The study of rock crack propagation by multi-scale method is of great significance to comprehensively and accurately understand the law of rock crack evolution. In this paper, the theoretical, experimental and numerical methods from macroscale, mesoscale and microscale used for crack propagation in recent years are summarized and analyzed. Firstly, the evolution mechanism of the crack and the related research status are analyzed from a single scale. Secondly, multi-scale theory, modeling, meshing algorithm and macro-mesoscopic parameters are reviewed in the multi-scale coupling method. Through the analysis of the results published in recent years, it is considered that the following aspects need to be further studied: the characteristic parameters of the rock are different at different scales, so the extraction of the characteristic parameters under different scales is essential to modeling and coupling; the heterogeneity of rock and the prefabrication of cracks are greatly affected by human factors, so that 3D printing will be a good breakthrough to build the model of crack owing to its accurate control on the distribution and the size of cracks. The internal stress field of the rock is complex and varied, and the generation and expansion of the microcracks in the process of crack propagation are closely related to the surrounding environment. Therefore, it is of great importance to combine theoretical, experimental and numerical research with practical engineering.
The Chang 6 reservoir of Yanchang formation in Jingan oilfield has relatively poor quality: the porosity ranges mainly from 8 to 14%, and permeability ranges from 0.018 to 10.48 md, with a mean of 1.10 md, categorized as low porosity and low permeability reservoir type with strong heterogeneity. Petrographic and geochemical analyses of various components in these sandstones have provided clues of diagenesis. The sandstones at the early stage of diagenesis are characterized by non-ferroan calcite cementation, grain-coating, pore-lining clay minerals, and initial dissolution of detrital grains. Authigenic quartz, pore-filling and grain-replacive laumontites, albitized detrital plagioclase, authigenic K-feldspar, illite and late ferroan calcite cement dominate the late diagenesis. Reservoir quality is influenced by products of late diagenesis stage, the cement (calcite, albite, quartz, illite, and laumontite) occluded primary and secondary porosity. The organic acidic fluid derived from organic matter in the source rocks during the late diagenesis, which results in the dissolution of detrital plagioclase and laumontite cement and was the main reason for the enhancement of reservoir-quality. As a result of that, the residual primary pore and dissolution pore comprised the main accumulation space for oil and gas, and thus become important targets for hydrocarbon exploration.
Production from unconventional formations, such as shales, has significantly increased in recent years by stimulating large portions of a reservoir through the application of horizontal drilling and hydraulic fracturing. Although oil shales are heavily dependent on oil prices, production forecasts remain positive in the North-American region. Due to the complexity of hydraulically fractured tight formations, reservoir numerical simulation has become the standard tool to assess and predict production performance from these unconventional resources. Many of these unconventional fields are immense, consisting of multistage and multiwell projects, which results in impractical simulation run times. Hence, simplification of large-scale simulation models is now common both in the industry and academia.
Typical simplified models such as the “single fracture” approach do not often capture the physics of large-scale projects which results in inaccurate results. In this paper we present a simple, yet rigorous workflow that generates simplified representative models in order to achieve low simulation run times while capturing physical phenomena which is Fundamental for accurate calculations. The proposed workflow is based on consideration of representative portions of a large-scale model followed by post-process scaling to obtain desired full model results.
The simplified models that result from the application of the proposed workflow for a single well and a multiwell case are compared to full-scale models and the “single fracture” model. Comparison of fluid rates and cumulative production show that accurate results are possible for simplified models if all important components for a particular case are taken into account. Finally, application of the workflow is shown for a heterogeneous field case where prediction studies can be carried out.
Shales make up a large proportion of the rocks with extremely low permeability representing many challenges which can be complex in many cases. A careful study of rock and fluid properties (i.e. PVT of shales) of such resources is needed for long-term success, determining reservoirs quality, and increased recovery factor in unique unconventional plays. In this communication, a comprehensive thermodynamic modelling is undertaken in which capillary pressure is coupled with the phase equilibrium equations. To this end, the data associated with both shale oil and gas-condensates of Eagle Ford shale reservoir located in South Texas, U.S., is used. Different properties, including bubble and dew point pressures, capillary pressure, interfacial tension, liquid and gas densities, and liquid and gas viscosities, are predicted observing the effects of rock pore sizes by the thermodynamic modelling performed in this study. The results demonstrate that the thermodynamic model developed in this study is capable of simulating the PVT properties of oil and gas-condensates in shale and tight reservoirs. For a binary mixture 25:75 C1/C6, the bubble point pressure at different reservoir temperature is increased by increasing the pore sizes from 10 to 50 nm. Furthermore, an increase in pore sizes from 10 to 50 nm can increase the dew point pressure for a studied binary mixture 75:25 C1/C6.
Sulfur particles carried by high-speed flow impact pipelines, which may cause equipment malfunctions and even failure. This paper investigates the scouring effect of mist gas containing sulfur particles on elbows in highly sour gas fields. The multiphase-flow hydrodynamic model of the 90° elbow was established by using the computational fluid dynamics (CFD) method. The scouring effects of the gas-liquid mist fluid with the water-liquid fraction of 20% and particles with the diameter of 0.01-0.05 mm on elbows were explored within the flow velocity range of 0-20 m/s. In addition, the influences of secondary collision, mean curvature radius to diameter (R/D) ratio, inertial force, drag force, and Stokes number on trajectories of sulfur particles were studied. Moreover, the influences of hydrodynamic parameters of multiphase flow on corrosion inhibitor film were analyzed with the wall shear stress as the reference value. Serious erosion mainly occurred in the extrados of elbow as well as the junction between downstream pipeline and the intrados of elbow, the maximum erosion area occurs at 61.9°. When the incident position of the particle was far away from the top of the inlet plane, the probability of secondary collision became smaller. Furthermore, the erosion rate decreased with the rise in the R/D radio. The maximum erosion rate of elbow increased with the increase in the Stoke number. The maximum erosion rate reached 0.428 mm/a at 0.05 mm particle diameter and 20 m/s fluid velocity. The wall shear stress increased with the increase in fluid velocity and mass flow rate of particle, the fitting function of the wall shear stress curve was the Fourier type. The results indicated that high-velocity particles had a serious erosion effect on elbows and affected the stability of the corrosion inhibitor film. The erosion effect could be retarded by controlling the velocity and diameter of particles. The results provided technical supports for the safe production in highly sour gas fields.
One of the most severe problems during production from heavy crude oil reservoirs is the formation of asphaltene precipitation and as a result deposition in the tubing, surface facilities and near wellbore region which causes oil production and permeability reduction in addition to rock wettability alteration in the reservoir. So one of the economical ways to prevent such incidents is using the chemicals which are called asphaltene inhibitor.
In this study, the influence of three commercial inhibitors, namely; Cetyl Terimethyl Ammonium Bromide (CTAB), Sodium Dodecyl Sulfate (SDS), Triton X-100 and four non-commercial (Benzene, Benzoic Acid, Salicylic Acid, Naphthalene) inhibitors on two Iranian crude oils were investigated. This study extends previous works and contributes toward the better understanding of interactions between asphaltene and inhibitor. Effect of functional groups and structure of inhibitors on asphaltene precipitation were studied and it seems clear that the nature and polarity of asphaltene (structure and amount of impurities presented) has a significant impact on the selection of inhibitors. asphaltene dispersant tests and Core flood tests were designed for evaluation of inhibitors in static and dynamic conditions. The results revealed distinguished mechanisms for asphaltene solubilization/dispersion (such as hydrogen bonding, π-π interaction and acid-base interaction) and influence of additional side group (OH) on inhibition power of inhibitor.
During the experiments, it was found that increasing inhibitor concentration may lead to the self-assembly of inhibitor and declining of asphaltene stabilization. So, finding optimum concentration of inhibitor with high efficiency and available at a reasonable price is very important. The results suggest that 600 ppm of CTAB and 300 ppm of SDS were approximately optimum concentrations for the studied crude oils. One of the most important findings that differ from previous studies is the revelation of the mechanism behind the SDS/asphaltene behavior in various concentrations of inhibitor. Effect of chosen inhibitors on asphaltene precipitation and consequently deposition in porous media was studied, and then experimental data were modeled for evaluation of permeability impairment mechanisms. Permeability revived after inhibitor squeezing and cake formation mechanism played an important role in permeability reduction before and after treatment in porous media. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in the different period of production if needed any treatment process.
Oil formation volume factor (OFVF) is considered one of the main parameters required to characterize the crude oil. OFVF is needed in reservoir simulation and prediction of the oil reservoir performance. Existing correlations apply for specific oils and cannot be extended to other oil types. In addition, big errors were obtained when we applied existing correlations to predict the OFVF. There is a massive need to have a global OFVF correlation that can be used for different oils with less error.
The objective of this paper is to develop a new empirical correlation for oil formation volume factor (OFVF) prediction using artificial intelligent techniques (AI) such as; artificial neural network (ANN), adaptive neuro-fuzzy inference system (ANFIS), and support vector machine (SVM). For the first time we changed the ANN model to a white box by extracting the weights and the biases from AI models and form a new empirical equation for OFVF prediction. In this paper we present a new empirical correlation extracted from ANN based on 760 experimental data points for different oils with different compositions.
The results obtained showed that the ANN model yielded the highest correlation coefficient (0.997) and lowest average absolute error (less than 1%) for OFVF prediction as a function of the specific gravity of gas, the dissolved gas to oil ratio, the oil specific gravity, and the temperature of the reservoir compared with ANFIS and SVM. The developed empirical equation from the ANN model outperformed the previous empirical correlations and AI models for OFVF prediction. It can be used to predict the OFVF with a high accuracy.
Separate-layer injection of CO2 is an important method to improve oil and gas production and recovery. Conventional single-stage nozzle is usually blocked by impurities, and the ice-barrier phenomenon is very common. To solve this problem, large-diameter multi-stage circumfluence nozzle was designed to release pressure stage by stage. In order to illuminate the throttle characteristics of the CO2 multi-stage circumfluence nozzles, numerical simulation was performed to test several nozzles with different diameters and stage numbers. Furthermore, we tested the throttle characteristics through laboratory experiments and obtained the effects of several critical parameters such as nozzle diameter, number of stage and pressure drop on the throttle characteristics. The results show that the flow rate decreases as the nozzle stage increases on the condition of constant pressure and nozzle diameter. And pressure difference increases as nozzle stage number increases under the constant flow rate. The throttle capability of multi-stage circumfluence nozzles was much better than the concentric nozzles. Large-diameter multi-stage nozzle is recommended rather than small-diameter single-stage nozzle during the process of separate-layer injection, which can efficiently prevent impurities and ice blocking. The results are expected to provide a theoretical support for the nozzle choice of separate-layer injection of CO2.
Attempts to reduce the amount of greenhouse gases released into the atmosphere in recent years have led to the development of Carbon Capture and Sequestration (CCS) technology. However, there have been many studies reporting leakages form CO2 storage sites as a result of cement degradation induced by generation of an acidic environment in the storage site. Although there are a number of approaches proposed to enhance the efficiency of the cement, the degradation issue has not been totally resolved yet perhaps due to the excessive corrosives nature of carbonic acid and supercritical CO2. The aim of this study is to propose a methodology to improve the physical and mechanical characteristics of the cement by nanomodification such that a consistent rheology, constant density and a good strength development can be achieved. A new dispersion technique was proposed to ensure that the cement formulation gives a consistent result. The results obtained indicated that unlike the literature mixing, cement slurries prepared by the new mixing technique are very consistent in their rheology, regardless of the sonication parameters chosen. The measurements of the compressive strength performed at the reservoir condition revealed that nanosilica contributes in the strength development up to a certain point. Thermogravimetric Analysis (TGA) conducted at the last stage indicated that the amount of Portlandite left in the cement by adding nanosilica is decreased due to the pozzolanic reaction, which would help the cement to have a higher chance of survival in a storage site. However, cautions must be taken to maintain a certain amount of Portlandite in the cement for slowing down the carbonation rate, as otherwise the matrix of the cement is attacked directly and the cement will be degraded very fast.
The production process in the gas reservoir with an aquifer is complex. With gas production, aquifer water could possibly flow into the production well and accumulate within the well bore, which leads to a lower production rate and may even block the producer. However, few studies in the literature investigate the damage caused by the liquid phase in this kind of reservoir or predict gas productivity using the relationship between reservoir pressure and water gas ratio (WGR). For this reason, it is important to know the effects of the formation of liquid phase behavior on production when an aquifer is present under a gas reservoir.
From the results of published literature reviews, we found that studies focused on the production of a gas reservoir with bottom water. Nevertheless, for gas well damage from the liquid phase behavior, we found that there was no statistical data or mathematical model of the relationship between reservoir pressure and the gas oil ratio (GOR), which affects production.
In this research, based on the theory of fluid flow in porous media, a new mathematical model of water and gas production and a new equation on gas well productivity is developed. To verify the model and equation, gas production data collected from the field are applied. By analyzing the typical gas reservoir with bottom water and the collected data, influences from the liquid phase behavior are shown. In this way, mathematical relationships between reservoir pressure and the WGR and between the GOR and production decline were obtained. The new gas productivity model is derived from the gas and water pseudo pressure functions, which can be applied to analyze well damage caused by the liquid phase.
In order to verify the mathematical model, production data were collected from a typical gas reservoir with an aquifer located in the Changxing gas reservoir. The results indicate that a semi-logarithmic linear relationship is obtained between the WGR and productivity decrease. When the WGR increases from 0.5 to 15 m3/104 m3, damage caused by liquid phase decreases to 59%.
The tendency of gas productivity in the Changxing gas reservoir was obtained so that it decreases as reservoir pressure decreases and increases as the WGR decreases. The gradient of the gas productivity deduction increases as the WGR increases. By the end of the data analysis, two linear equations indicating the relationship between gas productivity and reservoir pressure and the relationship between gas productivity and the water gas ratio are obtained: QAOF=−A1lnWGR−B1 and QAOF=A2lnP−B2, respectively.
The new model and these two equations can be applied to predict gas productivity in the gas reservoir with an aquifer and determine the damage level to the gas well. They also can be used to guide development plans in the gas reservoir with an aquifer.
Conventional stimulation methods such as matrix acidizing, acid fracturing, or proppant fracturing have resulted in products that perform poorly and/or fail within months. Other options, such as water fracs with light sand, give better results but are prohibitively expensive. Mineral composition, brittleness index, stress regime, and petrophysical properties, which are favorable for creating complex fracture networks, can be obtained by geochemical and geomechanical analysis. The extended Reshaw and Pollard criterion shows that hydraulic fractures tend to be arrested by pre-existing natural fractures, and complex fracture networks would be created during fracturing. Additionally, the critical stressed faults theory indicates that the pre-existing natural fractures tend to slip with the shear mode as the pore fluid pressure increases. Rotating disk experiments and conductivity tests with artificial sheared plates have shown that flow channels can be etched at the location of scratches on fracture surfaces. Meanwhile, the carbonate cement in natural fractures can be chelated to form wormhole likely flow channels. Complex fracture networks with sufficient acid etched conductivity can be generated by water fracs with acid. A novel and economical volume stimulation strategy known as network acid fracturing has provided Tarim Oil Company the means to develope ultra-deep, ultra-high pressure, high temperature, and ultralow permeability but fractured gas reservoirs. Post-stimulation production performances of numerous wells with network acid fracturing are comparable to those with stimulated reservoir volumes.
The applicability of early time data in reservoir characterization is not always considered worthy. Early time data is usually controlled by wellbore storage effect. This effect may last for pseudo-radial flow or even boundary dominated flow. Eliminating this effect is an option for restoring real data. Using the data with this effect is another option that could be used successfully for reservoir characterization.
This paper introduces new techniques for restoring disrupted data by wellbore storage at early time production. The proposed techniques are applicable for reservoirs depleted by horizontal wells and hydraulic fractures. Several analytical models describe early time data, controlled by wellbore storage effect, have been generated for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. The relationships of the peak points (humps) with the pressure, pressure derivative and production time have been mathematically formulated in this study for different wellbore storage coefficients. For horizontal wells, a complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. Another complete set of type curves has been established for fractured formations based on the number of hydraulic fractures, spacing between fractures, and wellbore storage coefficient.
The study has shown that early radial flow for short to moderate horizontal wells is the most affected by wellbore storage while for long horizontal wells; early linear flow is the most affected flow regime by wellbore storage effect. The study has also emphasized the applicability of early time data for characterizing the formations even though they could be controlled by wellbore storage effect. As a matter of fact, this paper has found out that wellbore storage dominated flow could have remarkable relationships with the other flow regimes might be developed during the entire production times. These relationships can be used to properly describe the formations and quantify some of their characteristics.