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Supercritical carbon dioxide (ScCO 2) drilling can effectively protect shale formation from hydration damage and improve drilling rate comparing to conventional drilling technology. The wellbore stability of shale formation is one considerable issue under ScCO 2 drilling conditions. In this study, the numerical simulations are performed to calculate collapse cycling time of shale formation under ScCO 2 drilling conditions based on thermoporoelastic coupling model. The results show that comparing to water seepage condition, the variation of formation temperature is larger, pore pressure and stress are lower for ScCO 2 seepage condition without adsorption effect, the comparison between water and ScCO 2 seepage conditions verifies the thermoporoelastic coupling model. For ScCO 2 drilling conditions, if adsorption‒induced strain is ignored, the risk of wellbore collapse will be slightly underestimated comparing to the results with adsorption effect. When adsorption‒enhanced elastic modulus is ignored, the risk of wellbore collapse will be significantly underestimated comparing to the results with adsorption effect. The wellbore collapse may occur with the increasing well depth for ScCO 2 drilling conditions. This study can provide the theoretical guidance for exploiting shale reservoirs using ScCO 2. • The thermoporoelastic coupling analysis of wellbore stability for ScCO 2 drilling. • The effect of ScCO 2 adsorption-induced strain on wellbore stability. • The effect of ScCO 2 adsorption-enhanced elastic modulus on wellbore stability. • The comparison of distribution of temperature, pore pressure and stress between hydraulic fracturing and ScCO 2 fraturing. [ABSTRACT FROM AUTHOR]

As an abundant type of unconventional hydrocarbon resources on the earth, shale oil has been widely concerned by scholars across the world. During flowback period, flow-back resistance of fracturing fluids increases because of the existence of shale oil. Therefore, it is of practical significance to study the flow-back capability of fracturing fluid for high well performance. In this paper, fractal method of porous media has been used for calculation of relative permeability of oil-water two phase flow in shale pores. First, we built up flow equation of single nanopore with four layers: boundary layer, bulk wetting phase layer, oil-water two phase layer, and nonwetting phase layer. Furthermore, boundary slip, boundary, viscosity change in boundary layer and threshold pressure gradient is considered for correction flow rate equation. The pores of shale matrix can be simplified into capillary bundle model, and fractal theory is suitable for this model. Aperture fractal dimension and tortuosity fractal dimension is used to expand its scale to porosity media with fractal method. Then the model is verified by experimential results and classic models. Furthermore, serval main factors affecting the relative permeability of water are primarily analyzed, and the more essential factors out of the aforementioned ones are extracted and further studied. The results show that with the increase in the thickness of oil-water two phase layer, the relative permeability of water is affected more seriously; The relative permeability of water is positively correlated with slip length and thickness of boundary layer. This work provides a more convenient approach to calculate relative permeability with no experiments, and provide permeability for numerical simulation in flow back period. • A new model is developed for calculating oil-water two-phase relative permeability of shale formation during flowback period. • The effects of boundary layer thickness, oil-water two-phase layer thickness, threshold pressure gradient and slip length on relative permeability are studied. • Relative permeability can be calculated rapidly with high accuracy. [ABSTRACT FROM AUTHOR]

Abstract: This study aims to characterize the Laffan Shale Formation in Sirri oil fields from a borehole stability point of view. This paper describes the process and workflow for data-acquisition and interpretation in a shale formation characterization program and not only demonstrates the benefits of acquiring specific data, but also highlights the uses of the data to aid the exploration decision process. The next purpose of this paper is to provide a research process that can be applied in similar geological settings. In the study process, we collected a complete set of information and samples from the fields and presented a detailed case study, including laboratorial studies of formation samples and interpretation of the information. Available samples and information sources from Laffan Formation include drillhole core samples, daily drilling and geology reports and petrophysical logs of drilled wells and structural geological data of the area. Type and quantity of minerals were determined by direct and indirect methods. Bulk XRD analyses performed on core samples showed presence of traces of clay minerals. For determination of the exact clay mineral type, clay minerals were extracted and treated by heat and ethylene glycol saturation. Treated samples were subjected to XRD analyses. Interpretation of the gamma ray and natural gamma spectrometry logs allowed the determination of the type and content of clay minerals. In a next step, in order to study the distribution of minerals types and fabric of the shale samples, SEM photomicrographs were acquired. Cation exchange capacity of the samples was determined by methylene blue method and hot roll dispersion test in a water based drilling fluid was carried out to experimentally confirm the results. The caliper logs show washouts in the Laffan Formation in most wells. Pore pressure of the Laffan Formation was determined by using data obtained from both acoustic and resistivity logs. From the identification results it can be concluded that Laffan is not a swelling but a hard and brittle shale formation. The instability problem is not due to the dispersion or high pore pressure and cannot be completely solved by drilling fluid design and mechanical causes must be addressed. A noticeable point in this study is the similar results of direct and indirect methods of mineralogy determination. The practical conclusions of the study can be used in the field by engineers. [Copyright &y& Elsevier]

To reveal the proppant transport in the tortuous fracture network, a method introducing the normal distribution random function into the quartet structure generation set was proposed to construct the three-dimensional tortuous fracture networks. The tortuosity can be controlled by the variance of random function. And then, the proppant distribution in the tortuous fracture network was simulated with the consideration of the interact between slurry, fracture surface and proppants. Finally, effects of velocity and viscosity of slurry and the density and particle size of proppants on the proppant distribution in three different fracture networks were investigated. The accuracy of this model was verified by the experiment. The simulation reveals that besides the velocity decrease due to the fluid split, the slurry velocity also fluctuates because of the fracture width variation. The transport distance of proppants in tortuous fracture is about 10.7% shorter than that in the smooth fracture, while the distribution height is increased in the tortuous fracture network. Instead of forming the regular sand dune, the proppant is dispersively distributed in the tortuous fracture network. The proppant density and the slurry velocity are the main factors influencing the proppant distribution, followed by the slurry viscosity and proppant size. Proppant with smaller particle size can enter the area with narrow fracture width, so that the distribution of proppant in the fracture is more uniform. The research results can provide some guidance for the optimal design of slurry and pumping schedule in the hydaulic fracturing operation. • The slurry velocity in the main fracture fluctuates because of the fracture width variation. • The proppant is dispersively distributed in the tortuous fracture network. • Proppant density and slurry velocity are main factors influencing the proppant placement. • The structure and tortuosity of the fracture network also affect the proppant placement. [ABSTRACT FROM AUTHOR]