Bagum, MonuaraAhammad, Jalal M.Hossain, M. EnamulHusain, Tahir...
16页
查看更多>>摘要：Efficient and optimistic drilling operation depends on a number of parameters and drilling fluid (DF) additives is one of them. Traditional DF mud contains toxic chemical compound that causes environmental issue, cost optimization and reservoir formation damages. Present demands of DF and future challenges have urged researchers to develop eco-friendly drilling fluid additives with minimum impact on the environment. Aloe Vera does not contain any serious toxic compound compared to others DF additives; thus it is used in various cosmetic products. The present investigation leads toward the development of a drilling mud additive using Aloe Vera. The SEM-EDX method is conducted to the elemental analysis of Aloe Vera to investigate composite in it. In this research, the four representative recipes of the DF are formed with this additive along the base material bentonite. Complete rheological tests and filtration tests of the different concentrations of mud additives are performed to investigate the feasibility of this new additive. Rheological properties and other related investigations are carried out with different sizes of the sample particle and mud preparation formula. A comparative study is performed along with other additives with respect to rheological, environmental and economic benefit. This present investigation suggests Aloe Vera can be used as a potential DF additive that is environmental friendly instead of toxic chemicals. The investigation confirms the benefit of this new additive, which is environmental friendly. All the drilling purposes including hydrocarbon industries and mining companies can benefited from this newly developed DF additive.
Santos, AndersonScanavini, Helena F. A.Pedrini, HelioSchiozer, Denis Jose...
11页
查看更多>>摘要：The upscaling of geological properties is a fundamental requirement to construct a suitable simulation model since the geological model typically contains millions of cells, which makes it computationally difficult to simulate it on such a scale. The process consists of a scale transfer that adapts the petrophysical properties of a high-resolution grid to a coarser grid. Nevertheless, this is not a trivial operation, especially for absolute permeability, which is a non-additive property. One of the most reliable methods is to perform a flow simulation on fine-scale cells that correspond to the coarse block and derive the single permeability value that reflects the same flow value. Still, this is a very time-consuming method and depends on the imposed boundary conditions. This work aims to take advantage of recent advances in artificial intelligence to produce results with similar or better quality of flow-based methods, and more adaptive. It handles models with multiple geological realizations by employing machine learning to capture patterns from a subset of scenarios and use it to generalize for all others. The methodology is divided into two stages - local and global. In the first one, a deep neural network is trained with a fraction of geological realizations using the flow-based results as a reference. In the second stage, clustering analysis is employed along with a neural network optimization to learn an adjustment procedure for the coarse simulation model concerning the cumulative field production predicted by the fine model simulation. Afterward, the trained network performs the upscaling of remaining realizations, but more efficiently in terms of computational time and providing better output in terms of production and injection. The method was applied to a benchmark model and the experimental results demonstrate that the local technique was capable of reproducing very similar values to the flow-based upscaling using only one scenario in training and at the global stage the coarse model was improved even further matching the field oil production forecast of the fine model. Different scenarios were used for training and testing and the results were consistent showing no bias towards a specific configuration and capability of generalization to different scenarios. Ultimately, the proposed artificial intelligence approach performed an accurate upscaling, surpassing the reference approach with forecast production similar to the fine model, and also fast to compute when considering multiple geological realizations, since it reduces the required numerical simulations to a fraction of the total.
查看更多>>摘要：The application of nanomaterials in petroleum industry is becoming common. Nanofluids are used as the water phase in the process of water alternating gas injection. Previous studies mainly focused on the effect of nano particles on the pore throat properties of porous media or the effect of nanofluids on crude oil emulsification. However, in the process of water gas alternating displacement, the relative flow of water and gas affects the displacement front and gas breakthrough time. Therefore, it is significant to study the effect of nanoparticles on mass transfer at gas-liquid interface. Based on the good dispersion and unique physical properties of nano particles in the base solution, in the process of alternating injection of CO2 and water, water is used as the base solution and nanoparticles are added to form a uniformly dispersed nanofluid. In this study, the enhancement of mass transfer by nanoparticles at the gas-liquid interface was studied. The theoretical model of the micro mass transfer at the gas-liquid interface during the percolation of nanofluid and CO2 in porous media was deduced. Combined with the absorption experiment of CO2 mixture, the enhancement effect of nanoparticles on mass transfer process was verified. Different factors affecting CO2 absorption were also compared. The main fluids used in the experiment were deionized water, SiO2, TiO2 and Al2O3 nanofluids. The experimental results of different nanofluids show that TiO2 nanoparticles enhance the mass transfer most obviously, and SiO2 inhibits the mass transfer when the content exceeds a certain content. In addition, the optimum absorption concentrations of the three nanoparticles are in the range of 0.06-0.08 wt parts per thousand. Combined with the relative permeability experiment, the influence of nanoparticles on the law of gas-liquid relative permeability is further revealed. This experimental result provides a theoretical guidance for the application of nanoparticles in enhancing oil recovery.
查看更多>>摘要：Hydraulic fracturing is currently one of the most economical and effective means to develop shale oil resources. However, the fracturing effects in shale oil wells vary significantly. The compatibility between the fracturing fluid and the shale oil reservoir is one of the important factors affecting the fracturing stimulation. In this study, a series of physical simulation experiments were carried out to reveal the changes in the physical properties and surface properties of a shale oil reservoir using different fracturing fluids (guar gum fracturing fluid, slick hydraulic fracturing fluid, and formation water fracturing fluid). The dynamic flowback process of different fracturing fluids was visualized and quantitatively characterized using the NMR technology. The results indicate that with the increase in soaking time in the formation water fracturing fluid, the hysteresis coefficient of the shale increased. The increasing ink-bottle pores resulted in worse pore connectivity and physical properties of reservoir. The shale undergoes strong water sensitivity damage and strong stress sensitivity, which is not conducive to the stability and long-term effects of shale oil production. After injecting the guar gum fracturing fluid, the pore connectivity of the shale is enhanced, and the stress sensitivity is the weakest. The particle suspension and dispersion system of the guar gum fracturing fluid is the most stable, which greatly avoids reservoir damage caused by solid particle migration blocking in the pore throat. In addition, it can effectively inhibit shale hydration and expansion, and achieve the highest displacement flowback efficiency, which is more suitable for the fracturing operation of shale oil reservoirs in the study area. The effects of the slippery hydraulic fracturing fluid on shale are between the above two fracturing fluids. The research results are of great significance in guiding the fracturing operation of shale oil wells in the northern Songliao Basin.
查看更多>>摘要：Fracturing is a critical process affecting rock deformation and geofluid flow in underground engineering. However, previous studies coupled 3-D geomechanics and geofluids rarely considered the process of rock frac-ture in real time due to the lack of experimental apparatus. In this work, we present an auxiliary device for an existing true triaxial geological apparatus, with which we implanted AE modules into loading platens with grooved fluid channels, to better collect fracture-related acoustic emission signals and their locations. We minimize the end-friction effect in terms of the performance of the auxiliary device, loading method, and pro-gram of experiments. Our case study used a cubic sandstone specimen to investigate stress-strain behaviors, the evolution of intrinsic permeability, and the spatiotemporal characteristics of acoustic emissions (AE) under true triaxial stress coupled with CO2 gas flow (1 MPa at the inlet and atmosphere at the outlet). We found an obvious correlation between AE characteristics and the evolution of permeability. The AE signals could be applied to identify the fracture mode that triggered the essential change in rock permeability from a decrease to an increase. Furthermore, the AE source locations suggest the polymodal faulting mode of specimen failure, which is consistent with previous studies and our computed tomography (CT) scanning images. The case study also demonstrated the effectiveness and reliability of the device developed, which can play an important role in studies of oil and gas exploration and geological sequestration of CO2.
查看更多>>摘要：Capital and operating expenses of polymer injection projects are sometimes borderline to ensure profitability. Therefore, it is of interest to significantly improve the oil recovery potential with a low enough marginal cost. The addition of surfactant is very effective to enhance oil recovery, but, with traditional formulation guidelines, the high cost of chemicals and the difficulties in preparing the SP solution is major obstacles. The objective of this study is to try to adapt the concept of optimal surfactant formulation, without trying to achieve ultra-low interfacial tensions, to improve the overall efficiency of polymer injection. Phase behaviors of conventional surfactants/crude oil/water systems have been studied to find the optimal formulation conditions at high surfactants concentration. This ultra-low tension formulation was then diluted by more than one order of magnitude compared to "traditional" surfactant designs and was successfully tested in core floods at different injected volumes in order to optimize the design and minimize the cost. Contrary to expectations, it was found that the optimal formulation used at ultra-low concentrations can sufficiently modify the flow propagation to significantly improve polymer flood. The volume of surfactant injected was optimized to be "good enough" just to upgrade polymer flood without seeking complete desaturation. The low formulation concentration level makes it easy to handle and can considerably extend the application limits of polymer injection.
查看更多>>摘要：Forward modeling is a fundamental support to study the seismic response of reservoirs structure and subsurface architectures. Carbonate reservoirs result in non univocal seismic response caused by the facies heterogeneity and due to the possible presence of infilling fluids. The carbonate ramp outcropping in the Majella Massif (Central Italy) is an excellent surface analogue of buried heterogeneous structures. It offers the opportunity to directly analyze a carbonate reservoir which clearly shows facies variations and natural hydrocarbon-impregnations allowing to quantify the induced petrophysical changes. In this study, we integrated original field and laboratory measurements with 3D facies modeling to carry out 1D and 2D forward seismic models of a carbonate reservoir following a structured workflow. A careful petrophysical characterization measuring density porosity and seismic wave velocities has been performed in all the sampled facies and then used as input for the 3D velocity model. The "Sequential Gaussian Simulation Co-Kriging" (SGS-CK) results to be the best algorithm to build the seismic velocity model, consequently a low-frequency (40 Hz) synthetic 1D seismogram was carried out simulating facies and hydrocarbon-saturation variations. Thus, a 9 km long synthetic profile from the platform top to the basin, SE-NW oriented, was carried out simulating the outcropping architecture and spatial distribution of the facies. The obtained synthetic seismic outputs are closer to real geophysical surveys with respect to classical forward modeling. Perturbations of the seismic signal derived from the modeled facies heterogeneity without introducing artificial noises made the synthetic results more realistic preserving the horizons architecture. We also quantitatively show that variations in the signal related to the hydrocarbon saturation can result in an increase or decrease in reflectivity depending on the seismic properties of the surrounding layers. The presented results give new insights about reservoir architectures and can be useful to better process as well as to interpret the field seismic data and the resulting seismic sections acquired in carbonate realms.
查看更多>>摘要：Dimethyl ether (DME) is arousing attention as a novel water-soluble additive in oil industry. The accurate prediction of phase behavior of DME and water system is crucial important for DME-based research. An equation of state has been a powerful tool for solving phase equilibrium problem, which is based on an ideal molecular force model with binary interaction coefficients reflecting the deviation of a non-ideal system. However, the current knowledge of interaction coefficient is limited by obtaining from backward by using phase equilibrium data. This leads to the unclear meaning of the interaction coefficients, insufficient response to the molecular force interaction relationship at the molecular level and no ability to predict phase equilibrium properties without primary use of experimental data. To overcome this, in this study a correction by combining an activity coefficient and a linear solvation energy relationship (LSER) has been proposed to address the solubility deviation from an idealized model. This deviation at the micro level indicates the deviation of nonideal molecular forces from the ideal Raoult's law. Based on this novel correction, binary interaction coefficients have been obtained with a more practical molecular interaction relationship, which leads to more consistent results with experimental data from the literature. Moreover, in asymmetric phase systems, concentration-dependent binary interaction coefficients have been proposed based on previous discussion to represent intermolecular forces in non-ideal phase systems. Furthermore, partitioning coefficients, which lead to a potential criterion for solvent selection for heavy oil recovery, have been discussed from the perspective of intermolecular forces. This study provides new insights into non-ideal phase behavior. By combining a LSER and activity coefficients, a quantitative analysis on non-ideal molecular behavior and related complex phase problems becomes possible.
查看更多>>摘要：Oil sources and accumulation processes of the Neoproterozoic Luotuoling Formation (-930 Ma) in the Liaoxi Depression are investigated using integrated fluid inclusion, basin modelling and oil-source rock correlation analyses. In the upper Luotuoling Formation sandstone reservoir in Han-1 well, abundant bitumen inclusions and white fluorescent bitumen-bearing oil inclusions were observed. Combined with microthermometry of aqueous inclusions and burial history analysis, the oil charge time of the upper Luotuoling Formation sandstone reservoir took place at approximately 465-455 Ma. This oil was derived from the Gaoyuzhuang Formation source rock according to biomarkers and isotope compositions. However, oil generation of the Gaoyuzhuang Formation had already ended before 455 Ma, so the oils cannot be generated directly from the Gaoyuzhuang Formation source rocks, but definitely migrated from the destroyed paleo-oil accumulations in the Wumishan or Tieling formations. In addition, the lower Luotuoling Formation sandstone reservoir contains mainly yellowish orange fluorescent oil inclusions. The oil in the lower Luotuoling Formation sandstone reservoir was directly generated from the Hongshuizhuang source rock at 240-230 Ma. The study on oil accumulation history of the Neoproterozoic Luotuoling Formation reservoir is significant for further exploration of Proterozoic petroleum resources in the Liaoxi Depression, North China Craton.
查看更多>>摘要：Gypsum-salt rock is typically developed in carbonate reservoirs, and this rock has both constructive and destructive effects on the reservoir. The ways in which gypsum rock controls reservoir development are closely related to the diagenetic conditions. In this study, a typical saline lacustrine basin, the Qaidam Basin in China, was selected to examine the influence of gypsum-salt rock on the development of the carbonate reservoir under different diagenetic conditions. Four main geological factors were assessed: formation condition (temperature), typical salt mineral (anhydrite), and fluid properties (Ca2+ and Mg2+), along with multi-group fluid-rock chemical reaction models devised using multiphase-flow solute-transport simulation technology. Mineral dissolution, precipitation, and transformation in the reservoir under various temperature, pressure, fluid, and mineral conditions were analyzed, and the change of reservoir porosity was calculated. The results showed that the concentration of Ca2+ in fluid controls the dissolution and precipitation of carbonate minerals in the reservoir; moreover, continuous and sufficient Mg2+ is a necessary condition for dolomitization. Precipitation of anhydrite decreases with increase of temperature, verifying that anhydrite precipitates more easily at low temperature. Dissolution of calcium-containing minerals in overlying gypsum-salt rock can lead to mineral precipitation in the subjacent reservoir and reduce its quality.
NSTL
Elsevier