Passive Microseismic Optimizes Oil and Gas Production

By Susan Eaton

New Technology Magazine, July/August 2008 - In the hunt for oil and gas, exploration geophysicists detonate dynamite or use thumper trucks, actively sending seismic sound waves into the ground to measure acoustic reflections from subsurface geological formations. But what do development geophysicists do when conventional seismic data can't image dynamic changes -- on the scale of millimetres to hundreds of centimetres -- within oil and gas reservoirs as they respond, over the life of the field, to temperature and pressure changes from enhanced oil recovery operations using steam, water or CO2 injection?

A new breed of Canadian geophysicists -- we'll call them earthquake seismologists -- has adapted technologies used for decades in the mining sector, and is passively listening to seismic sound waves emanating from mini-earthquakes in response to subsurface oil and gas production activities. During the past decade, Vancouver-based Weir-Jones Group and Kingston-based ESG Canada Inc. have tested their earthquake monitoring systems in Alberta's oilpatch -- today, their passive microseismic monitoring (PMM) technologies are being used to optimize oil and gas production in Canada and around the world.

Whether it's high pressure cyclic steam stimulation in Alberta's oilsands, a waterflood at Ghawar, the world's largest oilfield in Saudi Arabia, CO2 injection for enhanced oil recovery at Weyburn, Saskatchewan, or a 100-tonne hydraulic fracture operation to prop open tight gas sands, in all cases the reservoir's tensile strength is exceeded. As they strain, the rocks pop, crack and shear, creating mini-earthquakes ranging from zero to negative three in magnitude (in comparison, San Francisco's Great Earthquake of 1906 measured eight in magnitude).

Temporary and permanent multi-level arrays of high resolution microseismic sensors -- installed down wellbores near the reservoir, or distributed close to the surface in shallow boreholes, respectively -- measure dynamic changes in oil and gas reservoirs and pinpoint these acoustic events in x-y-z space and time. Each sensor location, known as a "level" in the vertically-deployed arrays, is comprised of tri-axial (or multi-component) geophones, oriented along the x, y and z axes. The arrays are conveyed down the wellbores and boreholes using either wireline or coiled tubing.

"We're talking about microseismic events that are the equivalent of the amount of energy from a firecracker," says Doug Bleakly, ESG Canada's manager of U. S. Marketing and Sales. Stated another way, these small noises or energy bursts in geological reservoirs -- induced by injecting fluids or gases under high pressure -- are on the order of less than one billionth of magnitude of recorded earthquakes. Geophones manufactured for PMM applications are of extremely high fidelity, with broad bandwidths approaching 500 hertz, enabling them to record acoustic data up to a kilometre from the epicentres of these mini-earthquakes."

Oil and gas geophysicists are usually trained in active seismic techniques and are relatively unfamiliar with microseismic theory and application," explains Bleakly, a geologist. "Microseismic applies earth seismology to the oilpatch. Geophysicists understand active -- not passive -- seismic, so part of our job is education."

ESG (which stands for Engineering Seismology Group) grew out of a geophysical consortium, struck during the late 1980s, between the mining industry and Queen's University in Kingston, Ontario. For the past decade, beginning with the Cotton Valley Consortium in East Texas in 1997, ESG has used microseismic to map hydraulic fractures for oil and gas operators in Canada and the United States.

Since 2002, ESG has worked with Alberta's oilsands operators, using microseismic to monitor dynamic changes in and around this unconventional reservoir as it responds to cyclic steam stimulation (CSS) operations. Passive microseismic monitoring records, in real time, where the rocks fail or fracture, usually near the leading edge of the steam flood in the reservoir. From an environmental perspective, PMM technology has also been successfully used in Alberta's oilsands to monitor the integrity of casing in injection wells and of the shale cap rock layer which contains the steam within the reservoir.

Most recently, ESG has applied its PMM technology to map the thermal response of oilsands to steam-assisted gravity drainage (SAGD) operations. "In SAGD, you inject steam at lower pressures than CSS," says Bleakly, citing this significant difference between the two thermal extraction methods. "This lower pressure, combined with other factors, results in smallermagnitude events that create challenges for deployment and detection."

Smart wells and intelligent fields

"The Ghawar field has everything going against it for 4-D seismic data acquisition," says Shivaji Dasgupta, microseismic project manager with Saudi Aramco's Exploration and Petroleum Engineering Center. He says the geology at Ghawar has precluded the use of conventional, time lapse 4-D seismic data to optimize production parameters over the life of the field.

Aramco is currently injecting seawater into the flanks of this giant field, which measures 250 kilometres long by 30 kilometres wide. Given that Ghawar's Arab-D carbonate reservoir produces about five per cent of the world's oil supply, premature water breakthrough in wells -- due to sub-optimal waterflood operations -- poses serious commercial problems for Aramco.

According to Dasgupta, a geophysicist, the seismic signature (or the acoustic impedance contrast) of the seawater replacing the produced oil is extremely low; therefore, the advancing waterflood cannot be mapped using conventional seismic data. Further, conventional seismic data can't image certain rock properties, including the presence of micro-fractures and micro-faults which may play a key role in the waterflood. "Passive microseismic monitoring doesn't really care about the rock properties," he explains. "It measures the fluid pathways along the dynamic front of the waterflood.

"Ghawar is wired for data acquisition," says Dasgupta, describing the 2007 installation of a multimillion-dollar PMM system which covers a nine-square-kilometre area. Aramco drilled 225 holes that were 14 feet deep into the bedrock of the Haradh Desert, and cemented permanent arrays of tri-axial geophones down the holes. A dedicated network of recording systems -- one for each of the borehole sensors -- was buried underground for safety reasons.

More than 70 kilometres of composite power and fibre optic communications cables were buried in trenches and connected to high speed wireless communication links, enabling the transmission, in real time, of large volumes of microseismic data, to a processing centre. Ghawar's entire PMM system -- hardware and software -- was manufactured by Terrascience Systems Ltd., a member company of the Weir-Jones Group.

In addition to the widely distributed system of buried sensors, two observation wells were drilled, one to 400 feet and a second to 3,500 feet (the Ghawar Arab-D reservoir sits at 6,700 feet). Thirty arrays of permanent tri-axial sensors were cemented at various levels in these two dedicated "listening" wellbores, which were also equipped with temperature, pressure and flow gauges. The cement bond in the wellbore provides a very quiet environment for the geophones to listen and to record perturbations in the reservoir.

In order to calibrate the PMM system, Aramco pulsed the injector wells at varying rates and observed immediate changes in the reservoir's acoustic properties -- the microseismic data indicated clear trends parallel to the irregular sweep of the waterflood, and sub-parallel to fracture directions in the area. Describing this pilot project as "proof of concept," Dasgupta says: "Now that it's working, it's giving us a huge benefit." Despite early encouragement, however, Aramco intends to monitor the reservoir's mini-earthquakes for several years prior to expanding its PMM network at Ghawar.

The downhole arrays in the two observation wells, combined with the grid of 225 sensors over the study area, enables Dasgupta to look at what's happening -- in a map view -- between the producing and injector wells, which are approximately one kilometre apart. "We are looking at putting intelligence in wells and fields," says Dasgupta. "It's becoming imperative for us to do this -- we need to continuously monitor the pathways of water to the wells."

From his office in Dhahran, Dasgupta can monitor the microseismic data being collected 24 hours a day, seven days a week, at Ghawar. "All the systems are online, and the operator has instant accessibility to the reservoir's performance data -- it's brilliant," says Iain Weir-Jones, founder and principal of the Weir-Jones Group.

While Dasgupta calls Terrascience's PMM installation at Ghawar "the world's largest," Weir-Jones suggests that his company's decade-old passive monitoring installations in Alberta's oilsands at Cold Lake are equally large. Weir-Jones describes this technology as "Life of Field" and says it's an order of magnitude more cost-effective than conventional 4-D seismic data that requires repeated deployment, throughout the life of the field, of seismic source and geophone arrays.

Houston-based Mark Puckett is the Schlumberger Wireline Geophysics Domain Champion for the U. S. Geomarkets -- simply put, Puckett is the chief wireline geophysicist for Schlumberger in the States. In May, Puckett benchmarked two PMM technologies -- Schlumberger's wireline sensors in a horizontal wellbore and Terrascience's permanent sensors cemented in widely distributed shallow boreholes -- to document the reservoir response to different hydraulic fracturing techniques in the Bakken formation of North Dakota.

"You're going to live with the stimulation footprint [of the hydraulic frac] for the life of the well," explains Puckett. "It's very important, in these unconventional reservoirs, to understand how the reservoir [is] responding to stimulation, in order to improve the recovery factor."

The $14-million Bakken Research Consortium, led by Headington Oil Company and supported by Schlumberger and the North Dakota Oil & Gas Research Council, involved the drilling of three horizontal wells in a 640-acre spacing unit, into the Bakken formation at around 9,000-feet depth. Additionally, a widely-spaced pattern of shallow boreholes was drilled consisting of 18 holes that were 300 feet deep and three 1,500-feet-deep wells for the downhole placement of permanent geophone arrays.

The Schlumberger multi-component sensor array was deployed in the central of the three horizontal wellbores -- this well was the designated observation well -- to passively monitor hydraulic fracture operations in the other two horizontal wellbores. When production rates decline in the two producing horizontal wells, they will be hydraulically re-fractured -- both Schlumberger's wireline and Terrascience's permanent senor arrays will record these operations. Approximately $5 million of the consortium's total capital budget was dedicated to PMM technology applications.

According to Puckett, observation wells need to be situated within half a mile (800 metres) of treatment wells in order to adequately monitor hydraulic fracture propagation in geological reservoirs. However, in the relatively unexplored areas of the Williston Basin and the Western Canadian Sedimentary Basin, wells are often spaced too far apart, rendering them geophysically unsuitable to record mini-earthquakes propagated during hydraulic fracture operations designed to exceed the reservoir formation's pressure.

Oil companies are reluctant to compromise nearby producing wellbores by turning them into temporary monitoring boreholes, and they're even more reluctant to drill an offsetting well simply to monitor hydraulic fracture propagation. Puckett points to another factor driving the use of permanent PMM installations -- today's horizontal wellbores have extremely long reaches, often exceeding one mile in length.

"We can't always get close enough to the wellbore," says Puckett, with respect to using wireline sensors that are deployed downhole during the frac operations. "Therefore, we have to look at alternative expressions of microseismic monitoring to evaluate hydraulic fracs."

Yet, given that observation and treatment wells should be no farther than half a mile apart, in a lateral sense, how can geophone arrays, deployed down shallow listening boreholes that are one to two miles distant -- in a vertical sense from the Bakken reservoir below -- adequately record the mini-earthquakes propagating during hydraulic fracture operations?

"In a wellbore, you're limited to the tools you can use -- there's a tradeoff when you miniaturize," explains Puckett, describing how the Schlumberger geophones and their external housings have been shrunk in size in order to clamp to the side of the wellbore's production casing. Adds Puckett, "When we move to the surface [shallow boreholes], we have many more options for sensors, when it comes to their sensitivities."

Paul Anderson is a senior geophysicist with Apache Canada Ltd.'s Exploration and Production Technology group in Calgary. Anderson started using PMM just a few months ago, and he has been on a steep learning curve ever since. He's used observation wells -- including the re-entry of old wellbores -- to deploy ESG's multi-component sensors to map hydraulic fractures in unconventional reservoirs, including tight gas sands and Apache's emerging shale gas play in northeast British Columbia. "As a technique, it has a lot of promise," he says. "We're in the early stages, but the PMM data seem to be lining up with some of our early assumptions."

"In general, I think that the technology is sound -- we just have to learn how to use it properly for oil and gas applications." However, Anderson cautions: "There are some technical issues that need to be addressed -- specifically, the building of the seismic velocity model for the real earth medium."

As a geophysicist, he says, he has difficulties with the value-added step of integrating the microseismic and conventional seismic data because there aren't appropriate software tools available in the marketplace to facilitate this integration. "We [Apache] are early adopters of technology, and we're open to work with the microseismic vendors to push the envelope," Anderson says.

Bleakly echoes Anderson's comments: "Microseismic today is probably where reflection seismic was in the 1960s or early 1970s. We've got a demonstrated track record," he adds, "and now we've got to take it to the next level, to get the absolute most out of the data -- that's our challenge for the next decade."

Susan Eaton (susaneaton@shaw.ca) is a Calgary-based geologist, geophysicist and freelance writer who manages her own environmental and energy consulting practice, SR ECO Consultants Inc.

CONTACTS FOR MORE INFORMATION

Doug Bleakly, ESG Canada
T: (925) 323-6296
E: doug.bleakly@esg.ca

Mark Puckett, Schlumberger
T: (281) 704-5015,
E: puckett@houston.oilfield.slb.com

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