‘It’s not just theoretical’

New Modeling Technologies in the Pipeline

American Association of Petroleum Geologists (AAPG)

Downhole reservoir monitoring is a concept that’s generated a lot of buzz.

Too bad it’s also generating a lot of fuzziness.

Part of the confusion comes from so many new tools and techniques jostling for the industry’s attention. And more developments are coming.

Fred Aminzadeh
Fred Aminzadeh

Fred Aminzadeh is executive director of the University of Southern California Reservoir Monitoring Consortium (RMC) in Los Angeles. He served as president of the Society of Exploration Geophysicists in 2007-08.

Aminzadeh listed 16 research areas of high importance for future reservoir work, ranging from integrated reservoir management to underwater acoustic communication.

The RMC has identified six of those for high-priority research, he said they are:

  • Optimized hydraulic fracturing for shale.
  • Physical models to monitor reservoir fluid.
  • Microseismic/micro earthquake (MEQ) to map reservoir structure.
  • Time-lapse petrophysics for reservoir monitoring.
  • MEQ and seismic integration for shale reservoirs.
  • Tomography-based reservoir modeling.

“It's not just theoretical,” Aminzadeh said. “Some of these things are being tested in the lab now.”

Geophysical Techniques

In its early days, conventional reservoir monitoring typically involved 4-D seismic and a comparison of static, analytic “snapshots” of the reservoir.

As monitoring advanced, the industry began looking for less expensive and more continuous techniques, with additional emphasis on temperature and pressure monitoring.

Aminzadeh described three categories of geophysical techniques used in reservoir monitoring, the physical properties they measure and the reservoir properties inferred:

♦ Type 1: Four-D surface seismic, vertical seismic profiling, cross-well seismic.

  • Physical properties measured – Changes in amplitude, arrival time, waveform.
  • Reservoir property inferred – Fluid saturation, pressure changes.

♦ Type 2: Microseismic or passive seismic.

  • Physical property measured – Rock shear failure with stress perturbations.
  • Reservoir property inferred – Fluid flow pathways, flow anisotropy.

♦ Type 3: Borehole and surface electromagnetic changes.

  • Physical property measured – Electrical resistivity changes.
  • Reservoir property inferred – Saturation 4-D changes.

The new or improved approaches now under development will not only expand the horizons of reservoir modeling, but should also strengthen the industry’s capabilities.

“Time-lapse petrophysics is something that’s not much talked about, but it’s very important,” Aminzadeh said.

“Tomography has been talked about a lot,” he continued, “but what has happened in the past is that tomography has been used to create a static picture of the reservoir.”

Microseismic Impact

Along with these developments, computing advances are playing an important role in monitoring, analyzing and understanding the reservoir.

“Since some of the changes in the reservoir are very subtle, advanced computing techniques need to be used to detect the changes,” Aminzadeh said.

One approach gaining attention is the use of microseismic in reservoir monitoring, often accompanied by separate temperature and pressure monitoring. Geologists probably are most familiar with microseismic in the form of monitoring of small-scale seismic events or its use for analyzing fracture patterns that result from hydraulic fracturing.

“Microseismic itself is still in its infancy in terms of using it as a tool to monitor the reservoir,” Aminzadeh said.

“It’s the type of thing that will be in demand for many types of applications in the future,” he added.

Shan Jhamandas is general manager-Western Canada for ESG Solutions in Calgary, a company that has provided microseismic monitoring systems since 1993.

“Microseismic is one of the few technologies that can give you a continuous picture of what’s going on in the reservoir away from the borehole,” Jhamandas noted.

“We can deploy it for the life of the reservoir, for the life of the asset. And that monitoring goes on 24-7,” he said.

In microseismic monitoring, an array of permanently installed sensors downhole and at the surface can detect signals associated with dynamic changes in the reservoir.

“Microseismic is grounded in earthquake seismology. As the rock reacts, it’s basically moving – it’s cracking, it’s shifting,” Jhamandas said.

Continuous methods of reservoir monitoring could produce an overflow of data if they captured and reported all available information. Jhamandas said microseismic will commonly focus on signals above a certain threshold: the background noise of the reservoir. That gives a continuing picture of changing dynamics.

“What’s great about it from a geophysical point of view is that with microseismic you can fill in those gaps in 2-D seismic, in 4-D seismic,” he said.

“From a geological viewpoint, what’s really interesting there is the different kinds of rocks in the reservoir and how they react to stimulation,” he added.

A related and growing application of microseismic monitoring is in carbon sequestration and CO2 injection programs.

“There’s a lot of concern from landowners and other stakeholders that the CO2 is going to escape somehow and even cause surface damage,” Jhamandas said.

Inching Toward Integration

ESG Solutions has 400 permanently installed, geophone-based monitoring systems around the world, about half of them in the reservoir environment in the oil and gas industry, according to Ted Urbancic, executive vice president of global energy services for the company in Kingston, Canada.

Urbancic noted that continuous monitoring has multiple benefits for the operator beyond optimizing production and maximizing reservoir life, including areas like casing failure, fracture spread and reservoir containment.

“If you have a breach of the caprock, that can be detrimental on a lot of levels,” he said.

He sees the future of monitoring moving toward the integration of seismic, pressure and temperature components, in approaches that would also include rock mechanics, geomechanics and other geoscience considerations.

“The level of application technology is increasing rapidly. There’s a big push toward integration of techniques to monitor and understand the reservoir,” he said.

Fiber Optics Potential

Another emerging development is the use of fiber optic technology in reservoir monitoring. Distributed temperature sensing (DTS), digital acoustic sensing (DAS), distributed strain sensing (DSS) and other techniques have just started to come into their own in the past five years.

Shell Canada conducted the initial downhole field trial of DAS fiber optics during completion of a tight gas well in 2009. In 2010, the world’s largest permanent offshore fiber-optic reservoir monitoring system was installed at Ekofisk Field in the North Sea.

A single fiber optic line can be treated to measure multiple parameters along its length. Fiber Bragg Gratings use ultraviolet inscription to create a systematic variation to the refractive index of the fiber core.

Distributed optic systems take their name from this distribution of sensing along the line length. With sensitivity to both strain and temperature, the treated fiber optic systems are gaining wider acceptance in reservoir monitoring.

As an added benefit, they withstand harsh temperature environments and corrosive environments without meaningful loss of capacity and are resistant to electromagnetic interference.

A substantial amount of research has gone into fiber-optic reservoir monitoring in recent years, but Urbancic thinks the technology isn’t quite ready for full uptake by the industry.

“In use with microseismic reservoir monitoring, using fiber optic technology on a regular basis is still a number of years off,” he said.

But the use of fiber optics for monitoring for pressure and temperature is increasing in oil and gas operations, according to Eric Holley, product champion in Calgary for Pinnacle, a Halliburton Co. business unit.

“It’s happening now – we’ve got a pretty intense schedule coming up in 2012,” Holley said.

“We’re seeing not only a lot of growth in the industry, but a lot more diversification within the industry in the area of fiber optics,” he observed.

Holley said fiber optics monitoring is even being utilized in shale-gas and heavy-oil reservoir environments.

DTS is the “bread and butter” application for Pinnacle, which is essentially Halliburton’s fiber optics arm, he said.

“I think the advances for DAS are going to be larger in the coming year,” he noted, “with the idea that it can be more of a complement to DTS.”

Microseismic monitoring and fiber optics sensing are only two of the many and varied approaches being applied to reservoir monitoring now. Other developments include:

  • The use of coiled tubing to deploy downhole sensors, including in-tubing DTS.
  • Ground-penetrating radar applications for monitoring.
  • Four-D microgravity for fluid monitoring and gas-injection assessment.

Beyond that, there’s the problem of high pressure, high temperature and the additional challenges of placing sensors in live wells.

And if anyone is starting to become comfortable with the current picture, Aminzadeh named a number of areas that could bring breakthrough changes in the future, including nanotechnology, signal processing developments, 4-D geophysics, cloud computing, advanced sensors and pattern recognition/artificial intelligence.

Today, downhole reservoir monitoring isn’t a practice than can be described easily, but one that requires monitoring.

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