Supercritical CO2 Fracturing Research Articles

Experimental study on the supercritical CO2 fracturing of shale considering anisotropic effects

Hydraulic fracturing using freshwater as fracturing fluid is regularly employed in commercial shale gas or oil production. Many problems are brought by the fracturing fluid of water, such as water shortages, swelling of clay mineral, and the pollution of flow-back water. Replacement of water by supercritical CO2 (SCCO2) in the hydraulic fracturing treatment of shale reservoir has meaningful potential for the improvement of gas production. Hydraulic fracturing experiments, under different injection rate and stress state, were carried out for studying the SC-CO2 fracturing of shale considering anisotropy effects. Anisotropy of shale has a significant impact on the mechanical behavior and fracture propagation of shale in the experiment. There shows a downward tendency for breakdown pressure with the increase of bedding plane angle in general. Higher injection rate can lead to the higher breakdown pressure, while higher deviator stress can lead to the lower breakdown pressure instead. In addition, three patterns of fracture propagation can be observed in the experiment, relative to the bedding structures of shale specimen, including propagating along, propagating across and arresting. The maximum values of fracture width during experiment in shale with different bedding plane angle ranges from 0.29 mm to 1.05 mm, while the final fracture width after the fracturing experiment is kept within the range of 0.01 mm–0.04 mm under the injection rate of 0.3 ml/s.

Experimental investigation on abrasive supercritical CO2 jet perforation

abrasive supercritical CO2 (SC-CO2) jet perforation is the key procedure in the SC-CO2 fracturing, which will directly affect the exploitation of oil and gas. The properties of the SC-CO2 fluid, such as density, viscosity, diffusivity and so on, change greatly with the variation of temperature and pressure, which directly affect the particle-carrying ability and perforation performance. This paper investigates the influence of key parameters, such as ambient pressure, fluid temperature, jet standoff distance and jet pressure, on the perforation ability of abrasive SC-CO2 jet. The results indicate that the ambient pressure has no significant effect on perforation under the condition of a fixed jet differential pressure. When the confining pressure increases from 5 to 15 MPa, the hole depth and diameter decrease by 5.7% and 18.6% respectively. The hole depth increases slightly with the rising of jet temperature. In addition, with the jet temperature rising per 20℃ within the range from 40 to 100℃ and the standoff distances being 4 to 10 mm, the hole depths increase by 3.8% and 12.0% in average, respectively. Furthermore, the hole depths keep unchanged at first and then decrease rapidly with the increasing standoff distance. However, the hole diameters and effectively impinged areas increase with the standoff distance. The influences of SC-CO2 jet pressure on the perforation performance are similar to that of the conventional jet. Additonally, both effective hole depths and volumes increase linearly in general with the increasing of jet pressure. The hole depths averagely increase by 36.6% when the SC-CO2 jet pressure rising by 5 MPa. Furthermore, the research also shows that perforation performance of pre-mixed jet is better than the post-mixed jet, the volume ratio of the two kinds of perforating holes is 12.02 under these experimental conditions. All the above merits have provided a theoretical foundation and experimental proven for the field application of SC-CO2 jet perforation technology.

Optimization design of hydraulic parameters for supercritical CO2 fracturing in unconventional gas reservoir

Unconventional gas reservoirs are characterized by ultra-low permeability. Such ultra-low permeability can significantly affect the geometry of the fractures being created in the reservoir, as well as bring about challenges with regard to how to effectively mitigate formation damage issues during fracturing. Supercritical CO2 (SC-CO2) fracturing, as an innovative and promising stimulation method, incurs no formation damage, and is capable of effectively improving the reservoir permeability, preventing near-wellbore formation blockage. Taking the effects of adsorption between CO2-shale-CH4 into consideration, a two-phase filtration rate calculation model of SC-CO2 fracturing in unconventional natural gas reservoirs is proposed. Based on physical property equations of a SC-CO2 fluid, and considering the internal fluid energy, the change in flow work, and the filtration and adsorption characteristics of SC-CO2-shale, temperature and pressure field models were built inside the wellbore and fracture of SC-CO2 fracturing, as was a two-phase flow model of SC-CO2 fracturing fluid carrying proppant in a fracture under an unsteady state. The calculation results show that the temperature and pressure of the fracturing fluid in the wellbore increase with the depth of the well. The temperature of the SC-CO2 fluid in the fracture increases with the increase in fracture length, and eventually reaches close to the original formation temperature, whereas the pressure of fluid CO2 in the fracture decreases with an increase in the fracture length. The hydraulic parameters of SC-CO2 fracturing are optimized, such as the CO2 injection temperature, pumping rate, proppant density, and diameter. According to the proppant embankment profile, the method of increasing the proppant concentration in small steps and the optimization of the proppant pumping process satisfy the fracture propping requirements.

The effect of supercritical CO2 fracturing fluid retention-induced permeability alteration of tight oil reservoir

Supercritical CO2 (SC-CO2), as a non-aqueous material of fracturing fluid, receives widely attention in the development of unconventional reservoirs. In this study, permeability regain (Krg) was introduced to characterize the permeability alteration on tight cores by SC-CO2 fracturing fluid. Meanwhile, scanning electron microscope (SEM), microscope system, nuclear magnetic resonance (NMR) were used to reveal the mechanisms of permeability alteration at different scales.The results showed that the composition of SC-CO2 fracturing fluid, fluid filter loss, and reservoir permeability were all responsible for permeability alteration. With the increasing thickener contents and filter loss of fracturing fluid, core permeability regains turned to be declined. Comparatively, tight cores which consist of more micro-nanometer sized pores were more likely to receive more formation damage of permeability, as well. The retention of thickener in microchannels (micro pores) were confirmed to be the main mechanisms on permeability alteration.

Numerical study of supercritical CO2 and proppant transport in different geometrical fractures

AbstractSupercritical CO2 (SC‐CO2) fracturing, as a kind of waterless fracturing method, is an effective treatment in the unconventional oil and gas industry. Due to its characteristic lower viscosity, supercritical CO2 fracturing is likely to create thin and long fractures that connect pre‐existing natural fractures and generate complex fractures. It is therefore very challenging to predict how far supercritical CO2 carrying proppant can go and how proppant will be transported in natural fractures, when natural fractures are contacted or penetrated by induced fractures. In this paper, proppant transport with supercritical CO2 in fractures was analyzed using the computational fluid dynamics method. Three types of fractures – planar fractures, T‐shape fractures and crossing‐shape fractures – were modeled. Five parametrical cases were studied using the T‐shape and crossing‐shape models. Results show that, for T‐shape fracture cases, a turbulent flow regime might develop at a fracture junction, which can make proppant propagate to natural fractures. For crossing‐shape fractures, a turbulent flow takes place behind the fracture junction, which causes a little sand dune to form downstream of the induced fracture. With the reduction in the width of the natural fracture, the height of the sand bank at the thinner natural fracture is higher than that at the wider natural fracture. Using a proppant whose density and diameter are respectively less than 1540 kg/m3 and 0.25 mm, as well as a sand‐carrying fluid whose sand ratio ranges from 8% to 10% and injection rate exceeds 2 kg/s, is beneficial to prop natural fractures. Moreover, the larger the intersection angle of the crossing‐shape fracture is, the more difficult it is for proppant to enter natural fractures. This study reveals the influence of fracture geometry on proppant transport with SC‐CO2. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Supercritical CO2-water-shale Interactions under Supercritical CO2 Stimulation Conditions

As one of the main unconventional gas reservoirs, the exploration and exploitation of shale gas reservoirs has been a hot spot of global resources development. The traditional water-based fracturing fluid with the disadvantages of large water consumption and serious formation damage does not apply to shale gas reservoirs stimulation. Supercritical CO2 fracturing technology, using harmlessness CO2 for sand-carrying fluid, was brought forward to apply to development of shale gas reservoirs, with the advantages of no water consumption, no damage to formation, contributing to CH4 desorption, etc. When applying supercritical CO2 as the fracturing fluid, in fractures supercritical CO2 interacts with shale in the presence of water. The study on the interactions of shales and supercritical CO2 in the presence of water is a basic issues in stimulation of supercritical carbon dioxide within shale reservoirs. The objective of this study is to solve the key problems which the interactions of shale, supercritical CO2 and water involves, such as mineral elements migration, microscopic pore structure and so on.

Model for calculating the wellbore temperature and pressure during supercritical carbon dioxide fracturing in a coalbed methane well

Supercritical CO2 fracturing can form a more complex fracture network in rocks than hydraulic fracturing and avoid aqueous phase trapping damage in reservoirs. Thus, it is a promising alternative to hydraulic fracturing for enhancing the production of low-permeability hydrocarbon reservoirs. In this study, a new numerical model for predicting the wellbore temperature and pressure during supercritical CO2 fracturing was established based on thermodynamics, heat transfer, fluid mechanics, and a numerical solution method. In the new model, the physical properties of CO2 are calculated with the Span–Wagner and Vesovic models, and the heat generated by fluid friction losses is absorbed by the tubing and CO2 according to the contact coefficient. The model was used to examine the influences of the injection rate and temperature on the wellbore pressure and temperature. The results indicated that both the heat transfer and pressure in the wellbore are transient processes in the initial stage of injection; as the injection time increases, the heat transfer and pressure in the wellbore can be considered steady processes. The CO2 temperature in the wellbore is considerably affected by both the injection temperature and rate, whereas the wellbore pressure is greatly affected by the injection rate but weakly affected by the injection temperature. The CO2 pressure in the wellbore decreases rapidly as the well depth increases because of high fluid frictional resistance, so a drag reducer suitable for liquid CO2 needs to be developed.

Microcrack-based geomechanical modeling of rock-gas interaction during supercritical CO2 fracturing

Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore- and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.

Design of experimental system for supercritical CO2 fracturing under confining pressure conditions

Supercritical CO2 has the characteristics of low viscosity, high diffusion and zero surface tension, and it is considered as a new fluid for non-polluting and non-aqueous fracturing which can be used for shale gas development. Fracturing refers to a method of utilizing the high-pressure fluid to generate fractures in the rock formation so as to improve the oil and gas flow conditions and increase the oil and gas production. In this article, a new type of experimental system for supercritical CO2 fracturing under confining pressure conditions is designed, which is based on characteristics of supercritical CO2, shale reservoir and down-hole environment. The experimental system consists of three sub-systems, including supercritical CO2 generation system, supercritical CO2 fracturing system and data analysis system. It can be used to simulate supercritical CO2 fracturing under geo-stress conditions, thus to study the rock initiation pressure, the formation of the rock fractures, fractured surface morphology and so on. The experimental system has successfully carried out a series of supercritical CO2 fracturing experiments. The experimental results confirm the feasibility of the experimental system and the high efficiency of supercritical CO2 in fracturing tight rocks.

The influence of different diffusion pattern to the sub- and super-critical fluid flow in brown coal

Sub- and super-critical CO2 flowing in nanoscale pores are recently becoming of great interest due to that it is closely related to many engineering applications, such as geological burial and sequestration of carbon dioxide, Enhanced Coal Bed Methane recovery ( ECBM), super-critical CO2 fracturing and so on. Gas flow in nanopores cannot be described simply by the Darcy equation. Different diffusion pattern such as Fick diffusion, Knudsen diffusion, transitional diffusion and slip flow at the solid matrix separate the seepage behaviour from Darcy-type flow. According to the principle of different diffusion pattern, the flow of sub- and super-critical CO2 in brown coal was simulated by numerical method, and the results were compared with the experimental results to explore the contribution of different diffusion pattern and swelling effect in sub- and super-critical CO2 flow in nanoscale pores.

Phase state control model of supercritical CO2 fracturing by temperature control

A phase state control model of supercritical CO2 (SC-CO2) fracturing by temperature control has been developed on the basis of CO2 physical properties, fluid filtration characteristics, internal energy, and flow work variation in the fractures. A considerable amount of analysis focuses on the effects of the CO2 injection temperature and pressure, geothermal gradient, pumping rate of CO2 fracturing fluid temperature, pressure field, and phase behavior in the wellbore and fractures. In this study, the phase control method of the fractures during SC-CO2 fracturing in addition to its chart is obtained. The results indicate that the temperature of the SC-CO2 fracturing model in the wellbore and fracture is less than that when not considering the flow work model at the same location. During the process of fluid flow, a transition occurs from the liquid to supercritical state in the wellbore or fractures. The phase transformation point differs in the fractures such that a lower injection temperature relates to a high pumping rate, lower geothermal gradient and closer location of transformation point to the end of fractures. Thus, to obtain the optimal stimulation effect of the supercritical CO2 fracturing, the phase behavior of CO2 should be controlled according to the reservoir conditions through surface equipment by optimizing the injection temperature, pressure, and pumping rate of the fracturing fluid.

Wettability Alteration Study of Supercritical CO2 Fracturing Fluid on Low Permeability Oil Reservoir

Hydraulic fracturing has become an important stimulation technique for low/ultralow permeability reservoirs. Supercritical CO2 (SC-CO2), as a no water phase material of fracturing fluid, receives wide attention. Current researches on SC-CO2 fracturing fluid has mainly focused on its viscous properties and superiorities. However, little attention has been devoted to the interaction between SC-CO2 fracturing fluid and the oil reservoir during the fracturing process. Besides, in a low permeability reservoir, the wettability determines the oil recovery by imbibition, which is a main way to explore oil for a matrix. Therefore, it is crucial to study the wettability alteration on a low permeability oil reservoir introduced by SC-CO2 fracturing fluid. In this study, a contact angle goniometer was introduced to characterize the wettability alteration on low permeability cores by SC-CO2 fracturing fluid. Meanwhile, nuclear magnetic resonance T2 spectra, a scanning electron microscope, and a energy dispersive spect...

Experimental study on the growth behavior of supercritical CO2-induced fractures in a layered tight sandstone formation

As a non-aqueous fracturing technology, carbon dioxide (CO2) fracturing is eliciting increasing attention in the exploitation of tight oil/gas reservoirs. This study explored the growth behavior of supercritical CO2 (SC-CO2)-induced fractures in layered tight sandstones through a series of laboratory fracturing experiments under triaxial stress states. Acoustic emission (AE) monitoring and computerized tomography scanning were performed to analyze the AE focal mechanisms and fracture geometry. The features of SC-CO2 fracturing were discussed through a comparison with the features of x-linked guar and slickwater fracturing. The influences of horizontal differential stress and pumping rate during SC-CO2 fracturing were also examined. Results showed that SC-CO2 likely promoted the dilation or shearing of bedding planes and natural fractures, resulting in a complex fracture network even under a high horizontal differential stress. Statistical analysis of the P wave polarity of AE waveforms indicated that the AE events associated with the SC-CO2 induced factures were dominated by shear failure. Most of the branching fractures induced by SC-CO2 fracturing were extremely narrow that they impeded proppant transport. For SC-CO2 fracturing, injection pressure (especially breakdown pressure) was low and likely dissipated as the growth of branching fractures. AE activities, indicating the fracture growth, more likely occurred when the injection pressure rose high (e.g., in tens of seconds before and after breakdown) or fluctuated remarkably. A large pumping rate was necessary to maintain high injection pressure which can open the branching fractures widely and persistently because of the extremely large leak-off rate of SC-CO2.

Effects of CO2–brine–rock interaction on porosity/permeability and mechanical properties during supercritical-CO2 fracturing in shale reservoirs

A series of static soaking experiments, combined with the bulk-rock X-ray diffraction and scanning electron microscopy analyses, was conducted to investigate the influences of supercritical CO2 fracturing on the physical–chemical properties of shales. CO2–brine–rock reactions under different conditions, which result in the changes of porosity/permeability and mechanical properties, were investigated in detail. CO2–brine–rock reaction was confirmed to occur rapidly (maybe less than 0.5 h) during supercritical-CO2 fracturing in shale reservoir with high temperature and pressure. Minerals, such as calcite, dolomite, K-feldspar, and albite, were variably dissolved after the soaking of CO2-saturated brine. Mineral composition, reaction time, temperature, pressure, porosity, and permeability evidently influenced rock reactivity. Stronger reaction likely occurs in carbonate-rich shales of relatively high porosity and permeability. Mineral dissolutions resulted in numerous large etched pores, which eventually caused the significant increase in porosity and permeability (up to one order of magnitude), and decline in tensile strength (up to 71.3%) and surface friction coefficient (9.8%). Calcite-filled natural fracture can be corroded more deeply than the matrix, which has the potential to affect the growth behavior of supercritical-CO2-induced fracture when it intersects with the natural fracture.

Impairment mechanism of thickened supercritical carbon dioxide fracturing fluid in tight sandstone gas reservoirs

Non-aqueous supercritical CO2 (scCO2) fracturing stimulation techniques have acquired much attention in the development of tight gas reservoirs recently. However, few researches have devoted to the impact of scCO2 fracturing fluid on permeability and relevant mechanisms. In this study, phase behaviors of thickener polydimethylsiloxane (PDMS) and co-solvent kerosene in scCO2 were studied. The regained permeability investigations reveal that the low filtrated volumes of scCO2 fracturing fluid have instant and major deterioration of sandstone permeability. The regained permeability ratio reaches the equilibrium with the further increase of filtrated volumes. The compositions of scCO2 fracturing fluid also have impact on the regained permeability. Another regained permeability tests demonstrate that slick-water causes more permeability damage to lower-permeable samples, while scCO2 fracturing fluid causes more permeability damage to higher-permeable samples. The relevant mechanisms are proposed. XRD in clay swelling tests detects the existence of the clay minerals in the tight sands and eliminates the potential of clay swelling effect of scCO2 fracturing fluid. Our investigations indicate the operational feasibility of scCO2 fracturing fluid in tight gas reservoirs and the addition of high content of co-solvent should be avoided as to maintain the low permeability damage to gas reservoirs.

Numerical analysis of the effect of natural microcracks on the supercritical CO2 fracturing crack network of shale rock based on bonded particle models

SummaryThe problem of predicting the geometric structure of induced fractures is highly complex and significant in the fracturing stimulation of rock reservoirs. In the traditional continuous fracturing models, the mechanical properties of reservoir rock are input as macroscopic quantities. These models neglect the microcracks and discontinuous characteristics of rock, which are important factors influencing the geometric structure of the induced fractures. In this paper, we simulate supercritical CO2 fracturing based on the bonded particle model to investigate the effect of original natural microcracks on the induced‐fracture network distribution. The microcracks are simulated explicitly as broken bonds that form and coalesce into macroscopic fractures in the supercritical CO2 fracturing process. A calculation method for the distribution uniformity index (DUI) is proposed. The influence of the total number and DUI of initial microcracks on the mechanical properties of the rock sample is studied. The DUI of the induced fractures of supercritical CO2 fracturing and hydraulic fracturing for different DUIs of initial microcracks are compared, holding other conditions constant. The sensitivity of the DUI of the induced fractures to that of initial natural microcracks under different horizontal stress ratios is also probed. The numerical results indicate that the distribution of induced fractures of supercritical CO2 fracturing is more uniform than that of common hydraulic fracturing when the horizontal stress ratio is small.

Research Progress of Thickening Agents for Supercritical CO<sub>2</sub>

Although supercritical CO2 fracturing has incomparable advantages compared to hydraulic fracturing as a new recreating technology of shale gas reservoir, the application of this technology has been limited by the low viscosity and weak carrying capacity of proppant. It’s critical to enhance the viscosity of supercritical CO2 by adding thickening agents. Thickening agents for supercritical CO2 thathave been studied by researchers mainly contained polymers, small molecular compounds and surfactants. Thickening agents that match with CO2 are characterized by low cohesive energy density, low polarity, high free volume and Lewis base. It’s necessary to study the interaction between thickening agents and CO2 by molecular simulation to design inexpensive, green thickening agents which could increase the viscosity of supercritical CO2 remarkably under low concentration.