Opportunities and challenges for supercritical CO2 as a fracturing fluid

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Schematic of a fracturing system highlighting induced and natural fractures and three primary gas-­‐in-­‐place origins of methane. The length scales involved in shale gas production cover thirteen orders of magnitude, ranging from nanometer size pores where methane is trapped, and sometimes up to kilometer long fractures that are conduits to the production well. An alternative fracturing fluid such as supercritical carbon dioxide (CO2) may more efficiently extract gas from (1) and (2) because CO2 is miscible with hydrocarbon, thereby preventing multi-­‐phase flow blocking, and from (3) because CO2 can exchange with methane that is sorbed to kerogen (insoluble organic material).

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Hydraulic fracturing of shale formations in the United States has led to a domestic energy boom. The process of injecting a fluid – typically water – into a target formation at pressures high enough to fracture the rock, is performed to increase permeability and thereby increase production. Currently, water is the only fracturing fluid regularly used in large-scale commercial shale oil and gas production in the U.S. Industry and researchers are interested in non-aqueous working fluids due to their potential to increase production, reduce water requirements, and to minimize environmental impacts. Theoretically, widespread use of non-aqueous working fluids could have a transformative impact on the U.S. energy industry and energy security. However, the science behind non-aqueous fracturing fluids is still relatively immature. Researchers in LANL’s Earth and Environmental (EES) Division have published a paper in Applied Energy examining opportunities and challenges to producing gas from tight shale formations (Figure 4).

The very small permeability of these formations prohibits efficient extraction using conventional methods. In addition, concerns about the use of water (e.g. water-availability, treatment or disposal of contaminated flow-back water, and induced seismicity) have encouraged increased exploration into the use of non-aqueous fracturing fluids such as supercritical CO2. Therefore, the Los Alamos researchers used a combination of new experimental (Figure 5) and modeling (Figure 6) data at multiple scales to analyze the benefits and drawbacks of using supercritical CO2 as a working fluid for shale gas production.

To evaluate the contribution of fundamental mechanisms to shale gas production, the team performed simulations using a novel reservoir-scale discrete fracture network (DFN) modeling approach that LANL developed, in which reservoir fractures are modeled as a set of two-dimensional planes in three-dimensional space with specified shape, orientation, aperture, and permeability. The subsurface flow simulator PFLOTRAN, a massively parallel code, calculated the pressure solution in the network. Particles representing gas packets are uniformly distributed throughout the network, and their travel time to the well is computed.

The paper theorized and outlined the following potential advantages of using CO2:

•Enhanced fracturing and fracture propagation as a result of more extensive and complex fracture networks when compared with water-based working fluids.

•Reduction of flow-blocking mechanisms (flow-blocking is hypothesized with the use of water due to high surface tension and subsequent blocking of pore throats).

•Increased desorption of methane adsorbed in organic-rich parts of the shale, due to the electrostatic moment that is present in the CO2 molecules, which may result in stronger interactions with organic constituents.

•A reduction or elimination of the deep re-injection of flow-back water that has been linked to induced seismicity and other environmental concerns.

The advantages of using CO2 could have a significant impact over time, leading to substantially increased gas production. Some concerns remain with using supercritical CO2. These include costs and safety issues associated with handling large volumes of supercritical CO2. However, the use of CO2 has the potential to increase production while lowering environmental impacts. If CO2 is proven to be an effective fracturing fluid, then shale gas formations could become a major utilization option for carbon sequestration of this greenhouse gas.

Reference: “Shale Gas and Non-aqueous Fracturing Fluids: Opportunities and Challenges for Supercritical CO2,” Applied Energy 147, 500 (2015); doi:10.1016/j.apenergy.2015.03.023. Authors include: Richard Middleton, Jeffrey Hyman, Qinjun Kang, Satish Karra, and Hari Viswanathan (Computational Earth Science, EES-16); Bill Carey, Mark Porter, and Joaquín Jiménez-Martínez (Earth System Observations, EES-14); and Robert Currier (Physical Chemistry and Applied Spectroscopy, C-PCS).

The Laboratory Research and Development (LDRD) program and DOE’s Unconventional Fossil Energy Program managed by the National Energy Technology Laboratory’s Strategic Center for Natural Gas and Oil funded different aspects of the work. The research supports LANL’s Energy Security mission area and the Information, Science, and Technology and the Materials for the Future science pillars through the development of means to increase gas production and for carbon sequestration. Technical contact: Richard Middleton

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First­‐of‐a-­kind microfluidic experiment of etched shale micro-model experiment at high pressure and temperature (8.62 MPa and 50 °C) with the displacement of water (white) by supercritical CO2 (black). Injection from left to right occurs a at constant flow rate (0.1 ml/min).

(Left panel): Results from a reservoir-­‐scale modeling approach to obtain production curves through fracture drainage. The figure shows pressure solution in the discrete fracture network. A network of 376 natural fractures based on data from the upper Pottsville formation (Alabama) is generated in a domain of size 200 x 200 x 200 m. A horizontal well is placed in the center of the domain. Six equally spaced fractures perpendicular to the horizontal well are created to represent hydraulically generated fractures. A pressure of 21 MPa is applied to the boundaries parallel to the horizontal well while a pressure of 17 MPa is maintained at the well. The simulation tracked 100,000 particles. Only1,000 pathways are shown for visualization purposes. The pressure gradient between the boundaries and the well draws the gas packets towards the well. (Right panel): A selection of the particle trajectories. Physically, these particle exit times represent the initial fracture drainage out of the network.