Lijun You

Laboratory measurement and interpretation of nonlinear gas flow in shale

Gas flow mechanisms in shale are urgent to clarify due to the complicated pore structure and low permeability. Core flow experiments were conducted under reservoir net confining stress with samples from the Longmaxi Shale to investigate the characteristics of nonlinear gas flow. Meanwhile, microstructure analyses and gas adsorption experiments are implemented. Experimental results indicate that non-Darcy flow in shale is remarkable and it has a close relationship with pore pressure. It is found that type of gas has a significant influence on permeability measurement and methane is chosen in this work to study the shale gas flow. Gas slippage effect and minimum threshold pressure gradient weaken with the increasing backpressure. It is demonstrated that gas flow regime would be either slip flow or transition flow with certain pore pressure and permeability. Experimental data computations and microstructure analyses confirm that hydraulic radius of flow tubes in shale are mostly less than 100 nm, indicating that there is no micron scale pore or throat which mainly contributes to flow. The results are significant for the study of gas flow in shale, and are beneficial for laboratory investigation of shale permeability.

Laboratory Measurement and Interpretation of the Changes of Physical Properties after Heat Treatment in Tight Porous Media

Prevention of water blocking and optimization of multiscale flow channels will increase gas production of tight reservoirs. Physical properties of samples from representative tight gas reservoirs were measured before and after high temperature treatment. Results show that, with the increase of treatment temperature, mass decreases, acoustic transit time increases, and permeability and porosity increase. Permeability begins to increase dramatically if treatment temperature exceeds the threshold value of thermal fracturing, which is 600~700°C, 500~600°C, 300~500°C, and 300~400°C for shale, mudstone, tight sandstone, and tight carbonate rock, respectively. Comprehensive analyses indicate that the mechanisms of heat treatment on tight porous media include evaporation and dehydration of water, change of mineral structure, generation of microfracture, and network connectivity. Meanwhile, field implementation is reviewed and prospected. Interpretations indicate that, according to the characteristics of multiscale mass transfer in tight gas formation, combining heat treatment with conventional stimulation methods can achieve the best stimulation result.

Mitigating Borehole Instability And Formation Damage With Temporary Shielding Drilling Fluids In Low Permeability Fractured Reservoirs

Along with the increasingly deep wells and long horizontal wells, the wellbore instability and formation damage undeniably becomes the biggest concerns during well construction. Sha 3 reservoirs in faulted B Depression, a low permeability exploration target zones, are highly fractured. Most of the wells with the barefoot interval length of over 2000m or even about 3500m were drilled under underbalanced conditions to improve exploration success rate. The exploration results were disappointing. Shale sloughing and borehole enlargement frequently occurred during the process of previous drilling, followed by some troubles including serious formation damage. Different kinds of drilling fluid techniques, including the nano-emulsion drilling fluid, polymeric alcohol and potassium formate, were tried to settle these problems with mixed results. Mineral analysis, shale dispersion and swelling test, and dynamic leakoff tests show that the solid particles mismatching well with the sizes of pore throats and the width of natural fractures and the high pH value of drilling fluids are two key factors triggered the borehole instability and formation damage. Based on the temporary shielding theory, the modified drilling fluids are developed by adding fibrous bridging agents and by decreasing pH value. Dynamic leakoff tests manifest that the modified drilling fluids are able to rapidly seal the micro fractures and pore throats and the percentage of regained permeability can reach more than 85%. Two experiment wells, a vertical well and a sidetracked well, located in an area of severe shale sloughing, were drilled with the modified drill fluids under micro overbalanced conditions. The results indict that the diameters of two boreholes are near-gauge, that the coring, well logging and completion operations are conducted very successfully, and that the well construction time is cut down by 50% compared with that of previous drilled wells. Introduction Recent decades have seen the increasingly important role of low permeability oil and gas reservoirs in increasing reserve and production supply. Proved low permeability oil reserves are 99.4×10 tons, 36% of the total oil reserves, and proved tight sandstone gas reserves are 3.1×10m by the end of 2010 in China. Borehole instability and formation damage contribute a lot to poor economic benefits of development of low permeability oil and gas reservoirs, which need to be minimized and effectively controlled for the play to be economical exploitable, so the significance of preventing the borehole instability and formation damage can never be overestimated. Borehole instability, followed by a series of problems, might induce the increase of a considerable amount of nonproductive time, and may indirectly or directly trigger formation damage, so the full consideration should be taken to how to maintain perfect wellbore quality during well drilling and completion. Sha 3 member in B depression is highly fractured low permeability reservoirs, one of the recent important exploration targets. Most of the wells were drilled under underbalanced conditions to improve exploration success rate, but the wells were designed with the barefoot interval of over 2000 m or even about 3500 m long in consideration of the cost and economic benefits. Different kinds of drilling fluid techniques, including the nano-emulsion drilling fluid, polymeric alcohol and potassium formate, were tried to settle borehole instability problems, but they did not work well. This paper focuses on finding the reasons for borehole instability and formation damage, and then presents the measurements for mitigating both borehole instability and formation damage of the low permeable fractured reservoirs by optimizing the drilling fluids.

An Experimental Study on Porosity and Permeability Stress-Sensitive Behavior of Sandstone Under Hydrostatic Compression: Characteristics, Mechanisms and Controlling Factors

Porosity and permeability stress-sensitive behavior of sandstone is investigated through porosity and permeability measurements under hydrostatic compression. An empirical logarithm model is applied to the evaluation of stress sensitivity. Mercury injection, casting thin sections and scanning electron microscope are adopted to discuss the microscopic controlling factors and mechanisms of stress-sensitive behavior of sandstone. Disparities between laboratory-scale and field-scale data are also discussed. Experimental results show that both porosity and permeability decrease with increasing effective stress, and permeability is more sensitive to stress. The evolution of porosity and permeability with increasing effective stress follows the logarithmic model and can be classified into three stages: rapid decline, moderative decline and stable-slight decline stage. Stronger permeability stress sensitivity is observed in specimens with lower initial porosity and permeability, which is fundamentally controlled by the size and shape of void spaces as well as the content and distribution of soft minerals. While porosity stress sensitivity is observed to be discrete. Pore throat with small aspect ratio and irregular shape, fractures and minerals with lower elasticity modulus lead to the increase in permeability stress sensitivity of sandstone. The stress sensitivity characteristics are essentially the result of the dissimilar deformation responses of pores and framework grains under effective stress. Stress sensitivity evaluated in the laboratory usually does not completely represent the stress sensitivity in the field, due to stress release, drilling induced fractures and the difference of experimental and in situ conditions.

Quantitative characterization of micro forces in shale hydration and field applications

Abstract Shales (illite was the dominant clay mineral) of Silurian Longmaxi Formation in Sichuan Basin and Triassic Yanchang Formation in Ordos Basin were taken as subjects to examine the mechanisms of shale-water interaction, quantitative characterization of hydration force and potential field applications based on micro forces analyses. Mica sheet with composition and property very similar to illite was tested for micro forces between the crystal layers. In electrolyte solution, micro forces between mica-solution-mica system include DLVO (Derjaguin-Landau-Verwey-Overbeek) force and hydration force; when the electrolyte concentration was low, the tested curve agreed with the theoretical DLVO curve; when the electrolyte concentration was higher than the critical value and the distance between mica sheets was less than 5 nm, the tested curve deviated from the DLVO curve completely, and the hydration force became dominant. Quantitative analysis indicated that the hydration force decayed in a rapid double-exponential type with the growth of distance. Field applications indicate that strict control of water invasion and reducing the strength of hydration force are the keys in designing collapse-preventing drilling fluids; meanwhile, during the shut-in period of shale gas wells, shale-water interaction can induce and extend micro-cracks, further improving the stimulation effect of shale reservoirs.

Effect of Fluid Exposure on Mechanical Properties of Organic-Rich Shale and Field Applications

Understanding the effect of fluid exposure on organic-rich shale mechanical properties is crucial in design of working fluids used in shale reservoir drilling and hydraulic fracturing. A series of triaxial compression tests and friction coefficient measurements were conducted on dry and fluid exposure specimen of three typical organic-rich shales in China. Fluid-type and time-dependent variation of mechanical properties were significantly observed between dry and fluid exposure specimen. These variations are attributed to the specific fabric feature of organic-rich shale and different fluid–shale interaction mechanisms, which is predominantly hydration for water-based fluid and friction reduction for oil-based fluid. Fluid exposure effect will increase the risk of wellbore instability through increasing pore pressure and decreasing shale strength. It also influences the propagation and orientation of hydraulic fractures, strengthens proppant embedment, and induces fines migration and colloids agglomeration/precipitation in hydraulic fracturing. Improve sealing performance, apply clay stabilizer and surfactant, manage pH value, and increase drilling rate are mainly effective methods to prevent or mitigate adverse effect of fluid exposure on shale oil/gas well drilling and production performance. These fluid effect control strategies have been successfully applied in the shale reservoir drilling in Sichuan Basin and Ordos Basin.

The critical porosity of tight sandstone: electrical property change based on pore structure and minerals

Porosity, which is an important petrophysical parameter of tight sandstone, is closely related to its electrical property under 100% brine saturation. In this work, core resistivity measurements were conducted under reservoir net confining stress with samples from Upper Permian tight sandstone to investigate its critical porosity. Meanwhile, TS, XRD and CEC analyses were implemented. Experimental results show that the change of electrical property with porosity is not clear unless putting 5% as a cut-off point of porosity. It is found that the contribution of brine to core resistivity is variable for different porosity and 5% is the key cut-off point. Considering that core electrical property is determined by pore structure and minerals, microstructure was studied, indicating that 5% is the demarcation point of porosity. Further, mineralogical composition and clays extra conductivity were analysed, and the results correspond to the conclusion on the porosity of 5% drawn by core resistivity measurements. [Received: October 7, 2014; Accepted: October 3, 2015[