Rethinking Fracturing: The Problems With Bigger Fracs in Tighter Spaces
- Stephen Rassenfoss (JPT Emerging Technology Senior Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 2017
- Document Type
- Journal Paper
- 28 - 34
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The Problems With Bigger Fracs in Tighter Spaces
When a new well is being fractured, anyone with a producing well nearby needs to look out for hits.
The hydraulic pressure used to fracture a new well is likely to be felt in older wells nearby because fractures tend to grow toward zones where the pressure has been depleted by production.
“It is unrealistic to expect total avoidance in formations such as the Eagle Ford, Woodford, and Bone Springs,” said Mike Rainbolt, completions engineer, senior advisor for Apache Corp., adding “let me rephrase that—it is impossible.”
The risk of a hit is high in those plays in Texas and Oklahoma because hydraulic fracturing there is likely to create long planar fractures, whose growth can be magnified by aggressive fracturing designs used to maximize liquids production.
Damage caused by “frac hits” is the high-profile problem that has fanned interest in the larger, but less obvious issue of how fracturing affects the reservoir between tightly spaced wells. Rainbolt presented a 43-page paper by Apache (SPE 187192) at the 2017 SPE Annual Technical Conference and Exhibition in October, which offered a broad look at the problem with examples and ideas on how to manage it.
The impact of a hit can be big and immediate. The Apache paper included a look at a well whose production dropped 65% after a hit and remained down until it was treated.
But these fracturing-driven interactions may only be apparent with production analysis. Apache’s study found one pair of wells where the area fractured by the second well overlapped with the original well. As a result, it said “the existing well could have produced the reserves without the infill well.”
Stressed About Production? Consider a Chemical Cocktail
Field testing is beginning to confirm laboratory work that indicates it is possible to achieve significant spurts in unconventional oil production using cocktails of chemicals.
BHP Billiton has pumped a blend of chemicals along with low-salinity brine to pressure-up shut-in wells. The result of these jobs, intended to reduce the risk of damage due to fracturing nearby, has been higher production lasting for months, including an estimated 20,000 barrels of oil from one well (SPE 187420).
Apache used its chemical blend to speed recovery of wells that had production bashed by frac hits. Positive results led to tests on underperforming wells that delivered strong, but short-lived, production gains (SPE 187192).
“You have a chance of getting your well back,’ said Michael Rainbolt, completions engineer, senior advisor for Apache Corp. who presented the findings at the 2017 SPE Annual Technical Conference and Exhibition.
Early tests using familiar chemicals and delivery methods have been reported in which the cost and the technical challenges associated with running a test are relatively low.
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