Hydraulic fracturing is much in the news these days given its widespread use in the ubiquitous shale plays.
It’s a long accepted, proven process that dates back to 1903. It was first commercially employed in 1948.
Even so, many people residing in these play areas are increasingly vocal about the technology, questioning and sometimes claiming it’s contaminating the subsurface aquifers that source their drinking water, among other complaints.
Perhaps they should abstain from eating ice cream.
That’s right. Ice cream.
The popular sweet treat contains guargum, which is used as a thickener in hydraulic fracing fluid.
“Most of the materials we use are pretty benign materials,” said Randy LaFollette, manager of shale gas technology at BJ Services in Tomball, Texas. “A lot of the material we get has normal household uses and ingredients.”
Whatever the makeup of the fluid, he adds, forget about it migrating into the aquifers.
“There are studies outlining the risk associated with shale gas especially,” LaFollette said. “The normal situation is that shale reservoirs have thousands of feet of vertical separation from aquifers or potential underground sources of drinking water.
“It’s hard for a frac job to migrate vertically thousands of feet,” he said. “There would be some sort of barrier in between – in other words, a rock with geomechanical properties that would act as a barrier to upward migration.
“In some places what happens as well is you see the overburden becomes the minimum principle stress,” he noted. “And so at very shallow depths, the fractures essentially want to turn sideways and not propagate vertically.
“If aquifers are above where that happens, the fracs can’t possibly grow in to them.”
Addressing concerns over surface spills from hydraulic fracing operations, LaFollette emphasized there is little risk of this happening. Should a spill occur, it can be cleaned before there is any damage to an aquifer.
He noted they are using passive microseismic technology to monitor the subsurface fractures as they are being created.
“Microseismic monitoring is for design calibration and also for shutting down jobs going toward some geohazard you don’t want,” he noted. “A classic example is the Barnett shale, where karsts and faults lead down into the Ellenberger salt water below the Barnett.
“When we see the fracture microseismic events going in that direction, we shut that stage down and move on to the next stage,” LaFollette said.
“We’re developing predictive capability,” he said. “We don’t want to waste frac material and the customers’ money to create fractures that aren’t beneficial.”
The layperson might be inclined to question whether hydraulic fracturing is really necessary or whether the operators are just too impatient to get the hydrocarbons out of the reservoir naturally.
So why do we fracture these shales, really?
A good example is the Barnett shale in Texas, which kicked off the ongoing shale boom. It’s home to sealed natural fracture systems that won’t produce economic quantities of gas.
In contrast, the Marcellus shale in the eastern United States is a mix of sealed and open fracture systems.
“You can drill the borehole for maybe 5,000 feet through a sealed natural fracture system with a shale gas well and then evacuate it,” LaFollette said, “and you won’t get enough gas to run a one-chair barber shop until you complete and frac that rock extensively.”
It’s all about gas molecule movement in nano-darcy matrix permeability, he explained while providing data points:
- Gas molecule movement in shale of about 10 feet in a well’s lifetime, as per Mohan Kelcar with the University of Texas.
- Gas molecule movement of about a meter/year, modeled by Nexen in Calgary.
- Gas molecule movement of a few feet/year, modeled by Chunlou Li at BJ Services shale gas technology group.
“We’re all converging on similar numbers,” LaFollette said. “The implication is if you don’t place a high permeability pathway close to where a gas molecule resides today in the reservoir, it will never find its way to the wellbore – there’s no geological time to wait around for these things to migrate out at their own pace.
“Therefore, we frac – it’s the only way with current technology to place many high permeability pathways into that volume of rock we want to drain,” he emphasized. “If you can make those fractures close enough together you can effectively drain a large part of the shale.
“The hydraulic fracturing process creates not only tensile fractures, it also shears existing fractures in the target.”
The fluid mix used in hydro fracing has specific functions:
- Transmit energy to the formation to split the rock.
- Transport proppant (through tubulars, completion, near-wellbore fracture).
- It must be compatible with formation minerals and fluids.
- It must be easy to recover.
Slick water fracs, which provided about the same production results as crossed linked gel fracs, became the preferred fracturing fluid in the mid-1990s for shales with which it was compatible. These slick water apps cost about 30 percent less than cross-linked gel treatments, which is quite important given that fracture stimulation costs are a large piece of the AFE for these wells.
“Slick water is one of the simplest fracturing fluids,” LaFollette said. “Generically speaking, it’s comprised of water and a polyacrylamide friction reducer that makes the fluid more slippery – reducing the friction makes it cost less to pump a job.
“Other additives may be included, such as biocides, surfactants, clay control additives, and breakers, as needed to optimize treatment effectiveness,” he noted.
In shale fracs, operators typically recover about 10 to 25 percent of the frac fluid – and what comes back tends to have a high dissolved solids content. What’s done with it depends on what it is when it comes back.
“You may start with potable water and it comes back supersaturated,” LaFollette noted. “You get into water recovery process issues and reclamation issues.
“Especially where water is hard to come by, you’ll see partial reclamation and dilution with other water sources to be pumped down the next well,” he said. “We’re using as much of recovered load as possible.”
Environmentally friendly products are high on must-have lists of both operators and service companies.
For example, the use of ice cream component guargum as a thickener in frac fluid is light years removed from the long-ago days of small frac stimulation treatments using war surplus napalm.
These days, what’s green can always be greener.
“We have a project that started last year looking at the environmental aspects of our products,” said Andy Jordan, technology support manager at BJ Services. “We looked at the components of the products and came out with a system to verify the relative ‘greenness’ of the different chemistries we use.
“This mostly helped us to identify the better products in our product line.”
When queried about the anxiety on the part of those folks who fear contaminated ground water, Jordan noted they are working to educate the public to show the hydraulic process is controlled, e.g., using microseismic, and the risks are minimal with regard to drinking water.
He noted also that certain states, e.g., Wyoming, Pennsylvania and Colorado, are wanting to establish their own regulations relative to fracing rather than being under the thumb of the federal government’s EPA rulings on the matter.
Meanwhile, there appears to be a whole new twist of sorts on the ongoing animosity between environmental groups and energy companies regarding hydraulic fracing. A coalition reportedly is being established among some of these entities with the objective to collaborate on a plan to step up safety and regulation of hydro-fracing.
Southwestern Energy and the Environmental Defense Fund reportedly are said to be the nucleus for this planned new project, which was announced at press time.
If you’re laying out plans to begin a frac job, LaFollette has some advice: Begin with the end in mind:
- Think about the frac before planning where to land the lateral.
- What frac fluid will be used – and how effectively can it transport proppant above the level of the horizontal in thick pay zones?
- Is there a good lower frac barrier?
An effective set of propped fractures and sheared fractures is actually what you are buying in gas shales. So:
- How much embedment is expected?
- Is the proppant strong enough?
- Will the proppant retain strength over the long term?
- What is the maximum length of lateral that can be placed into the formation and effectively cleaned up after fracturing?