Recovering the remaining oil in the subsurface is a basic common goal of producers and geoscientists.
To accomplish this, they must first identify the location of what is left to recover.
This effort can be especially challenging when dealing with unconventional reservoirs, where hydraulic fracturing and commingled production from differing horizons/formations are often the norm.
Enter “oil fingerprinting,” where geochemical differences between oil samples produced from different formations or zones can be used as natural tracers to quantify the contribution of each reservoir to a commingled production stream, explained AAPG member Mark McCaffrey, geoscience manager of interpretive services at Weatherford Laboratories in Dallas.
“The average black oil has more than 100,000 different compounds, and we measure about a thousand of them,” McCaffrey said. “Two different oils could be 99-percent similar in composition and still have 50 differences, so you can easily tell one oil from another – it’s like a fingerprint.”
This low cost oil “fingerprinting” method has long been used to geochemically allocate commingled production from conventional reservoirs.
It also has key applications for unconventional reservoir development.
Characterizing fracture height, for example, is a big deal.
An operator can determine if hydraulically-induced fractures have propagated out of the formation containing a lateral wellbore and into an overlying or underlying pay zone, resulting in commingling of oil produced from different reservoirs. In other words, determine if the fracture(s) outgrew its anticipated length.
Oil fingerprinting enables the operator to define what percentage of production is being sourced from each zone contacted by the induced fractures. This information, in turn, impacts the strategy for developing each of the horizons in the prospect.
In some instances, this quantitative allocation of individual pay zones to the commingled production stream is needed for royalty/tax calculations.
Then there’s the issue of identifying “cross-talk,” where induced fracture networks from separate wells completed in adjacent formations hook up with each other. This can occur when one well is drilled nearby another with each completed in a different formation, based on the belief that the fractures in the second well won’t be long enough to tie in with the fractures from the first.
The geochemistry of the oils produced from the two wells will indicate if “cross-talk” is occurring.
So, you ask, if you don’t want to deal with unanticipated occurrences like fracture system hookups and such, why not just space the wells a bit farther apart?
This may sound like a no-brainer, but there are other considerations that go into that decision.
For starters, operators like to drill wells close together for a number of reasons, both practical and financial.
Then there’s the likely fallout from retracting an announced plan to drill, say, 500 wells in a certain play over the course of the coming year. Suddenly declaring that the plan has been scaled back by half would have repercussions best avoided.
Oil fingerprinting can be used to decide if increased spacing is truly needed.
How It’s Done
Overall, oil fingerprinting follows a somewhat simple blueprint.
The procedure begins with dead oil samples collected at the earth’s surface using glass jars with Teflon-lined lids. The dead oil is evaluated using high-resolution gas chromatography (HRGC) to determine the abundance of the different compounds. Between 200 and 250 natural tracers are typically identified during an oil fingerprinting project, said McCaffrey.
“A key challenge in each project is the need to have a sample of oil that is certain to come from each zone,” he said. “These single zone pure oils are called end-member samples, and there are some great strategies the operator can use to collect these samples, which we use to calibrate each project.
“The relative contribution of each end-member oil sample to a commingled sample is calculated using a linear-algebra solution of simultaneous equations, where the number of equations equals the number of natural tracers,” he noted. “The accuracy of an allocation estimate is very high.”
He emphasized also that geochemical production allocation is dramatically less expensive than production logging and can be used in situations where production logging cannot be applied. For example, it can’t be used to assess the fracture height given that the logging tool cannot traverse upward through the fracture.
The relative low cost for the geochemical methodology allows field engineers to monitor output frequently over lengthy time periods. This enables the operator to stay on top of the individual zones’ changing contribution to the production stream.