabound bodies as textural heterogeneity increases. Irregular dolostone geometries occur in the Polpís Fm, which is texturally homogenous relative to the overlying Bovalar Fm, cross‐cutting bedding in areas with high abundance of faults. Faults occur adjacent to dolostone and constrain its lateral extent across the outcrop. Dolomitisation fronts are typically sharp with morphologies affected by small‐scale faults and bedding‐parallel stylolites. Dolomitisation occurred under burial conditions and dolostones were later overprinted by phases of calcite and saddle dolomite cementation. The spatial distribution of dolostone is strongly influenced by the depositional heterogeneity and faults, while smaller structures (i.e. metre‐scale fractures and stylolites) and bedding surfaces controlled the dolomitisation front geometry. Dolostone geobodies at Serra Esparreguera provide new insights into the structural, depositional and diagenetic controls on dolomitisation at a seismic scale, which can be used as a predictive guide to improve the understanding of carbonate reservoirs with complex paragenetic histories.

Sedimentation of open-framework gravels in alluvial-fan settings: Quaternary Poplar Fan, northwest China

Open-framework gravels (OFGs) form common lithofacies of alluvial fans. However, inferences of their mechanisms of transport and deposition, and of controls on their distribution in alluvial-fan successions, remain difficult, limiting our ability to interpret the environmental significance of such deposits and to predict their distributions in ancient successions. From an applied standpoint, such predictions are important in the development of hydrocarbon reservoirs and remediation of aquifers hosted in alluvial-fan strata. To elucidate our understanding of formative conditions of different types of OFGs, a study has been undertaken on the Quaternary Poplar Fan, in the endorheic Heshituoluogai Basin, China.Based on observations from outcrops and trenches on the Poplar Fan, eight different types of OFGs are identified: these lithofacies types account for 7% of the total deposits of the fan. During high flow stages, OFGs are deposited in association with supercritical sheet-like flow (type 1), unconfined streamflow (type 2), and flow in groundwater-fed channels (type 3). During low flow stages, OFGs are associated with trough cross-stratification (type 4) and sigmoidal cross-stratification (type 5); these types occur over the entire fan. At the fan margins, OFGs are associated with gulleys (type 6), especially at the distal fan toe. Other OFG types are associated with bank collapse (type 7) or intercalated with aeolian deposits (type 8). A model is proposed to account for the distribution of different types of OFGs across the fan, wherein types 1, 2 and 4 seen in the medial fan are dominant. This provides a framework for the identification, prediction and correlation of OGFs in subsurface alluvial-fan successions.

Integration of Thermal Core Profiling and Scratch Testing for the Study of Unconventional Reservoirs

Core analysis provides the essential information necessary for the characterization and development of hydrocarbon reservoirs. High core-scale heterogeneity and anisotropy, natural in unconventional reservoirs, complicate reservoir characterization and dictate the sampling methodology used. Continuous high-resolution thermal measurements with an optical scanner and scratcher along the core column can yield benefits in a sampling strategy. This article describes some features of the suggested integration of non-destructive thermal profiling with partially destructive scratch testing applied for the study of rocks from the Bazhenov Formation (West Siberia, Russia). The spatial variation in the unconfined compressive strength and thermal conductivity components parallel and perpendicular to bedding for more than 1000 samples are demonstrated and discussed on core and log scales. The relationships between these properties are established for different rock types composing the formation. The joint analysis allows specialists to correctly define multiscale heterogeneities and facies that would be difficult or impossible to observe with logging data analysis or geological description alone. The established relationships make it possible to partially replace the semi-destructive scratch test with non-destructive optical scanning, providing UCS estimation. One more important outcome of the present work is the lessons learned regarding how to organize future works. The integration of thermal core profiling and scratch testing data looks promising for unconventional reservoir characterization.

Modeling In-situ tectonic stress state and maximum horizontal stress azimuth in the Central Algerian Sahara – A geomechanical study from El Agreb, El Gassi and Hassi Messaoud fields

Central Algerian Sahara hosts many prolific hydrocarbon accumulations in the Paleozoic successions. In this work a contemporary stress field of the Saharan platform has been evaluated using the dataset from recently drilled wells in El Agreb, El Gassi and Hassi Messaoud fields. A pore fluid pressure gradient of 0.56 PSI/feet is interpreted from the in-situ measurements in the Paleozoic reservoir units. Vertical stress (Sv) modeled from the bulk-density data indicates an average of 1.02 PSI/feet gradient. Rock elastic property-based approach is employed to model the magnitudes of minimum (Shmin) and maximum horizontal stress (SHmax) components, which were calibrated with leak off test/minifrac and breakout widths, respectively. Paleozoic stress profiles reveal Shmin/Sv range of 0.74–0.84, while SHmax/Sv varies between 1.1 and 1.33. Subsurface stress distribution indicates that the present-day stress field in the Saharan platform is principally strike-slip faulting (SHmax > Sv > Shmin). A cumulative 1490 m of B-D quality wellbore breakouts, inferred from the acoustic image logs, suggest a NW-SE/WNW-ESE SHmax orientation, which is parallel to the absolute African plate motion and Africa-Eurasia plate convergence direction, implying ridge push force to be the dominant contributor to the tectonic stress field. Mean SHmax orientation shows slightly anticlockwise rotation (126°N to 144°N) from south (El Agreb) to north (Hassi Messaoud field). Inferences are discussed regarding the fault slip potential and hydrocarbon reservoir development.

РЕШЕНИЕ ПРЯМОЙ ЗАДАЧИ ГРАВИРАЗВЕДКИ МЕТОДОМ ИМИТАЦИИ ОТЖИГА ДЛЯ ИНТЕРПРЕТАЦИИ ДАННЫХ ГРАВИМЕТРИЧЕСКОГО МОНИТОРИНГА СОСТОЯНИЯ НЕДР

The long-term development of hydrocarbon reservoirs (HCR) in the geological environment, complex deformation processes occur. Gravity monitoring is carried out to evaluate the possible geodynamic risk and negative consequences from HCR. As a result, the interrelationships of the continuously changing field-geological situation (changes in production volumes, changes in reservoir pressure, processes of fluid injection into productive formations) are investigated. The main tool for solving the gravity inversion when determining areas of increased industrial hazard is the solution of the gravity direct problem. In these studies, proceeding from a given initial approximation of the environment, the problem is realized through successive approximations. To assess such distributions, the authors of the article recommend using the simulated annealing technique within the framework of stochastic optimization. It is aimed at fitting the optimal parameters of the medium provided that a minimal residual of the gravity field values occurs. The approach is implemented using three simple mathematical models of the geological medium such as horizontal prism, homogeneous sphere, and vertical ledge. This technique allows fitting the media values simultaneously by a pair of its parameters. The operation of the algorithm is described and the simulation results are provided. The results showed acceptable accuracy of the algorithm for solving the direct gravity problem by the proposed method. The simulated annealing technique made it possible to increase the reliability of the HCR model while reduce the time for the analysis of the gravity field.