2008-computing properties form 3d imaging

Next-generation computed tomography(CT) scanning reveals the actual porestructure of shale reservoirs at thenanometer scale, and breakthroughalgorithms compute the physical proper-ties of shale from these 3-D images —all with unprecedented accuracy

AUTHORHenrique Tono, Ingrain

Analysis of reservoir rock sampleshas long been regarded as acumbersome process requiring

costly coring operations, increaseddrilling risk, and time-consuming physi-cal lab experiments. Shales are particu-larly difficult to measure using physicalmethods as a result of the rocks’ smallpore sizes. But Ingrain, a startup oil-field service company, has achieved atechnical breakthrough by applyingadvanced digital imaging and comput-ing technologies to the process of phys-ical core analysis. Ingrain’s digitalapproach to measuring rock prop-erties provides operators with theporosity, permeability, conductiv-ity, and elastic properties of shales.

This non-destructive processaccommodates all types of reser-voir rocks, including those thatare difficult or impossible to sub-ject to physical lab experimentssuch as oil sands and shales.Without the constraints of a phys-ical lab, the process can returnaccurate measurements fromcores or drill cuttings within days— fast enough to aid criticaldrilling and production decisions.

Challenges to shale property measurement Shales have some of the smallestpores found in any clastic or non-clastic reservoir rock. As a result,hydrocarbon flow in shale reser-

voirs occurs in pore structures that areorders of magnitude smaller than typicalsandstone or carbonate reservoirs. Thiscomplexity makes it difficult to measureshale properties in physical lab experi-mentation. Until now, efforts at digitalrock properties measurement in shalesfailed because rock samples were notbeing imaged at the nanometer level, orcomputations were being performed onsimplified pore network models thatdidn’t accurately characterize thedetailed fabric of reservoir rocks.

Next-generation technology The new process begins with a team oftrained geologists evaluating rock sam-ples and preparing them for imagingwith industrial-grade CT scanners.Hundreds of 2-D scans of each rocksample are layered to create a high-resolution 3-D digital capture of therock sample. Most conventional sam-ples are imaged using a MicroXCT

system that functions at resolutions up to one micron. For shale samples,Ingrain uses a NanoXCT, the onlymachine of its kind currently beingused in the oil and gas industry. Withthe ability to produce accurate imagesof a sample’s pore network at a resolu-tion of .05 microns, the NanoXCT isparticularly valuable in capturing thecomplex pore networks of unconven-tional reservoirs, including shales.

After imaging, geologists apply sophis-ticated image segmentation software todifferentiate between the grains andpore space within the 3-D volume. Thefinal result is a digital version of theactual fabric of the original physicalrock, which Ingrain calls a “vRock.” ThisvRock reveals the complete pore net-work at a level of detail that allows thecompany to accurately compute physicaland fluid flow properties. The propri-etary fluid flow computations are basedon the lattice-Boltzman method, which

allows for simulation of fluidflow in pore spaces of any com-plexity.

By unifying innovative tech-nology with its proprietary segmentation methods andcomputational algorithms, thecompany provides operatorswith new insight into theirreservoirs. Further, the speed ofthe process allows for largenumber of samples to beprocessed quickly, resulting inmore measurements and theability to better characterize theintricacies of the reservoirs athand. This has high value inshale reservoirs, where inherentheterogeneities require largeamounts of data to create accu-rate reservoir models.

When the process is com-plete and results are delivered,vRocks are stored for operators

Computing properties from 3-D imaging

Figure 1. A three-dimensional rendition of a shale sam-ple. The blue represents the pore structure. The gray areasrepresents the matrix, and the white spots are framboidalpyrites. (Images courtesy of Ingrain)

E&P | November 2008 www.EPmag.com

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in a secure database. Software runs ina web browser, giving geoscientists theoption of requesting multiple analyseson the same vRock to modify parame-ters and observe how the resultschange.

Improving decisions and reducing riskThe ability to measure shale proper-ties introduces new elements of knowledge that can improve decision-making and reduce risk. For example,velocity measurements are typicallyused to predict pore pressure. But inshale formations, velocity is affectednot only by pressure but also by thesilt content of the shale (high silt con-tent causes high velocity). In shale

reservoirs where there is a risk of over-pressure, this new analysis method canimprove pore pressure prediction bymeasuring silt content in shales.Further, the solid hydrocarbon con-tent of the shale can be quantified,which helps in interpreting well logsof shale sections.

Shales and other unconventionalassets will continue to challenge opera-tors simply because they require trialand adoption of new methods andtechnologies. By introducing a newlevel of insight and knowledge to theE&P process, Ingrain is empoweringoperators with the basic informationrequired to overcome the challengesof shales, ultra-low permeability, andcomplex reservoirs.

Figure 2. A two-dimensional slice througha shale. The dark areas are the pores. Thewhite spots are high density framboidalpyrites. The gray areas are siliceous min-erals. The light gray areas are carbonateminerals.