查看更多>>摘要：Estimating the ultimate storage capacity of deep saline aquifers is important to address the formation potential to store the envisioned large volumes of CO2. Injection data (i.e. injection rate, bottomhole pressure, and cumulative injected volume of CO2) are routinely recorded during storage operations. These data contain valuable information on the subsurface (e.g. the reservoir pore volume and the formation storage capacity) that can be extracted. In this paper, we present a two-step graphical technique to infer the pore volume and the ultimate storage capacity of closed saline aquifers by analyzing the available injection data. First, the pore volume is inferred through adapting the concept of the material balance time. Material balance time is an approximate superposition time function developed to interpret production data from oil and gas wells operating at variable pressure/rate conditions during the boundary-dominated flow period. Using material balance techniques, the ultimate storage capacity is then estimated through linear extrapolation of the average pressure trend to the maximum allowable pressure the formation can withstand. The average pressure is not available in practice, but is can be obtained from the injection data. Two approaches are presented in this study to calculate the average pressure;; namely the rigorous and the approximate approaches. Unlike the rigorous approach, the approximate approach does not require a prior knowledge of some reservoir properties (e.g. relative permeability, absolute permeability, formation porosity and thickness) to calculate the average pressure. To investigate its potential and reliability in analyzing CO2 injection data, the proposed technique is applied to four synthetic cases representing different well operating conditions. Results indicate that the approximate approach consistently overestimates the actual (simulated) storage capacity as compared to the rigorous approach. The agreement-between the inferred and the simulated reservoir pore volume, and between the analytical and numerical estimates of storage capacity-validates the potential application of the technique to CO2 storage in closed saline aquifers. The technique is further substantiated through application to a field data set utilized from a commercial-scale geological storage (CGS) project. Field data interpretation shows that the proposed technique can be utilized to identify the degree of hydraulic continuity and reservoir compartmentalization within a target formation by interpreting the corresponding pressure and rate responses.
查看更多>>摘要：Wettability is a critical parameter that controls fluid flow and distribution as well as recovery efficiency in reservoir rocks. The sensitivity of Nuclear Magnetic Resonance (NMR) relaxation measurements to wettability is well-known. Here we develop a new approach to calculate a wettability index based on low field NMR transverse (T2) measurements which is simpler than existing models in the literature and still affords good agreement with Amott-Harvey and USBM wettability test results. The model relies on the emergence of a bulk like relaxation signal from the non-wetting phase in partially oil/water saturated cores. Unlike other models in the literature, which require T2 measurements at up to four different saturation states, our model only requires measurements at two partial saturation states;; irreducible brine (S_(wi)) and residual oil (Sor). The performance of the model was tested using experimental results from different core types aged with light and heavy oils containing varied amounts of asphaltene. Different wettability conditions with Amott-Harvey/USBM values ranging from-0.39 to 0.79 were thus tested. When compared with measured reference wettability indices from the Amott-Harvey or USBM method, the model prediction showed good agreement (the calculated mean absolute error was 0.10). Additionally, improved accuracy was achieved relative to existing comparable models in the literature for the range of samples considered.
查看更多>>摘要：To characterize the subsurface geomechanical response to hydraulic fracturing (HF) activities, we study the spatiotemporal changes of seismic velocity during the completion of four HF wells in the Fox Creek area, Alberta, Canada. We estimate temporal velocity changes (dv/v) from ambient seismic noise recorded during the Tony Creek Dual Microseismic Experiment (ToC2ME) by comparing a 5-day stacked noise correlation function with a reference noise correlation function stacked over the deployment period. In the frequency band (0.1-0.4 Hz) most sensitive to the injection depths (~3.4 km), we observe daily dv/v that revealed alternating gradual velocity decreases and increases with magnitudes in the range of ±0.9%. We found a strong temporal correlation between the onset of velocity decreases and periods of intense seismicity, suggesting that the observed dv/v reductions are likely caused by stress-induced subsurface deformation due to elevated pore pressures, increased crack density, and ground shaking. A period of dv/v increase observed between the beginning and end of different well stimulation is attributed to crustal healing. Comparing the dv/v time series with injection parameters, we observed a 272.66% increase in induced seismicity and 50% more reduction in dv/v during the second injection phase that are correlated with 90.53%, 169.64%, and 4.34% increase in the injection volume, rate, and pressure, respectively. Our study provides valuable new information on the changes in reservoir elastic properties within the Western Canadian Sedimentary Basin. It also demonstrates that coda wave interferometry using data from dense seismic arrays near injection sites can be an additional tool for monitoring hydraulic fracturing operations.
查看更多>>摘要：An ultra-deep exploration well has been drilled in the Tarim Basin, northwest of China, with an Ordovician target zone is at a depth of over 7500 m. The Ordovician formation is within a graben structure. Extensive bedding planes and natural fractures develop in the target formation according to seismic analysis and image logging data from several reference wells, indicating a high risk of borehole instability or other complications while drilling through the fragmentized Ordovician zone. To mitigate potential borehole instability problems and associated nonproductive time during drilling the well, an integrated geomechanical study is conducted that combines geological, seismic, logging, and drilling data. The pore pressure, collapse pressure, and fracture pressure of the well are estimated and a safe mud window is provided to guide drilling operations in the Ordovician graben formation. A fracture development index is also calculated to locate the fracture distribution zones. The factors affecting wellbore stability are analyzed by establishing a discrete element model. With the guidance of this study, the well was successfully drilled and the stability of the wellbore was well controlled during drilling in the fractured formation.
查看更多>>摘要：Casing eccentricity reduces displacement efficiency during horizontal well. However, there are many problems such as the short length of horizontal well simulation and long calculation time now. In this study, the cement model was re-established based on the relative motion principle. Through the reverse movement of the wall, the short horizontal section model was realized to simulate the displacement process of the long horizontal section without generating new grids and the computational resources were greatly reduced. Besides, by redefining the displacement interface length and dynamic displacement efficiency, the precision problem of displacement efficiency parameter analysis in engineering is solved. The accuracy and practicability of this method were verified by comparing it with the previous research results. On this basis, the effects of the concentration, displacement, density difference and the rheological properties of the isolator were studied. The results show that it is beneficial to equalizing the velocity of the narrow and wide side, with the measure that decreasing the eccentricity, increasing the positive density difference or the viscosity difference of the two-phase fluid, thereby improving the displacement efficiency. This study provides a comprehensive modelling method for numerical simulation of cementing displacement and provides theoretical guidance for field cementing operations.
查看更多>>摘要：Flow behaviors of the heavy oil and its asphaltic residues in a horizontal pipe are simulated using a filtered liquid-solid two-fluid model. The filtered liquid-solid two-fluid model systematically filters the highly resolved simulation results. The filtered model retains the mesoscopic scale flow characteristics to simulate the macroscopic flow. The test of drag force models including KTGF-model (Gidaspow model) and filtered model is conducted. The predicted pressure drops based on the filtered model with wall correction are well corresponded with the experimental data by Hector Zambrano et al. Also, the distributions of the time-average asphaltic residues volume fraction, asphaltic residues velocity, solids pressure and granular temperature along the radial direction are obtained for different asphaltic residues fractions of 6%, 8% and 12%. It is revealed that the mesoscopic-scale flow behavior of particle clusters is detailedly reproduced with a filtered model considering wall correction, and the asphaltic residues aggregations are more obvious at the bottom of the pipeline.
查看更多>>摘要：In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multistage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.
查看更多>>摘要：Steam assisted gravity drainage (SAGD) is an energy and water intensive oil recovery technology for in-situ extraction of oil sands bitumen. It is essential to recycle the SAGD produced water (PW) to reduce water consumption and improve the energy effciency of the process. This work investigated the removal of residual organic matter (ROM) in the SAGD-PW by the ceramic nanofltration (NF) membrane process. The overall removal effciency of ROM in the SAGD-PW was infuenced by their polarities, membrane pore size, and membrane material. Non-polar oil components including saturated and aromatic hydrocarbons were completely removed;; meanwhile, approximately 80% of polar components were removed by the membrane nanofltration. Membrane nanofltration signifcantly altered the chemical composition of the SAGD-PW by removing 95.0-98.3% of total solvent extracted material (TSEM). The chemical fngerprints of the solvent extracted materials in the feed and permeate samples were characterized. The profle of polar components such as naphthenic acids (NAs) in the permeate samples is signifcantly different from that in the feed samples.
查看更多>>摘要：The reservoir spaces of the carbonate reservoirs in the Tahe oilfield consist of fractures and vuggies. The injection of particle plugging agents to control the dominant channel of water flooding is an important measure in enhancing oil recovery. In this paper, a simplified parallel fracture is used to represent the complex fracture structure, and an oil-water-particle three-phase flows computational fluid dynamics model based on the volume of fluid-discrete element method (VOF-DEM) model is established to study the particle transport and accumulation behaviors after water flooding in the fractures. The results show that the injected particles are transported and accumulate along the water phase channel in the main fracture after water flooding but barely flow directly into the secondary fracture. The particle accumulation in the main fracture reduces the cross-section of the water phase flow channel, which leads to an increase in the pressure loss in the main fracture and the flow ability in the secondary fracture. The oil-water interface at the top of the accumulation changes during the process of particle injection, which is beneficial in enhancing oil recovery. The simulation results of different parameters show that the injection velocity, particle volume fraction, and particle diameter affect the position, length, and height of the particle accumulation in the main fracture, which exhibits an important influence on the oil-water interface in the main fracture and the flow ability in the secondary fracture.
查看更多>>摘要：Polymer microspheres have high swelling ratio, which can be used to improve the heterogeneity of low permeability reservoirs. When combined with a spontaneous emulsifying flooding system, the sweep efficiency of the system can be increased. However, due to its strong hydrophilicity, the conventional polymer microspheres cannot be adsorbed on the oil-water interface and reduce the interfacial tension, so as to improve the stability of emulsion and further improve the oil washing efficiency of spontaneous emulsion flooding. In this paper, surface-active microspheres S-PM are developed by using stearyl methacrylate (SMA) as the surface-active monomer. Compared with conventional polymer microspheres, the microspheres are amphiphilic particles with a swelling particle size of 600 nm, which can improve the stability of emulsions while improving the heterogeneity of low permeability reservoirs. The study of interfacial behavior shows that S-PM can decrease the interfacial tension to 0.005 mN/m by dragging surfactant molecules to the oil-water interface through polar action and increasing the surfactant concentration on the interface, and can increase the interfacial dilatational elastic modulus to 26.5 mN/m by forming a rigid adsorption layer. The emulsion stability analysis and micrographs show that S-PM can be distributed on the surface of the droplet. Due to the decrease of oil-water interfacial tension and the increase of interfacial strength, it is not easy to collide and coalesce, thus improving the emulsion stability. The dewatering rate decreases from 81.6% to 65.4%, and the TSI decreases from 9.7 to 5.3. The profile control results show that after adding S-PM, the spontaneous emulsifying flooding system is suitable for heterogeneous low-permeability reservoirs with permeability ratio below 5. This study expands the function of polymer microspheres, and it is expected to further improve the recovery of low permeability reservoirs by combining surface-active microspheres with a spontaneous emulsion flooding system.
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