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New approaches characterize mudrocks
New approaches characterize mudrocks
Shales are attracting attention. Previously written off as seals, rather than reservoirs, and considered too tight for production, new techniques are being developed to better quantify the potential in these fine-grained sequences. Although we have made considerable progress in understanding shales and mudstones, these rocks are so diverse that much uncertainty remains.
The characterization of mudrocks as shale gas and oil reservoirs is the subject of an applied geosciences conference in Houston this month, focused on improving exploitation of mudstones in the US Gulf Coast region.
Reverse-engineering nature. Professor Juergen Schieber runs the Shale Research Lab at Indiana University Bloomington (IU) and has studied mudrocks for 30 years, beginning with microbial mats in the clastic record. He now focuses on experimental mudstone sedimentology in order to understand shale successions and properties.
The IU flume facility was built to study depositional and erosional parameters of mud and to duplicate depositional features observed in the rock record.
“Some of the simplest experiments are the most enlightening,” he said, noting that cohesion and flocculation of clays produced surprising results. Organic matter settles more quickly than clay particles, resulting in black-gray laminations (showing that these are not necessarily seasonal markers related to variation in oxygen levels). Subsequent turbidity (e.g., storms and currents) causes resuspension and resettling, reworking the organic matter.
Flume work in the 1990s showed that both clay and silt can be carried as bed load. Flocculated clays are the hydraulic equivalent of coarse silt, and will actually form ripples. Salinity speeds up the process of flocculation. The lab produced finely laminated deposits, demonstrating that black shales can be emplaced by currents and are not limited to gradual accretion of flocculated sediment raining down through the water column. These current deposits are better sorted, as silt and clay particles travel separately and form homogenous ripples. The notion of deepwater current transport of flocculated clays across basins changes the search criteria for shales.
Schieber has also recreated lenticular shales using the flumes; eroding very soft muds, little lumps of clay bounce along in the current, become entrained, and then flatten during burial and compression. The team verifies the process through depositional cycles that build up “thick” layers (several centimeters) showing clear sedimentary structures.
Despite success with experimental modeling, Schieber says it’s humbling to look at a real sea bottom. He and his graduate students participate regularly in offshore coring, to keep one foot solidly in the rock record. The IU team has a third flume under construction that will allow them to make artificial source rocks and control water chemistry. A fourth flume will be added later this year to model tidal cycles and storm waves.
The way of sandstone? Schieber predicts that mudstone research will parallel the history of sandstone research, in which field-derived information and experimental data were used to model facies and depositional systems. The microfabric of shales derived from water-column settling differs from current-generated deposits, and Schieber has a hunch that the source rock gives an idea of the pore type and connectivity.
“From an intellectual perspective, shale research is clearly a frontier of sedimentary geology,” Schieber said, “and will contribute much to a better understanding of earth processes, earth history and earth system interactions. It is also becoming crucial in the exploration and utilization of vast, untapped hydrocarbon deposits in oil and gas-rich shales.”
Digital rock physics. Ingrain Inc. has developed its CoreHD service (high-resolution X-ray CT scanning) for whole cores, which provides detailed images that the geologist can use to understand rock laminations, fractures, burrows and other features of interest. Joel Walls, the company’s director of unconventional technology, says InGrain can process this data to obtain bulk density and effective atomic number at a sub-millimeter scale on the whole core. The data, acquired within a few days of the core leaving the wellsite, helps locate zones of highest reservoir quality.
The company obtains 3D nano-scale images using scanning electron microscopy with a focused ion beam. These images can capture a 3D pore system plus kerogen and solid minerals in a shale sample. This digital volume is analyzed for multiple rock properties including connected porosity, kerogen volume, directional permeability, relative permeability and capillary pressure.
Based on data collected using digital rock physics, Walls says that in the Eagle Ford Shale, kerogen-associated porosity provides better permeability than an equivalent amount of intra-granular porosity. Thus, kerogen-dominated pore systems will have higher reservoir quality.
Geochemistry and geophysics. Black shale diagenesis, gas isotope chemistry and nanotechnology applications are some of the current trends in geochemical shale research. Advances in 3D seismic, rock physics, geomechanical analyses and microseismic monitoring are among the geophysical tools used to characterize shales and monitor development of shale plays.
Many tools are under scrutiny for the edge they might provide in gaining new technical perspectives of Gulf Coast mudrocks—with a lot of attention to the Haynesville, Bossier and Eagle Ford. Practical research is already illuminating the difference between these plays and the Barnett archetype.
Shale plays are being identified, defined and claimed at a dizzying pace. Some development drilling appears to be driven by allowable well spacing rather than geologic criteria, Schieber says, but “Once the gold rush is over, people will take a more scientific approach.”
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