The best thing to be said about frack hits is the phenomenon provides an interpretive framework for everyone and every scenario.
Attend enough meetings, read enough papers and it is apparent that frack hits have no long-term effect on production; have a negative production impact and cannibalize reserves, creating uneven reservoir drainage; or, counter-intuitively, produce a positive production outcome.
It is evident the industry remains in the dark about the issue. It is hard to find two accounts from the same basin that even agree on the percentage of frack hits as the industry moves to infill drilling—let alone how best to approach the issue.
Some operators claim success avoiding the phenomenon via preloading and repressuring while others argue such impacts are illusory and amount to robbing Peter to pay Paul. There is agreement on the causes, which include slickwater-associated greater proppant loading, tighter spacing (both between laterals and between stages in a single lateral), higher fluid volumes and an emphasis on near-term production maximization, or net present value.
The frack hit debate continued at this year’s SPE Annual Technical Conference and Exhibition in Dallas. E&P companies have experimented with a variety of approaches over the last half decade ranging from fracture and flow, small parent well preloads, higher rate water parent well preloads and refractures.
Consultant Ali Daneshy argued for a more precise definition of well interference to incorporate same well or intrawell versus offset or interwell interferences. One redistributes production between stages and generates patchy reservoir production while the other reroutes production between wells.
Substituting the term “well interference” for “frack hits” or “well bashing” opens the phenomenon to characterization that has definable attributes and therefore becomes eligible for engineered solutions. Attributes can range from simple pressure increases in offset wells to fluid and/or proppant communication to, in extreme cases, damaged downhole completion or production equipment.
In the Eagle Ford, one defense mechanism is spacing with well interference more common in laterals less than 122 m (400 ft) apart. That said, well interference, in one instance, was observed as far away as 610 m (2,000 ft). Go figure.
And that is exactly what the industry is doing. Techniques include far field diversion, which is achieved by multimodal particulate diversion in a pill comprising mixed sized proppant. The pill controls fracture length at the extreme and confines the stimulation field. The pill is pumped before increasing proppant and fluid volumes.
Large particles build bridging near the fracture tip while medium- and small-sized proppant pack the tip to create a mechanically strong, low permeability barrier, creating a pressure dip on the far side. Far field diversion pills reduced frack hits in the Eagle Ford Shale from 64% on 233 stages in 11 wells to 16%, according to a team from Schlumberger.
Daneshy suggested shortening fracture length by reducing fluid volume and increasing spacing, employing cemented liners for better well control, and drilling and cementing adjacent laterals before stimulation via zipper fracture or simultaneous operations and placing wells on production.
BHP Billiton preloads the parent well and pursues a parallel development infill program, spending less upfront capital and generating payout more quickly in the Eagle Ford’s Karnes Trough and in the Permian Basin. Parent wells experienced a 25% increase in production over time versus control wells after infill fractures in parallel completion versus a 40% production decline in parent wells using other methods.
The irony? BHP Billiton is selling its U.S. acreage.
Richard Mason’s Market Intelligence column originally appeared in the November 2018 edition of E&P.
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