Hydraulic fracturing of unconventional oil and gas resources is inefficient with recoveries at less than 15 percent. One of the limitations to improving efficiency is the lack of knowledge of the fundamental properties of the fracture network generated by hydraulic fracturing operations. In the field, the ability to observe fracture and flow consists mostly of microseismic data on the number and location of fracture events. As valuable as these data are in delimiting the location and extent of fracture clouds, they provide neither the resolution nor the detail required to provide an understanding of processes occurring in unconventional reservoirs. In this task, the objective is to conduct experiments at reservoir conditions that provide fundamental insights into fracture growth, penetration, permeability, and surface area as essential components of developing methods of improving hydraulic fracturing performance in the field.

Key objectives:

1. Evaluate the relative significance of tensile fractures directly generated during hydraulic fracturing and shear fractures activated by hydraulic fracturing in permeability and hydrocarbon production.
2. Measure surface areas of tensile and shear fracture systems using microfluidics and triaxial coreflood systems and relate this to fracture-matrix interactions and the production of hydrocarbon. 
3. Replicate fracture systems created in the triaxial experiments within shale microfluidics models and investigate the efficacy of hydrocarbon removal by brine. 
4. Integrate results of x-ray tomography characterization, acoustic emission analysis of fracture formation, surface area data on fracture penetration, and sweep efficiency to create understanding of how fractures propagate, penetrate, and ultimately liberate hydrocarbon. 

Los Alamos National Laboratory (LANL), Los Alamos, NM 87545

Experimental studies of fracture-permeability relations generated under in situ reservoir conditions are limited. Most studies of hydraulic fracturing have used triaxial devices to examine rock mechanics (stress-strain behavior) and acoustic emissions associated with rock damage. Key features of hydraulic fracturing remain unexplored in these experimental studies. What are fracture properties (aperture and geometry) at reservoir conditions? How permeable are these fractures, and how does permeability evolve with fluid flow and time? What is the surface area of fractures in relation to the amount of matrix and hydrocarbon that can easily diffuse into the fractures? How does the injected working fluid migrate into and sweep hydrocarbon out of the fracture system? 

LANL will make use of unique experimental capabilities in a triaxial coreflood system with at-conditions x-ray tomography and high-pressure microfluidics. These allow the research team to overcome limitations of earlier work by making direct observations at in situ conditions so that fractures are generated and characterized without changing the environment. This removes the ambiguity created by ex situ analyses where fracture properties may change following decompression (e.g., apertures may open or fractures may even be created). The research team uses these in situ observations to characterize fracture density, connectivity, surface areas, and permeability.

LANL combines simultaneous triaxial-induced fracturing and x-ray tomography with a high-pressure microfluidics system for direct optical observations of fluid flow behavior to provide a unique opportunity to investigate the dynamics of fracture initiation and growth, fluid movement, and hydrocarbon production. This effort will yield new insights into how applied stress, fluid pressure, and injection dynamics impact fracture penetration, apertures, and permeability. The project will correlate acoustic emission activity with tomographic observations of fracture growth to enhance field understanding of microseismic surveys. Finally, this study will yield basic understanding of how to effectively displace and mobilize hydrocarbon from complex fracture networks.

Chesapeake Energy has supplied Utica shale core from the unconventional plays in Ohio and Pennsylvania. The researchers have data on the mineralogy, porosity, and organic carbon content of these samples. In addition, they have acquired Marcellus shale in outcrop.

Researchers developed a novel technique for inducing hydraulic fractures in a triaxial device. Previous studies have required specialized equipment or sample geometries, but LANL’s approach works with standard rock core and allows permeability measurements of the fracture system. The researchers have conducted simultaneous fracturing of shale in a triaxial device while conducting x-ray tomography imaging, an experimental first that will be key to understanding in situ fracture properties. They have developed and implemented an acoustic emission system to monitor fracture development.

Researchers have made numerous measurements of fracture permeability of Utica shale conducted in traditional compression experiments and using direct shear methods. These have provided detailed information on the effect of confining stress (or depth) and time on fracture permeability and evolution. Fracture permeability tests were performed at high effective confining pressure and showed that in spite of substantial sample shortening, permeabilities remained less than 1 mD until the pressure was released.

The researchers have conducted preliminary sweep efficiency experiments with a high-pressure microfluidics system to characterize hydrocarbon removal during water injection and developed improved fracture etching methods for representing complex fracture networks in shale. An experimental study that quantifies permeability of fractured, carbonate-rich Marcellus shale (Bedford Quarry, Pennsylvania) was completed. A newly modified version of LANL’s triaxial direct-shear device was used, which enabled improved resolution of permeability as well as a quantification of uncertainty of the permeability measurements. The results of the experiments demonstrate the importance of considering the stresses at which fractures are created when predicting the permeability of fractured, low permeability rocks. In LANL experiments on a carbonate-rich Marcellus shale, LANL investigated triaxial direct-shear specimen permeability as functions of: 1) increasing stresses at which fractures are created through initially intact material; 2) increasing confining stress on an existing fracture; 3) increasing shear displacement across an existing fracture; and 4) combined time-dependent effects such as mechanical creep, chemical precipitation, and particle mobilization.

• The effect of increasing the stress at which fractures were created was most significant.  
• Increasing the effective confining stress on an existing fracture was also found to cause permeability reduction.  
• Increasing the shear displacement across an existing fracture had varying effects, dependent upon the effective confining stress and magnitude of displacement.  
• Permeability after fracturing was generally observed to decrease with time.

In addition, experiments were completed on one Marcellus core, which was acquired from the Marcellus Shale Energy and Environment Laboratory (MSEEL). The sample lithology is much more clay-rich than what was used in previous experiments. Core preparation has begun for this study, which involves subsampling the 4"-diameter slabbed material to create 1"-diameter core that the research team used in the triaxial device. The team will conduct experiments similar to previous work but will apply new approaches of characterizing the tributary fracture zone (TFZ). The team worked with the quantification of fracture-network permeabilities as well as examining the impact of reservoir stress conditions on fracture permeability and the integration of tributary fracture zone properties with Discrete Fracture Network (DFN) simulations.  

A workflow was developed to help integrate tributary fracture zone properties with DFN simulation. In principal, this integration allows laboratory measurements from fractures at the centimeter scale to be related to larger fractures at the meter to kilometer scale and to be populated in the DFN model.

Using experimental data on the TFZ, LANL has also developed a methodology to incorporate diffusion and advective flow mechanisms in the TFZ to perform simulations on the influence of various transport mechanisms. These include simulations of matrix diffusion in the TFZ; simulations of the extent to which the TFZ consists of natural, reactivated and induced fractures; and simulations of the percentage of free hydrocarbon in the primary fracture network. The main conclusions of this study were that:

1. Matrix diffusion in the region of the TFZ significantly impacts production within the first year itself.
2. Depth of TFZ fracturing region had no effect on the shape of the production curves, although the total mass of the hydrocarbon produced increases with the depth.

An additional set of experiments using a relatively carbonate-rich sample of Marcellus core acquired from MSEEL were used to identify critical stresses associated with the transition from highly transmissive to weakly transmissive fracture systems. In the field, this critical stress is a function of the depth of the shale, fracture orientation, and pore pressure. The results of the experiments demonstrate the importance of considering the stresses at which fractures are created when predicting the permeability of fractured, low-permeability rocks.  

LANL has also performed experiments on multiphase fluid flow processes and has examined the impacts of fracture geometry and fluid properties on the recovery of hydrocarbons from complex fracture networks. LANL has also considered the role of matrix properties in the release of hydrocarbons into the fracture network. To this end, exploratory experiments were conducted investigating how surfactant impacts frack fluid interaction with the matrix and how surfactant impacts oil recovery in fracture networks. These experiments were conducted using a microfluidics system operated at reservoir conditions with temperatures at 50 oC and fluid pressures of 10 megapascals (MPa). Shale samples from an unconventional reservoir were sliced into thin wafers and then etched to produce fracture geometries for the study of fluid migration and oil production. Preliminary experiments show that LANL can measure fluid transport through the shale matrix allowing for the calculation of effective permeability, capillary barriers among other properties.

LANL completed experiments showing how changes in effective stress (e.g., as produced during pressure drawdown) created changes in fracture permeability for Marcellus shale.  The decrease in hydraulic aperture as a function of effective confining stress was fit using Barton-Bandis theory.

LANL has identified potential critical drawdown conditions that can close fractures and found
MSEEL core may be near critical stress. We investigated previous experimental results on
fracture closure with the aim of determining the conditions under which closure is important.  To do this, LANL developed a fracture-system model containing the well, the hydraulic fractures and natural fractures.  The impact of fracture closure depends strongly on the value of a in the equation below, the fracture-stiffness coefficient: 

b=b₀exp(aσ’n)

Where b₀ (initial fracture aperture) and a (fracture stiffness) are experimentally measured values specific to the reservoir or basin of interest and b is the calculated fracture aperture as a function of the effective stress σ_n.

Capabilities are being developed to handle methane gas in both microfluidics and triaxial coreflood experimental facilities. This will allow for a more realistic investigation into multiphase flow processes and allow researchers to assess the behavior of “live oil” systems. In particular, revised experimental protocols will provide more direct feedback to the development of pressure management strategies that maintain permeable pathways and allow for sustained hydrocarbon transport and production.

LANL has also continued work on experimental investigation of the permeability of Marcellus shale with a focus on MSEEL core material that was received from NETL. This work is part of a larger effort by the team to develop stress-fracture aperture permeability relations to support optimized pressure management strategies. LANL also completed experiments showing how changes in effective stress (e.g., as produced during pressure drawdown) created changes in fracture permeability for Marcellus shale.
 

LANL worked on the integration of large-scale fractures, tributary fractures, and the matrix to best utilize natural fractures. LANL has performed discrete fracture network simulations to relate the dependence of network structure and the apparent dissolution rates in geochemical reactions. Silica dissolution was used as the model reaction. Permeability and mineral volume fraction relationship was also incorporated to allow for changes in permeability as silica dissolves. The project has completed all tasks and milestones and will terminate on June 30, 2022.

Budget Period 1 – DOE Contribution: $700,000
Budget Period 2 – DOE Contribution: $700,000
Budget Period 3 – DOE Contribution: $800,000
Budget Period 4 – DOE Contribution: $973,100
Budget period 5 – DOE Contribution: $800,000

Planned Total Funding:
DOE Contribution: $3,973,100
 

NETL – Bruce Brown (Bruce.Brown@netl.doe.gov or 412-386-5534)
Los Alamos National Laboratory – Bill Carey (bcarey@lanl.gov )

Mechanistic Approach to Analyzing and Improving Unconventional Hydrocarbon Production - Part 1: Tributary zone fractures (small-scale) contributions to hydrocarbon production in the Marcellus shale (Aug 2018)
Bill Carey, Los Alamos National Laboratory, 2018 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA

Experimental Study of In Situ Fracture Generation and Fluid Migration in Shale (Aug 2017)
Bill Carey, Los Alamos National Laboratory, 2017 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA

¹ The original FWP was designated FE-406/408/409-14-FY15 and lasted two budget periods through 3/0216. Subsequent FWPs that extended this research include FE-722-16-FT18 for budget period 3 through 3/2018; FE-954-18-FY18 and FE-954-18-FY18 R1 for budget period 4 through 12/20; and FE-954-20-FY21 for budget period 5 through 9/21.