Surprise! Hot Spots Also Can Be Sweet (Spots)

American Association of Petroleum Geologists (AAPG)

Geoscientists have expended considerable effort in the quest to nail down the technology needed to predict “sweet spots” in the unconventional shale plays.

At the start of the now-phenomenal shale play bonanza, the thinking in general was that the rocks were homogeneous across an area of interest.

Then reality set in as the shale E&P players came to realize via the drill bit that heterogeneity rules, and homogeneity and uniformity are not even bit players in the big picture.

Instead, these dense rocks can vary considerably even from one well to the adjacent well, which adds considerable intrigue, aka risk, to leasing and drilling.

Seismic data often are used to evaluate a prospective area’s potential to produce. But this is expensive, so it’s often wise to first use some less pricey alternatives to get a grasp on what to anticipate.

These other methods include remote sensing, integrated organic/inorganic petrography, gravity, magnetic and various types of thermal maturity data to initially identify those areas with higher production potential.

Once the geoscientists get a better handle on prospectivity, they can then opt to apply more esoteric and expensive technologies like seismic.

A Different Heat Source

A whole new and promising (and inexpensive) scientific approach is being touted as an effective way to help to zero-in on sweet spots.

Janell Edman
Janell Edman

Thus far, the research and findings appear solid. Yet the still-controversial concept likely will stir up considerable debate in the industry, according to AAPG member Janell Edman, principal at Edman Geochemical Consulting in Denver.

“In separate studies,” Edman said, “experts have independently come together on the concept of using a combination of less expensive screening technologies to identify areas of localized high heat flow where recurrent movement of basement faults in areas already known to contain rich source rocks results in the maturation of hydrocarbons by hydrothermal fluids.”

“The published findings indicate that at both a mega- and a micro-scale, an internally consistent genetic model can be developed,” she said, “showing in multiple diverse locations that unconventional play sweet spots are often related to hot spots.”

She compared this to the general model for generating hydrocarbons where you have organic matter in the source rocks and conductive heat coming up from the basement into the sedimentary section. That heat matures the organic matter causing hydrocarbon generation.

“In the crust, you have radioactive elements that generate heat that comes up via conduction into the sedimentary section,” Edman emphasized, “and that’s the source of heat for most hydrocarbon models, or basin models based on burial history.

“But in our work, we actually have fluid movement, and that heat from the hot fluids is causing maturation of organic matter,” she said, “so it’s just a different heat source.

“Convective heat from the fluids is causing the generation.”

Convection Versus Conduction

The two types of heat transfer are quite different.

With conduction, the transfer of heat occurs slowly from the bottom to the top of successive rock units that are in direct physical contact, according to Edman. With convection, there is a rapid elevation of temperatures in multiple rock units simultaneously due to the relatively unconstrained movement of hot fluids.

She emphasized that convective heat flow via hydrothermal fluids is much more efficient than the transfer of heat by conductive heat flow.

Igneous activity in the shallow crust is more common than people realize, according to Edman, who noted that it’s this igneous driver that’s the ultimate origin of the hydrothermal fluids.

“The flow of hydrothermal fluids into the sedimentary section can be attributed to conduits provided by recurrent movement on faults and lineaments that extend to the basement,” she added.

In other words, the two major components needed to find the hot spots leading to prediction of potential sweet spots are:

An igneous driver for the hydrothermal activity.

A system of naturally occurring faults and fractures acting as conduits for the hydrothermal fluids.

Shopping for the Right Sensor

Besides serving as conduits for hot fluid flow, natural fractures can be important to create areas of increased permeability.

Given the plethora of techniques used to try to pinpoint areas with production potential, Edman emphasized the importance of using a combo that works best in a particular area.

For example, in an area with dense vegetation, remote sensing is not the way to go.

And it helps to have a well or two to allow for petrographic evaluation.

“I have a photomicrograph that shows carbonate cement that came in with hydrothermal fluids,” Edman said. “Then you have these trails of oil, fluid inclusions included in that carbonate cement showing that you had generation of that oil at the time the hydrothermal fluids moved in.”

There’s more.

Edman noted that AAPG member Dan Jarvie and his colleagues demonstrated in 2011 that the oil at Parshall Field in North Dakota was generated in situ.

“That’s what we’re saying,” she added. “If you look at biomarker data that Dan did, it showed that those biomarkers are at the proper level of heating we’re finding by the organic petrography.

“A lot of people think the hydrocarbons migrated in from the west where the Bakken is more thermally mature,” she commented. “But if you look at these biomarkers from Parshall Field, they aren’t all that mature.”

Edman and her colleagues have some convincing examples from the Eagle Ford at First Shot Field in Texas and the Parshall and Stanley fields in the Williston Basin showing that better production is related to areas of localized convective heat flow.

“This is a great inexpensive way to look for sweet spots in these unconventional plays,” she said. “If you do use seismic, it can help you identify those areas where you want to spend your money for it.”

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