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Battelle Oil & Gas Newsletter

Battelle Oil & Gas Newsletter

Geomechanical Assessment and Modeling to Reduce Fluid Injection Risks

What happens when you inject fluids deep into the earth? As the oil and gas industry expands the use of fluid injection for production, storage and disposal and CO2 storage and Enhanced Oil Recovery (EOR) technologies are developed, building a better understanding of subsurface structures and geomechanics is critical. Battelle is working on several projects that are shedding new light on the storage capacity of subsurface formations and mitigating the potential risks associated with deep geologic fluid injection. The results will be used to set safe injection limits and pressures and help oil & gas companies make better subsurface resource management decisions. 

In a study co-funded by the U.S. Department of Energy’s (DOE) National Energy Technology Laboratory and the Ohio Coal Development Office (OCDO), researchers are developing a geomechanical framework in the northern Appalachian Basin and surrounding Midwestern regions. The study is led by Battelle researchers Joel Sminchak (Principal Investigator) and Neeraj Gupta. The three-year project, which began in 2014, uses geophysical data, petrophysical data and laboratory test results to inform assessment of reservoir and geomechanical stresses and development of models for the area. The objective is to discover how faults, fractures and seismic stability affect carbon dioxide (CO2) injection potential and long-term storage security. Researchers will characterize the paleo-stress/strain setting, define geomechanical parameters, evaluate the potential for (and effects of) subsurface deformation, and ultimately assess CO2 storage potential based on geomechanical constraints.

 Battelle is also conducting a large-scale CO2 storage test in Michigan as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP). Battelle has led the MRCSP since 2003, and completed three successful small-scale carbon storage field tests between 2003 and 2009. As part of the current large-scale test, researchers have already evaluated and monitored more than 600,000 metric tons of CO2 injection in oil-bearing formations in Michigan, where CO2 produced from natural gas is being used for enhanced oil recovery by research partner Core Energy, LLC. The testing includes monitoring microseismic activity at injection pressures that exceed discovery pressure in the isolated buried reef structures to evaluate maximum safe CO2 storage potential in these highly depleted oil fields. 

Over the last decade, the use of fluid injection for both production and resource management has risen significantly. Hydraulic fracturing (fracking) and Enhanced Oil Recovery (EOR) methods inject millions of gallons of fluid underneath the surface to stimulate production. Brine produced over from these processes is often disposed of through deep geologic sequestration, or injection into sedimentary formations deep under the earth. The same technique can be used to sequester and store CO2 captured from power generation or other industrial activities. Geologic storage is seen as a potential solution to reduce greenhouse gas emissions and safely dispose of produced brine and wastewater where it cannot impact freshwater reserves or damage the environment.

However, the potential risks associated with fluid injection and geologic storage have not been fully characterized. Safe fluid injection requires an understanding of storage limits and safe injection pressures specific to each formation. Operators must also understand the geomechanical stability of the area. Better models are needed to map the storage potential of specific regions, characterize risks associated with geomechanical instability, and predict the impact of stresses caused by the injection of fluids into these deep formations. Battelle’s work will help answer questions such as:

  • Does fluid injection have the potential to cause surface uplift?
  • Does geomechanical instability in the region threaten the integrity of long-term storage formations?
  • Could fluid injection for production cause fracturing in the caprock that could lead to eventual escape of stored CO2 or brine in the formation?
  • Will fluid injection change hydraulic conditions near pre-existing faults, potentially leading to induced seismic activity?

Battelle researchers use coupled fluid-flow, geomechanical and fracture mechanics modeling in order to:

  • predict surface uplift by fluid injection and compare the predicted uplift results with measured satellite data to provide explanation and understanding of InSAR results;
  • predict stress changes by CO2/brine injection as a function of pressure and temperature variations;
  • predict and avoid the potential for fracturing in reservoirs and surrounding formations; and
  • investigate how injection of fluid, mainly in sedimentary formations, could cause seismicity deep in the crystalline Precambrian basement.

In addition to investigating the safety of brine disposal and CO2 storage, geomechanical modeling can be used to optimize production. Using geomechanics-fracture simulations, researchers can model hydraulic fracturing in a multi-staged hydraulically fractured horizontal well in shale formation to predict hydraulic fracture geometry and optimize hydraulic fracturing parameters (fluid and proppant volume and type).

Battelle researchers are continuing to refine geomechanical models in order to provide more accurate predictions for the oil & gas industry. Eventually, this work will lead to regional maps showing storage potential and injection limits for different parts of the formation. This data will allow the industry to more fully take advantage of the storage potential in deep geologic formations and mitigate the potential risks associated with fluid injection for both production and sequestration.