The digital looking glass continues to show improvement as a tool for oil and gas companies simultaneously performing field operations while fine-tuning ops with virtual twins.
Core Lab and Halliburton combined their distinct methods of core sample evaluations to speed the process and give producers deeper insight into production decisions.
Core analysis testing is among the oldest assessment tools used in reservoir characterization and decision making. In recent years, Core Lab used computed tomography (CT) scans to digitize that data for analysis and archiving — collecting massive data sets from onshore and offshore oil and gas fields around the world.
At that same time, Halliburton combined pore scale digital imaging and fluid dynamics to address industry challenges such as predicting IP and EOR methods. However, laboratory analyses of physical core samples are also required—a process that can take several months. In the past, a combined physical and digital program required transporting a physical core sample from one laboratory to another.
Chris Tevis, vice president for wireline and perforating for Halliburton, said while the digital version alone could help with “log calibration interpretation and to accelerate the use of data in static or dynamic reservoir models,” it still requires physical lab analysis for the highest accuracy. By the time lab tests come in several months later, “those results will create questions about the original log interpretation. So, the earlier that a customer can get a quick look at data, the more it improves their base log interpretation and reliability.”
Tevis said combining pore scale imaging with numerical modeling can reduce the turnaround time on experiments to a few days or weeks depending on the complexity of the rock.
Joe Ramoin, Core Lab’s general manager for petroleum services, said the company uses digital imaging for different purposes.
“We’re looking at overall core quality, basic lithology, potential fractures or heterogeneity—things that may impact core analysis,” he said.
Combining the two workflows made sense, in Ramoin’s estimation, because “it streamlines processing. There’s no need to trade samples. You get both solutions in a more efficient manner.”
To enhance the two companies’ collaboration, announced Oct. 9, Core Labs and Halliburton are opening a joint space in Houston where samples can flow through both laboratories seamlessly. A grand opening is planned this December.
The need for speed
The watershed moment for this collaboration evolved from increased client activity due to carbon capture and storage (CCS) projects in the U.S., where there’s a tight window for permitting and technical review of data. Halliburton and Core Lab both understood that operators need trusted digital special core analysis data to obtain timely CCS permits.
“We decided we could partner well with Core Lab and combine our respective datasets to complement each other,” Tevis said.
Peering into pore throat
Micro CT and scanning electron microscopy systems collect data in a manner similar to medical CT scans, Tevis said. In the field, the difference is that systems use special lenses that examine rock pores up to one-10th the diameter of a human hair. This detail allows operators to study the flow of hydrocarbons, water and CO2 for CCS.
Most often however, he said, “It’s about resolving the pores and the tiny doors, or spaces connecting the pores, known as pore throats.” From there the view is extrapolated. “The key is to move up from pore scale to log scale to basin scale,” for more complete analysis.
Indestructible digital twin
Tevis and Ramoin saw the benefits of using digital twins in rock and fluid flow assessments. Software allows for unlimited digital testing of strategies for a long list of procedures including drilling and completions, fracturing, production and EOR options—all without harming or altering any actual rock samples.
Ramoin sees tremendous potential for reducing risk, especially in EOR. “Sometimes,” he noted, “clients want to conduct feasibility studies with different surfactants or different EOR mechanisms. The ability to simulate multiple scenarios quickly helps with decision making.”
In a lab environment, testing those options could take months rather than a few days or weeks.
Ramoin observed that only in the field will the true results be known, but digital testing can narrow down the choices to the methods with the greatest chance for success.
IPs can also benefit from the process, Tevis said — as Halliburton saw in North Dakota’s Williston Basin.
One client’s mature field production had become limited. After imaging the rock and examining the porosity and connectivity, the producer asked Halliburton to run simulations for relative permeability, capillary pressure and other properties.
Tevis said the test revealed “different layers of rock demanded different recovery techniques, so they used primary recovery fluids in one section and secondary recovery methods in another. With that, they were able to significantly improve production.”
For the future
While this collaboration is in its early stages, both parties are excited about its possibilities. To borrow a line from the classic movie “Casablanca,” the partnership “could be the start of a beautiful friendship.”
Ramoin said the future offers opportunities “for continued development by pulling measurements and modeling data together.” He foresees unique workflows designed to reduce risk by combining the digital and physical solutions, along with both companies’ extensive knowledge. The ultimate goal is to assess clients’ needs, “leading to better decisions and better wells.”
Tevis said, “As we see success in this partnership, I see it expanding to wherever our customers need us. Right now we’re focused on North America, but we see these markets and the opportunity going global quite easily.”
Those markets would include all types of oil and gas activity, along with CCS, geothermal and other energy and transition-related drilling and production.