The relatively recent spate of near-frenzied drilling and hydraulic fracturing activity in a plethora of unconventional reservoirs prompted the production of massive volumes of hydrocarbons.
Yet a good bit of this fast-paced drilling action was triggered by the need to retain lease holdings.
Along the way, an unwelcome combination of increased well spacing and inefficient completions became the norm in many areas. The adage “haste makes waste” soon came to plague the operators, given that their hurried efforts sometimes led to inadequate drainage of the target hydrocarbon-bearing reservoirs.
It was determined that the logical and obvious strategies to address this dilemma are to re-fracture the existing wells and drill infills.
It’s widely known that refracturing a horizontal well can help to reduce the interaction between so-called parent and child wells by causing a high stress area around the refractured wells and diverting child well fractures away from the parent well.
This leads to improved productivity and recovery of both, according to Ripudaman Manchanda, research associate at the Department of Petroleum and Geosystems Engineering, University of Texas-Austin.
Biased Fluid Distribution
But we’re talking a whole new game here, and challenges abound.
For starters, re-fracturing a partly depleted horizontal well can lead to ineffective re-stimulation of the depleted intervals, even though diverting agents are employed with the goal to divert fluid and proppant to the non-depleted zones.
In large part, the problem is the geology.
Reservoir heterogeneity, for example, plays a key role in preventing horizontal well fractures from being identical. Adding to the complexity, stimulation to create fractures is implemented in sections or stages along the laterals, which further encourages non-uniform depletion along the well.
During the refracturing procedure, the stimulation treatment entails injection of fluid slurry into the total well, meaning individual fractures are not isolated during this procedure. And diverting agents used in refracturing can accomplish only so much.
Low depletion areas harbor lower pore pressure and lower in-situ stress in the rock matrix adjacent to the fractures, Manchanda pointed out. Therefore, during the restimulation process, the injected fluid is attracted here, with the unwanted result being a biased fluid distribution.
This negates the refracturing process goal to stimulate un-depleted regions of the reservoir, demanding a serious new look at this challenging scenario.
A possible solution to overcome the fluid distribution bias resulting from non-uniform depletion: slow injection.
Manchanda explained that this method involves injecting fluid — liquid or gas — slowly, for hours or even days, prior to pumping the scheduled refracturing operation.
Doing so helps to reduce the bias by inducing a kindred pore pressure adjacent to all of the well’s fractures.
In other words, slow injection can at least temporarily mitigate the near-fracture and near-wellbore effect of depletion on fluid diversion and fracture initiation.
This unique slow-injection strategy was simulated using a fully 3-D poro-elastic geomechanics model called Multi-Frac, which is a PC-based and cluster-based simulator used to design and optimize hydraulic fracturing in pad-scale operations.
“The results helped with understanding the impact this slow injection phase has on the pressures and stresses that develop during depletion and re-pressurization,” Manchanda said.
“This helps to design the rate and duration of the slow injection to efficiently re-fracture depleted wells,” he emphasized.
The University of Texas is the sponsor of the Multi-Frac development. In fact, the tool is based on the Framework for Research and Operations in General Geomechanics (FROGG) libraries, developed at UT-Austin over the course of the past 15 years, according to Manchanda.
Designed to be used by completions, production and reservoir engineers, Multi- Frac has been used a number of times in the field. It has proven to optimize both fracture spacing and sequencing along with well spacing for some notable unconventional plays. These include the Bakken, Eagle Ford, Barnett and Marcellus, along with Permian Basin locales.
Typical of new technology, Multi-Frac has been a long time in the making.
“What we have in place now is the work of about 10 years,” Manchanda emphasized.
“The first field project I was involved with using technology similar to Multi-Frac was about 2010.” he said. “The project was in the Barnett and lasted about two years; we did several wells and used this to plan for fracturing future wells.”
So, even though it was developed inside UT, there’s documented proof that it works in the field.
And it’s available — just not off-the-shelf.
“People come to us to get help, and that’s when they’re able to use it, so we continuously do projects with companies who provide us with funding,” Manchanda said.