Unconventional Measures for Shale Reservoirs
Authors: Rassenfoss Stephen , Jacobs Trent 
Published: January 2017

Unconventional Measures for Shale Reservoirs
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
One of the biggest ways to lower the cost of production from shale would be to identify zones that are productive, or not, before fracturing them.
There is a growing group of companies selling new ways of cutting the cost and time required to gather data while drilling, which will allow completion engineers to reduce the number of stages producing little or nothing.
“I think better placement is where the money is,” said Vikram Rao, executive director of the Research Triangle Energy Consortium.
While the methods and data points vary, these new ventures are all seeking to gather data or samples during normal operations that can be quickly turned into a report on a limited number of data points, which can be used to improve fracturing productivity.
Customers “want it cheap, want it fast, and want to see a return quickly,” said Chuck Matula, a board adviser for Drill- 2Frac, a startup company created by Vorpal Energy Solutions, that uses data recorded while drilling to compare rock hardness along a wellbore.
It is competing with another newcomer, Fracture ID, whose website describes what it does as “drill bit geomechanics.” Both are selling rock property analysis methods that are lower-cost alternatives to accepted methods, such as well logs, whose price limits their use in unconventional plays. But the cost, data-gathering method, and output of these two methods differ significantly.
Others are relying on readily available, alternative sources of data: cuttings, fluids, or well pressure readings. They are hitting the market at a time when low oil prices have created an appetite for new ideas.
“Definitely we are exploring lots of technology options right now. Anything to drive down our dollar per foot completion cost,” said Kevin Wutherich, director of completions for Rice Energy. “We are even looking at stuff that could save USD 20,000 a well. We have a program that might yield 70 wells a year, so that is about USD 1.5 million. That might not have been too big a deal (when oil was at USD 100/bbl) but these days we will chase that down.”

Getting a Feel for the Rock
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
The force required to drill through a rock is a direct test of its strength and stiffness. Anyone who has ever used a power drill to drill through plaster and then hit a wooden beam can feel the difference.
Turning those feelings into a reliable measure of the properties of rock based on the force required to drill a long lateral is a large challenge.
Two startups, Drill2Frac and Fracture ID, are selling services that do that, though their methods vary based on the sources of the inputs and the outputs offered to customers. Both are offering an option that can become a routinely used diagnostic method by those designing fractures by providing information comparable to that from a sonic log, but at a significantly lower price.
Rock property information was also often a missing piece for those doing microseismic testing, which images the impact of fracturing based on the sound produced during certain types of fracturing. Users wanted better rock property information to improve the interpretation of the changes in microseismic data gathered around a well, said Chris Neale, president of Fracture ID, which uses downhole drilling data for imaging.
“When I was deep in the microseismic world I was very frustrated. I could not tell them what microseismic was telling them. There was no in-well data to correlate the microseismic,” said Neale, who was a cofounder of MicroSeismic Inc. “We needed an inexpensive data stream that could give us high-resolution rock properties for every well drilled.”
Data gathered while drilling offer a measure that avoids the time and logistical challenges of running a sonic logging tool into a horizontal wellbore or setting up surface receivers for microseismic.
These companies are building on work going back decades on formulas to quantify rock properties based on data gathered while drilling and rock property analysis.
In a recent paper (SPE 178842), BP described a formula that it developed to estimate pore pressures using drilling data. The work improved on formulas dating back to the late 1960s and early 1970s.

DNA Sequencing: A New Diagnostic Tool for Shale Wells
Trent Jacobs, JPT Senior Technology Writer
For the past 2 decades, the use of DNA sequencing technology has largely been relegated to the domains of criminal forensics and the healthcare industry. The company betting that the shale industry soon will join that list is Biota Technology, a California-based startup.
Founded in 2013, Biota says DNA sequencing technology can help maximize production in horizontal shale wells by directing operators where to place the wells, and how they should be completed.
“We are addressing questions that our customers can’t answer today across multiple scales: Where are the sweet spots and producing intervals for each stage, what is the fracture height for each well, and what is the connectivity between multiple wells?” said Ajay Kshatriya, chief executive officer of Biota.
Biota so far has used its technology on 60 wells operated by six different US producers. Its novel approach involves analyzing the DNA of tiny microbes that coexist with the oil, water, and rock in the subsurface. There are hundreds of thousands of different microbes living inside a formation but certain species are associated with hydrocarbons tend to stand out.
Their unique signatures and locations along the wellbore allow Biota to generate a production profile which can then be used to design engineered completions in subsequent wells, or to identify refracturing opportunities.
“Think of the DNA as a tracking device,” said Kshatriya. “It is a high-resolution data source that provides 4D analysis across the production life cycle, which doesn’t introduce environmental risk or require downhole tools.”
During a drilling operation, as many as 600 samples may be taken from a single well. These samples come from drilling mud and cuttings and provide baseline data needed to characterize the well as production begins and comingles all of the microbial DNA.

Grinding Out Big Data From Tiny Samples
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
When describing what Ingrain does for oilfield clients, the rock-testing company’s director of unconventional technology, Joel Walls, points out that it is “not just for science.”
He brings it up repeatedly because the company, known for being a pioneer in methods built on imaging ultratight rock at the core level, has built a business testing drilling cuttings to help identify productive, fracturable rock to help operators design better completions.
The pricing and turnaround time is designed to fit into the industry’s need to sharply increase the productivity of wells using better diagnostic testing at a time when drilling has greatly slowed.
“The asset teams and technology that remain in these (operating) companies are some of the best in the industry,” Walls said. With the slowdown there is time to consider what they need to do, plan, and do more testing. The testing is guided by the realization that production performance varies widely from well to well, and from stage to stage due to unpredictable variations in the rock.
Before the oil price crash, companies commonly would “optimize” a drilling program by doing a few heavily monitored science wells to establish a standard design for the many wells that followed.
Wide performance variations made a case for the value of adding individual well data. But there is a limit on the time and money available to do so.
“The objective is to do it relatively inexpensively on every well drilled,” he said. To deliver on that Ingrain had to develop a system to scale up that process to deliver results in time to be used to adjust completion designs based on field-scale data.
“The trend is doing it quickly and doing it in a repeatable fashion on a commercial scale” using current technology, Walls said.
The turnaround time can be days, but it is normally about a week, for a price that he said is in the same range with other new testing methods costing less than USD 100,000 per well.
The cutting testing program uses mineral and elemental tests to measure brittleness, which can highlight if sections can be effectively broken using hydraulic pressure, and a look at pore-scale imaging to quantify the hydrocarbon-filled pores, which provides a good estimate of permeability.

Mapping Fracturing With Pressure Change
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
A service using pressure data from a few nearby unconventional wells to map fracturing will soon be for sale.
Statoil developed the method, and has used it to improve how it completes wells in three US unconventional plays, said Matt Dawson, investment manager at Statoil Ventures, which created a company to market the method, called Reveal Energy Services.
The approach assumes that in formations where most of the hydrocarbons are trapped in a dense, nearly impermeable matrix with a limited number of fractures, the pressure of the flow through those pathways can be measured in nearby wells.
The signals—a poroelastic pressure response—can be 10–100 psi, said Dawson, who also helped create the method.
The extremely limited flow in the formation, and the fact the monitoring wells are pressurized with water to protect them from the fractures growing from the well to be stimulated, ensures that the measurements are of “the pressure profile in the stimulated fracture,” he said.
With multiple surface measurements of pressure changes during fracturing— data from at least two wells are required, and more is better—Dawson said it is possible to measure the largest fracture’s length, height, and angle.
The method developed to track fluid flows through fractures has been used to evaluate Statoil wells in the Bakken, Eagle Ford, and Marcellus shales, and Dawson said “we are confident it will work in those three.”
More than one-third of the company’s wells in the Bakken were tested over a 12-month period, he said. Within a year he said they hope to be able to gather and interpret the data quickly enough for it to be used by crews as they are fracturing the well.
When Statoil researchers asked engineers in the field if they could try the test during fracturing in the Bakken, there were questions about how much it could complicate fracturing.
“It really turned out to be not very difficult to accommodate into normal operations,” said Darren Schmidt, a principal engineer in Statoil’s shale oil and gas research and technology group. The method requires setting plugs at certain times while fracturing, but if “you are zipper fracturing a well, you can fit this in normally on a multiwell pad and then get some good information,” said Schmidt, who was then doing completions.