Shale Producers Adopt Geochemistry Fingerprinting to Quantify Cross-Well Production
- Trent Jacobs (JPT Digital Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 2019
- Document Type
- Journal Paper
- 35 - 37
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Obtain a sample of reservoir rock, heat it up, add pressure, and then take a real close look at the drop of oil that comes out to find its unique “fingerprint.”
At a high level, this is the emerging extraction and geochemistry process that more than two dozen tight-oil producers have recently adopted to solve one of the shale sector’s biggest mysteries: how does oil flow through the rock matrix and into a hydraulically fractured horizontal well?
In a stacked formation, that question branches off into a few more: how much do neighboring horizontal wells communicate, which zones are co-producing the most, and how do these factors change over time?
“The ground truth comes when you collect rock, and know exactly what depth that rock comes from, and then extract hydrocarbons from that rock to know the fingerprint of that depth,” said Faye Liu, the founder and chief executive of geochemistry startup RevoChem.
Founded last year, the Houston-based firm has so far identified a geochemical fingerprint in more than 5,000 reservoir rocks and produced oil samples from more than 300 wells in nine different shale plays in North America and the Vaca Muerta Shale in Argentina.
Every new sample sheds a bit more light on the complex flow patterns of unconventional reservoirs. Among RevoChem’s findings is that pad wells placed in different benches of a tight reservoir stand a high chance of experiencing some level of cross-well communication (Fig. 1).
“All of your oil is a mixture coming from multiple zones,” explained Liu who was formerly a geochemist with Conoco Phillips. She noted that despite how they appear in modeling software, the evidence from geochemical fingerprinting shows that hydraulic fractures often extend out of their target zone and into other oil-rich layers of rock. “Essentially, every operator is experiencing the same process.”
A primary goal for adopters of the technology is to describe that vertical drainage in detail—and how the profile changes over time. “In a stacked development, every subsurface professional must be engaged with that understanding,” said Toby Deen, a senior engineer with private Permian oil and gas company Felix Energy, which started conducting time-lapse fingerprinting earlier this year.
In addition to vertical production allocation, operators are using geochemical fingerprinting to overcome the difficulty that other diagnostics have had in assessing the related parameter of fracture height. If wells are believed to have a fracture height somewhere in the range of 400–600 ft, then using wider distances between vertically separated wells to avoid interference is justified.
However, if the geochemistry shows that only 5–10% of the cross-well production is from the extreme tips of such a fracture network, then wider spacing may not be optimal (Fig. 2). What would make future spacing decisions easier is if an operator could prove that a majority of production is coming from an area just 200–300 ft away from the wellbore. “That means there is a lot of infill potential,” said Liu.
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