It doesn't take an official proclamation to recognize that unconventional hydrocarbons have catapulted to the top on the oil patch buzz-o-meter scale.
One might even question if it’s time to drop the “unconventional” qualifier, given the ongoing deluge of seminars, professional papers, industry luncheon talks, etc. spilling over the industry to address these resources.
But even though the array of plays such as tight sands, shale gas and coalbed methane have become the darlings of the industry -- particularly in the United States -- their inherent complexities continue to challenge the operators.
New approaches and new/refined technologies are a must-have to understand and economically produce these out-of-the ordinary reservoirs. Typical of this industry, the reservoir technology experts are meeting operators’ needs head-on.
Much of the technology effort is focused on tight gas shales -- not surprising, given the rash of new plays in various regions of the country. It is noteworthy that the gas in these tight rocks resides not just in the micro-pores but also is adsorbed on and in the organics.
“The bulk of land drilling in the U.S. today is tight gas shales,” said Sidney Green, founder and former CEO of TerraTek -- acquired by Schlumberger last year -- and currently geomechanics business development manager for Schlumberger Data & Consulting Services.
“It takes unconventional technology to produce tight gas shales,” he added, “and the issues have to do with the rocks themselves.”
Those issues include:
- Tight gas shale has very low matrix permeability, i.e. nano-darcies, which industry historically would refer to as no permeability. The ability to measure the matrix permeability became an issue early on, demanding a process to perform this task.
- The fractured nature of these formations is another highly complicated issue encompassing fracture direction; frequency of fractures; and the manner in which they’re open or not open.
- Shale formations tend to be non-homogeneous from a macro-scale down to the micro-scale. They’re highly layered, which tends to give a non-homogeneous formation in the vertical direction, and they’re also anisotropic in the horizontal direction, meaning the properties differ even in the horizontal plane.
Getting a handle on the heterogeneity issue is crucial.
“If we accept that the medium is heterogeneous, possibilities open up for understanding and predicting phenomena,” said Roberto Suarez-Rivera, Schlumberger scientific adviser and TerraTek’s discipline manager-stimulation and production division. “What is relevant is how to deal with all the properties -- clay maturation, clay types, kerogen maturation and the like -- in a combined fashion.”
In its efforts to identify the producing mechanism of these formations, TerraTek has applied detailed core analysis to measure the matrix properties of permeability, porosity and saturation.
Green noted this demanded the invention of a new procedure they dubbed TRA (tight rock analysis), which has become a standard in the industry.
The TRA is one of several new procedures the company uses to evaluate these multifarious reservoirs.
One such process relates to petrographic analysis, i.e., looking at the micro-structure of the shale. Classifying shales requires examination of the micro-structure and subsequent comparison to actual measurement of porosity, permeability and saturation characteristics.
Another new technique deals with the measurement of non-homogeneous and anisotropic properties on cores. In addition to standard techniques measuring properties on samples taken at different directions, a scratch test provides a continuous profile measurement on formation core. The acquired signature is invaluable to correlate with logs for predicting other properties.
TerraTek also jumped into the realm of core log integration, i.e., the scaling issue that ranges from the micro-scale petrographic analysis to lab scale core analysis to logging wellbore scale and on up to reservoir scale.
Ultimately, the company wants to see the evaluation process move from lab measurements on cores on up to logging and even seismic technology for reservoir evaluation in the next decade or so.
This evolution includes the recent introduction of Schlumberger’s sonic scanner tool, a new logging process with the potential to measure non-homogeneity and anisotropy.
“The sonic scanner has the ability to measure properties in different directions with a single log run,” Suarez-Rivera said.
“Instead of the long time it takes to complete all these measurements in all directions, we now can come up with the same type of measurements in a single log run.”
There’s different strokes for different folks when it comes to developing innovative technologies to economically produce hydrocarbons from unconventional reservoirs across the board.
Core Laboratories, which is a long-familiar name in the realm of reservoir technology, is big on the consortia approach as a cost-effective, efficient approach to bring needed technology to the operators.
“Half of our work on reservoir problems is through JIPs,” said Randy Miller, president of Core Labs’ integrated reservoir solutions group. “Today, 80 percent of this work is in unconventionals, especially in two large projects.”
The Tight Gas Sands of North America Fracture Stimulation Optimization project includes 30 companies from the United States and Canada. The program has been active for three years and is still going strong.
“It’s evaluating tight gas sand reservoirs from the pore scale looking at conventional cores,” Miller said. “We’re trying to solve a number of problems, like what’s net pay, how much gas is in place, what are the geomechanical properties, fluid sensitivity issues and what is the appropriate stimulation design.
“It goes from the core through the petrophysics through the stimulation design,” Miller noted, “and we also do post-frac production analysis.
“We’re comparing and contrasting different tight gas sands -- what’s common to them and what’s different, and how do you maximize or optimize production in a tight gas sand play versus another project.”
The program provides info that can save big bucks in exploitation of these reservoirs. The companies get a better handle on the appropriate petrophysical model, formation pay, how to complete and stimulate. The enhanced understanding of the reservoir also helps to select infill locations.
A second project -- Gas Shales: Reservoir Characterization and Production Properties -- is also focused on the United States and Canada and boasts 42 participating companies.
“We’re doing the same thing,” Miller said, “looking at the shales from core, reservoir properties, reservoir characterization scale and up through geomechanical properties, stimulation design and production analysis -- developing petrophysical models to determine what constitutes a pay or gas zone in a shale.
“There’s a number of shales in the Rockies currently being evaluated,” Miller noted, “as well as the Gulf Coast region and along the East Coast, such as the New Albany shale. There’s been a number of encouraging results from some of these other plays.
“In unconventional reservoir evaluation, these consortia are a very cost effective way for these companies to acquire technology and understand the reservoir,” Miller said.
“For instance, each of these shale plays has some unique components, and what works in one area may not work in another.”
The recognition of tight gas sands as an important resource is taking hold beyond the United States, according to Miller, who is optimistic about the opportunity to leverage what has been learned stateside relative to tight gas sand formation evaluation and stimulation.
He predicts more focus on unconventionals in Europe, South America, the Middle East (especially deeper gas reservoirs), Russia and China.
Miller noted also that while the United States and Canada currently are leaders in the realm of coalbed methane, this will expand into Europe as well as India and China.
Of course, contracts in the international arena can be dicey undertakings in even the best of circumstances these days -- and unconventional reservoir development brings its own set of baggage to the negotiating table.
Before any activity revs up, there will have to be a paradigm shift in the production sharing agreements typically common between the NOCs and the IOCs, which will reflect the manner in which these reservoirs are exploited.
“Right now a lot of these agreements discourage long-term input (capital) into reservoirs, and these reservoirs have a long life,” Miller said. “Also, to continue development and keep gas production up requires extensive infill drilling.”