Hydraulic fracturing has drawn intense interest inside and outside the industry, but far less attention has been given to what will happen in the decades of production to come.
The answers from a panel to the question, “So We Frac’d the Well, Now What?” indicated there is a long list of things to figure out.
“The day a well is turned over to the sales department is just the beginning of a long life,” said Joe Cardenas, stimulation technical manager at XTO, which is part of ExxonMobil.
“From a production engineer’s viewpoint, we are looking at reservoir predictions and wondering if we will be able to meet those predictions,” said John Patterson, global production engineering chief for ConocoPhillips.
“The oil we are bringing out is the gas and light ends. We are bringing out the gas that is the driver and the light ends that are the solvent” but leaving heavier oil behind, said George King, distinguished engineering advisor at Apache. “We ought to worry about that a little.”
“We are only getting to what questions we should be asking” when it comes to understanding unconventional reservoir performance, said Tom Blasingame, petroleum engineering professor at Texas A&M University.
The professor offered a condensed critique on the challenges of estimating what oil and gas is likely to be recovered. While he said there are plenty of reasons production decline curve analysis is a poor proxy for the reality of an unconventional reservoir, he said he has come to accept its place.
“This is the way we are communicating with auditors, students, and the public,” Blasingame said. What he said he is hoping for is a new generation of computer modeling capturing the complexity of reservoirs, but the computing power to run a simulator based on that complex reality would be staggering.
“It would require a 10,000- to 100,000-fold increase in data-processing power” over current simulators, he said. “I do not think that you are going to bolt things on to the current modeling technology.”
While reservoir engineers debate whether the ultimate recovery rates are realistic, production managers are trying to deliver on those projections. Several speakers said unloading the water will be critical; however, how that will be accomplished remains an open question.
“Can I put in a lift system that would last the life of the well?” Patterson said. The goal is to have a single installation because it may well be hard to justify the cost of installing a second one given the natural decline in these wells. Long-term monitoring will help questions about whether differences in the slope of wells—those drilled on an uphill grade accumulate water differently than those drilled downdip—will affect future production.
Well operators will need to adjust to changes in the environment around the well also. Cardenas told of a well drilled by XTO in 2005 in what was then an isolated spot outside Fort Worth, Texas. Two years later, there were 100 homes in a subdivision within 300 ft. By last year, there was residential development on three sides of it.
“Our risk of hazards has significantly increased for this pad site,” he said. On the surface, that would require methods to abate noise or respond to complaints about emissions.
A common thread in all of this is the requirement for good data, which means those responsible for wells also need to look over what flows in because bad data is a constant risk, said Lwanga Yonke, information quality process leader for Aera Energy.
To manage the data flow in a heavy-oil operation that drills and completes 1,000 wells a year in California, the company depends on employee involvement. They are expected to play a role in data quality and analysis so that it can be widely used.
“We talk about stewardship of data, not ownership,” Yonke said. “What you own you keep to yourself and do not share.”