Fracturing/pressure pumping

Mapping Fracturing With Pressure Change

A  service using pressure data from a few nearby unconventional wells to map fracturing will soon be for sale.

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This rig is drilling in the Eagle Ford for Statoil, which has been using a method it developed to track the impact of hydraulic fracturing using wellhead pressure data at several nearby wells. It is now marketing the test to others.
Photo courtesy of Statoil.

A  service using pressure data from a few nearby unconventional wells to map fracturing will soon be for sale.

Statoil developed the method, and has used it to improve how it completes wells in three US unconventional plays, said Matt Dawson, investment manager at Statoil Ventures, which created a company to market the method, called Reveal Energy Services.

The approach assumes that in formations where most of the hydrocarbons are trapped in a dense, nearly impermeable matrix with a limited number of fractures, the pressure of the flow through those pathways can be measured in nearby wells.

The signals—a poroelastic pressure response—can be 10–100 psi, said Dawson, who also helped create the method.

The extremely limited flow in the formation, and the fact the monitoring wells are pressurized with water to protect them from the fractures growing from the well to be stimulated, ensures that the measurements are of “the pressure profile in the stimulated fracture,” he said.

With multiple surface measurements of pressure changes during fracturing—data from at least two wells are required, and more is better—Dawson said it is possible to measure the largest fracture’s length, height, and angle.

The method developed to track fluid flows through fractures has been used to evaluate Statoil wells in the Bakken, Eagle Ford, and Permian shales, and Dawson said “we are confident it will work in those three.”

More than one-third of the company’s wells in the Bakken were tested over a 12-month period, he said. Within a year he said they hope to be able to gather and interpret the data quickly enough for it to be used by crews as they are fracturing the well.

When Statoil researchers asked engineers in the field if they could try the test during fracturing in the Bakken, there were questions about how much it could complicate fracturing.

“It really turned out to be not very difficult to accommodate into normal operations,” said Darren Schmidt, a principal engineer in Statoil’s shale oil and gas research and technology group. The method requires setting plugs at certain times while fracturing, but if “you are zipper fracturing a well, you can fit this in normally on a multiwell pad and then get some good information,” said Schmidt, who was then doing completions.

Fracture analysis based on pressure readings has been compared by Statoil against 11 other diagnostics, including tracers, shut-in interference tests, and production rate transient analysis. Reveal is currently running a field test for an operator comparing its results with microseismic imaging, fiber optics, and electromagnetic imaging, he said.

The service, which has been used by several customers already, will likely be priced at the high end of the range from USD 10,000 to USD 90,000, Dawson said.

The method requires a pressure response from a limited number of fractures. It will not work in a conventional reservoir or in unconventional ones with extensive natural openings for fluid flow, such as the Barnett. A strong fracture hit into an adjoining well means data from that stage cannot be used.

Adding what has been learned about fracturing using pressure analysis to other observations led to changes in fracturing methods, from a shift in the sand size mix to better prop smaller openings to earlier deployment of diverter to more effectively limit growth of the largest fractures.

Fracture mapping “is another tool to help us better understand our fracture geometry with minimal cost incurred,” said Wesley Zurovec, a completions engineer for Statoil in the Eagle Ford.