What happens when carbon dioxide (CO2) is injected into deep geologic formations? Battelle is using fiber optics to monitor injection efficiency and seismic activity at CO2 injection sites in Michigan. The work is part of the next stage of research for the Midwest Regional Carbon Sequestration Partnership (MRCSP).
CO2 injection is used for carbon capture and storage (CCS) and enhanced oil recovery (EOR). Whether the goal is simply storage of unwanted CO2 emissions or utilization of CO2 for secondary oil production, understanding how CO2 moves through subsurface formations and fills geologic reservoirs is important. Monitoring injection activities allows operators to determine whether CO2 is filling up the reservoir optimally and see how much available pore space is left for further injection. Monitoring technologies also detect seismic activity that may be caused by subsurface fluid injection.
The geologic formations used for CO2 injection can be a few thousand feet or more underneath the surface, making characterization and monitoring challenging. During injection processes, seismic imaging is used to monitor where injected fluids end up. For CCS, monitoring is needed to track the movement of the injected CO2 and to make sure it stays in the geologic storage reservoir.
Seismic reflection surveys are the traditional method used by geophysicists to analyze the earth's structure. For seismic imaging, an energy source (such as a vibrator truck, also known as a weight-drop truck, or dynamite placed in shallow soil borings) is used to produce sonic waves that penetrate the earth and are reflected back from subsurface formations. The returning waves are recorded on geophones. Different materials (e.g. rock, soil and liquids) produce different reflection patterns, which can be interpreted to generate a picture of what is happening underground. Standard seismic reflection surveys use geophones placed on the land surface; however, placing the geophones in a monitoring well, a method known as vertical seismic profiling (VSP), provides better imaging resolution.
The new Battelle study is evaluating the use of fiber optic cables to replace geophones for detection of reflected sonic waves in VSPs. Fiber optic cables could provide a number of benefits over geophones for subsurface imaging:
Unlike geophones, which provide a single point of detection for each device, fiber optic cables provide coverage along their entire length, resulting in higher resolution imaging.
Fiber optic cables, because of their small diameter, can be permanently installed in the cement outside the casing of a well without significantly increasing the size of the well.
Monitoring wells using fiber optics installed outside casing can still be used for other purposes (e.g., injection or production).
Fiber optic cables can also be used to measure temperature, providing additional characterization data to assess fluid movement and other characteristics important to oil & gas producers.
Fiber optic cables provide similar imaging data to that provided by geophones, but rather than using changes in voltage, they use patterns of light to create the image. Light signals are sent down the cable (a process known as “interrogating the fiber”) and backscattered light comes back up. Patterns in this backscattered light are used to build an image of the subsurface or detect seismic activity.
The Battelle study is part of ongoing work with the U.S. Department of Energy (DOE) and the MRCSP. The Battelle-led MRCSP, part of DOE’s Regional Carbon Sequestration Partnership Program, brings together nearly 40 government, industry and university partners across nine states and has completed several CCS validation projects. The fiber optic monitoring study is a continuation of this work.
The study is being conducted in partnership with Core Energy LLC. Fiber optic cables were installed in February 2017 in a pair of 6,000-foot deep wells, including one CO2 injection well and one monitoring well, at one of Core Energy’s oil fields in northern Michigan. Core Energy has now started injecting CO2 at the site to re-pressurize the reservoir for EOR, a process that will take 18 to 24 months. Battelle completed a baseline VSP study prior to the start of CO2 injection. Researchers will conduct a repeat survey after a year of CO2 injection to create images that show how the CO2 moved within the reservoir during the one-year injection period. The fiber optic system will also be used to monitor injection activities, including changes in temperature caused by injected CO2. Battelle researchers are interested in using temperature data to determine rock properties.
Battelle will use the data from this project to evaluate the fiber optic systems. If the technology proves to be effective, fiber optics may soon give operators and researchers a better way to monitor injection activities for CCS and EOR, as well as to monitor CO2 in geologic reservoirs several thousand feet or more below the surface.