Haynesville vs. Barnett

Is My Shale Better Than Your Shale?

American Association of Petroleum Geologists (AAPG)

Action in the red-hot Haynesville shale play in North Louisiana continues on the fast track.

Operators find it darn near irresistible, given that recent wells have registered IP rates exceeding 20 MMcf/d.

“The tremendous production rates of some early wells are no doubt related to the higher formation pressures observed within the Haynesville section,” said Kevin Ferworn, vice president at GeoMark Research in Houston. The company is a geochemical laboratory with considerable experience in oil and gas analyses.

It’s a perspective that has led Ferworn to a conclusion: For a variety of reasons – including those geochemical – the Haynesville Shale has a bit of an edge on its Barnett relative.

“Typical Barnett shale downhole pressures are plus-or-minus 0.45 psi per foot, while Haynesville sections often exceed 0.9 psi per foot,” Ferworn said.

“In situ oil/gas cracking and superior seal capacity are the big contributors to the increased pressures in the Haynesville,” he noted. “Each can be identified using mud gas isotope geochemistry.”

During oil analysis, researchers use high-resolution instruments to look at specific molecules in the oil called biomarkers, which live in the relatively heavy fraction of the oil. These biomarkers help to determine the nature of the source that generated the oil and gas.

In other words, the oil produced today contains diagnostic markers from the source.

“Gases are more difficult to type because there are so fewer molecules in gas,” Ferworn said. “Important things we can measure are the stable isotopes of carbon and hydrogen molecules.”

Wanted: Maturity

Methane is the lightest and most abundant of the many hydrocarbons that make up natural gas. A methane molecule consists of one carbon atom surrounded by four hydrogens (CH4). The carbon atom itself contains six protons and either six or seven neutrons in its nucleus – these are the stable isotopes of carbon versus the unstable C14, which decays over time.

The ratio of how much C12 there is relative to C13 can be measured to reveal crucial information about the formation gas, according to Ferworn.

“That ratio changes with the type of organic material laid down in the source rock in the first place,” he said, “and it’s especially important with the thermal maturity of that source.

“When you get to shale plays, what’s important from a geochemist’s point of view is whether there is enough organic material in the shale in the first place,” Ferworn said, “and did it get mature enough to break down into lots of gas.

“Isotopes help us answer that question,” he noted.

The idea is, the longer and hotter an oil and gas source rock gets buried, the more mature it becomes. The first thing that starts to form is bacterial methane, which is similar to methane from rotting vegetation in a landfill.

Using a maturity marker scale based on carbon isotope ratios, one can see that as temperatures increase with deeper burial, the oil window is encountered before going into still hotter deep dry gas.

“If you get a sample of gas from a shale play and measure the carbon isotope, you may get a certain value on the maturity scale and track it down,” Ferworn said, “finding the source left the oil window and moved into the gas window.

“Combined with actual source rock data, a calibration scale for all the different shale plays is developed” he said, “so the isotopes can be used to say if the shale got mature enough to make lots of gas.”

An ‘Effective’ Seal

The samples that are analyzed fall into two different categories. One consists of produced gases, but the most common approach is to capture gases during the drilling operation, where they are sampled from the mud stream.

The gas is separated out and sub-sampled before going to the mudloggers gas chromatograph, which analyzes how much hydrocarbon gas is caught up in the mud stream.

In increasingly high maturity shale gas wells, ethane and propane isotopes show a reverse, or “rollover,” shift on the analysis graph when it’s thought they shouldn’t.

“We think this shift is caused by gas that stays trapped in the shale,” Ferworn said. “The big gas molecules start cracking into more, smaller molecules, so things like ethane, propane, butane are breaking down into more methanes.

“This makes for drier gas,” he noted, “and more small molecules in the same space make the pressure go up. You see this kind of behavior in a nice mature section of the Barnett.

“In looking at a single well in the Haynesville play, once we break into the Haynesville, it’s about 99 percent methane gas – the bigger molecules have broken into lots more methanes,” Ferworn said. “At that point the well encountered a significant overpressure.

“The one important thing we see inside the Haynesville versus the Barnett is the magnitude of the shift of the ethane isotopes,” Ferworn noted. “It’s the biggest of any shale play we see.

“This is telling us that whatever the seal is – whether in the shale itself or something on top of the shale – it’s the most effective seal we’ve seen in any of the shale plays,” he said.

Haynesville vs. Barnett

The integrity of the seal is strikingly obvious when evaluating hydrocarbons in wells that tapped into reservoirs above both the Barnett and Haynesville.

The Barnett leaked considerably, which was documented by identifying Barnett-sourced oils in younger, shallower reservoirs.

Not so for the Haynesville.

Hundreds of oils in the GeoMark collection that have been chemically typed were used as a reference point to determine there were no Haynesville-sourced oils in any shallower reservoirs across the play.

“This makes you think more of the hydrocarbons generated in the Haynesville stayed in the Haynesville,” Ferworn said. “In the Barnett, you’re getting residual hydrocarbons that were not expelled into other reservoirs.

Another favorable aspect of the Haynesville is the presence of increased amounts or reservoir rock type minerals.

“You have more shale in the Barnett relative to the Haynesville,” Ferworn said, “and shale has very low permeability. Neither are 100 percent shale, but the Haynesville has more reservoir rock mixed in.

“When you get some reservoir rock mixed with the shale,” he said, “it enhances the permeability, providing pathways for the gas to escape. Even where you have fractures, the gas still has to migrate through the formation to get to them.”

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GCAGS Spotlights Shales

Kevin Ferworn will present the paper “Haynesville Shale Gas – Why Is It Better Than the Barnett,” during a day-long symposium on the Haynesville and other shale plays set for the Gulf Coast Association of Geological Societies’ annual convention.

The GCAGS meeting will be held Sept. 27-29 in Shreveport, La.

The symposium is set from 8 a.m. to 4:30 p.m. Sunday, Sept. 27, at the Shreveport Convention Center, featuring 17 talks on the Haynesville and other shale plays. Ferworn’s talk begins at 11:10 a.m.

Other talks include:

Martin B. Payne on “The Haynesville Play: A New Opportunity to Prove the Strategic Value of Natural Gas in Peak Oil Mitigation”(see related story) .

  • Roger M. Slatt on “Workflow for Stratigraphic Characterization of Unconventional Gas Shales.”
  • Thomas E. Ewing on “Ancestral Basin Architecture: A Possible Key to the Jurassic Haynesville Trend.”
  • Robert G. Clarke on “Haynesville Remains Popular While Other Shales Slow.”
  • J. Daniel Arthur on “Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale.”

The GCAGS meeting theme is “A Fusion of Geology and Technology,” built around papers and posters dealing with the Wilcox Formation; seismic applications and salt tectonics; Gulf Coast sedimentation and coastal subsidence; old fields and new plays; shale resource plays; and visualization, geochemistry and interpretation of geologic systems.

Emphasis: Gulf Coast

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