Sensor Tech for Better Fluids Tracking

New resistivity sensor system can give oil and gas companies a better view of subsurface data and the movement of fluids within a reservoir

By gathering data between and far beyond wellbores at reservoir depths at the surface - with or without deploying instrumentation downhole - the San Diego-based GroundMetrics' technology can improve subsurface visibility, and allow oil and gas companies to optimize drill locations and boost the rate of drilling success.

The technology has applications for conventional and unconventional fields, and can be used as a compliment to seismic, or in place of seismic itself. It also can be used to keep track of fluids after a successful oil well is drilled, said George Eiskamp, CEO of GroundMetrics, in an interview with Rigzone. Even with enhanced oil recovery technology and know-how, the most oil that can be recovered in production operations is 50 percent.

Several factors are involved, Eiskamp said, but the primary reason is loss of knowledge on fluid distribution and movement. Traditional surface-operated resistivity systems are limited to shallow underground targets and industry standard low-frequency surface sensors do not work very well, if at all in many terrains. These terrains include sand, desert ice, frozen tundra, gravel, caliche, exposed rock, and volcanic rock, as well as extremely hot and cold environments, according to a company presentation.

Borehole and downhole systems also are limited by lateral range. As a result of these limitations, oil is bypassed or remains undiscovered, Eiskamp told Rigzone. Depending on the basin, the success rate in finding oil is 25 to 40 percent. Sixty to 75 percent of the time, water is encountered and not oil. "On average, only one-third of oil is produced before production is terminated," said Eiskamp.

SYSTEM ACTS AS MRI FOR MEASURING FIELD PROPERTIES

GroundMetrics' systems can see in between and far beyond wellbores, providing multi-mile resistivity imaging. The company's systems have a depth capability of more than 10,000 feet and a lateral range of over 2 miles from the boreholes.

On conventional oil fields, GroundMetric's technology measures electric field properties, determining whether fluid is conductive - which indicates water - or oil, which is resistive. Eiskamp compares it to taking an MRI.

"We can increase a company's drilling rate success by enabling them to identify fluid types," said Eiskamp. "We can also show them oil and water barriers and movement so they can get the most production. That's how we compare and contrast with normal seismic."

GroundMetrics' technology has been successfully tested on five oil fields, and has received positive reviews from independent parties. Last year, Chevron Corp. outlined in a public presentation the benefits the technology would have on hydraulic fracturing, with returns of 5 to 20 percent by optimizing frac fluid pumping. This doesn't include savings realized from drilling fewer wells, which is a major cost saver.

By using this technology, Eiskamp estimates the industry could realize savings of more than $20 billion per year.

Eiskamp said GroundMetrics' solution has great potential for hydraulic fracturing treatments, given the limitations of existing technology - microseismic, tilt, and tracer technology.

Microseismic relies on acoustic measurements related to the earth breaking. "The problem is that this can be misleading," Eiskamp explained. "In some instances, the ground breaking might not be loud enough for sensors to hear it, and fluids can move without microseismic picking it up."

Another problem is that microseismic might encounter natural fracture zones in the ground, but the ground stops breaking. So an operator could move into natural fractures without the ground breaking, and sensors wouldn't pick up on it. A third way in which microseismic can be misleading is that, while fluid is pushing up against rocks to break it, those rocks in turn are putting pressure on other rocks, which can create a split or break far from where the fluid is located.

GroundMetrics instead measures the electric properties of the fluid, rathering than monitoring vibration. In comparison with microseismic, which requires a 20 square mile array over a field, GroundMetrics technology also requires a smaller surface array of less than one square mile.

Another method, tilt, is precise, but limited by the terrain and proximity to the wellbore. Tracer technology can confirm or refute commingling between wells, but doesn't give information about conduit pathways, according to a company presentation. The company proved in a case study that it can trace where fluid actually goes in a hydraulic fracturing operation, and compared those results from microseismic and tracers.

In that study, GroundMetrics demonstrated the potential commercial benefits of its technology to minimize unproduced zones between wells and allow more oil to be produced. It can also reduce the amount of frac fluid needed and the number of wells drilled. While the technology will not likely replace microseismic entirely - some companies are just used to it - Eiskamp said he doesn't see a reason why it couldn't be widely used. The technology's cost is about the same as microseismic, delivering more value at the same cost.

Source: Rigzone

Media

Taxonomy

• Oil & Gas
• Technology
• Sensor Systems