Going with the Flow: Universities, Operators Team on Flow Assurance Research

Just how cold can waterflood fluids be? How can E&Ps and service companies improve costs and production and anticipate unwelcome oil slugs in declining gas lift wells? These are questions being addressed by university researchers in association with the oil and gas industry, looking for ways to make production more efficient.

Using cold water

Is it possible to use water from inside the Arctic Circle as waterflood fluid in an over pressured reservoir without precipitating gas hydrates? And if hydrates do form, do they affect the productivity of the formation? An operator in the icy waters of the Barents Sea asked Luis E. Zerpa at the Colorado School of Mines to find out. Zerpa is associate department head in the school’s petroleum engineering department and director of the Center for Rock & Fluid Multiphysics.

Hydrates are crystalline solid, gas and water molecules formed at low temperatures and high pressures. When they form, the solids clog the pores in a formation, blocking both waterflood and production. In the case Zerpa studied —because the zone was a greenfield — the operator was considering a number of development options including waterflooding to maintain reservoir pressure above the bubble point to prevent the release of dissolved gas. As such, the operator needed to create conditions in which the flood would work without causing more problems.

Zerpa said the formation is shallow, just 250 m below the sea bottom, and is in 400 m water depth offshore Norway’s northern coast. The formation’s depth and latitude combine to keep its temperature around 17 C. The temperature of the water is barely above freezing, ranging from 2 C to 5 C, depending on the season.

For the test, Zerpa said, “We did core-flooding experiments on a large core, which was 3 inches in diameter and 10 inches in length.” 

They distributed 10 pairs of acoustic sensors,1 inch apart, “traveling across the core’s diameter.” The research team sent an acoustic wave into the core to measure the wave’s transmission velocity across the sample. Any solid hydrates formed would transfer the signal faster than the liquid, allowing researchers to “hear” how hydrates form inside the core.

Researchers simulated reservoir conditions in the core by injecting it with a live oil mixture and subjecting the core to increasingly colder waters, dropping the temperature one degree Celsius at a time. 

“When we cooled it down from 8 degrees C to 7 degrees, we formed hydrates, which we could detect as we saw the waves traveling faster across the core,” Zerpa reported.

Further testing revealed that the injected water, even at 8 C, had some compatibility issues with the formation water, requiring treatment on the former before it would work. 

Testing indicated the best interaction with the formation’s hydrocarbons came when the water was at or above 8 C, and when it had been treated for compatibility with the formation’s water. Because the nearby seawater never rises above 5 C, the operator will always need to warm the water before injecting it into the formation. 

Fiber optics to track the slug

The Permian Basin is populated with an estimated 40,000 horizontal unconventional wells, many minimally producing, mature gas lift wells. A Texas Tech University petroleum engineering professor said that if the industry learned to produce those wells more efficiently, it would reduce capex and opex on a large scale while boosting production. He is setting up a testing procedure on the campus to analyze the issues and propose solutions, and he is creating a consortium of industry members to support the research.

Proper operation of gas lift—whether plunger lift, intermittent gas lift, plunger-assisted gas lift , gas-assisted plunger lift, or other options—requires understanding and dealing with multi-phase fluid flow in pipes. While the wells that options for improvement have been studied for years, much remains to be learned, said Smith Leggett, assistant professor in the Bob L. Herd Department of Petroleum Engineering at Tech.

To that end, Leggett has spearheaded the formation of the Texas Tech Gas Lift Consortium to “address challenges associated with the widespread implementation of intermittently operating gas lift technology in horizontal, unconventional wells” both offshore and onshore. The consortium includes a significant list of producers and service companies that are contributing funds and technology.

The three most pressing goals for the consortium are to finding ways to reduce opex by reducing lift gas requirements; reducing capex by deferring artificial lift conversions; and increasing production by minimizing bottomhole pressures.

The consortium is using a novel approach — track the slug — in its research, which Leggett said will also inform offshore flow control. 

“We are tracking liquid slug production using distributed fiber optic sensing,” he said. 

An on-campus test well is being used to study how fiber optics could be used to detect and mitigate slugs before they surface. 

When a fiber optic cable is run downhole, “the entire fiber itself is the sensor.” 

Then, a short pulse of laser light is shot into the fiber. 

“As that laser pulse travels down the fiber, a portion of the light backscatters. So, based on the two-way travel time of the light in the fiber, you can know where those reflections of light are coming from,” he said.

Because the return signal is the sum of the reflectors along the entire length of the cable, “You can look at that backscattered signal and get a temperature measurement every meter along the cable,” Leggett added. 

Researchers can also pick up tiny stretches in the fiber generated by acoustic waves, providing acoustic measurements every five meters. With the cable strapped inside or outside of the pipe, researchers can “listen to the liquid slugs as they’re being produced and learn to characterize them based on the noise and temperature changes they generate,” Leggett said.

Offshore applications

Offshore production using gas lift generates pockets of fluid that build up in risers or in subsea pipelines. Normal flow involves a series of small slugs that come to the surface in a rapid-fire pattern. But, Leggett said, where there are valleys or other variations in the line the small slugs can aggregate into a large single slug that overwhelms the surface separator — straining the surface systems designed to handle the production. 

This situation is known as terrain-induced or riser-induced slugging. The goal is to use their fiber optic test well learnings to develop an algorithm capable of detecting them well before they surface. That information could allow operators to choke back the flow to prevent damage. 

Research is in the early stages, Leggett said. 

“A good research system involves the introduction, motivation, results and conclusions. We’re not yet to the results and conclusions piece,” with the first round of results and conclusions expected in fourth-quarter 2024, he said.