GIT is able to test many different lithologies, including clastics and carbonates. Several sample reports are available for viewing here Tests are performed on core plugs (standard plugs and sidewalls), in our laboratory. Maximum sample size is 60mm long, and 51mm in diameter. At this time, testing services are not available for cuttings.

GIT’s NMR SCAL techniques are limited not strictly by sample size, but by the volume of fluid held within the rock matrix itself. In order to achieve an adequate signal to noise ratio (SNR) from a sample, a certain minimum volume of fluid must be present in the rock. Typically, the minimum fluid volume necessary in the core plug is .2 ml for capillary pressure testing, or 0.05ml for standard NMR measurements.

GIT’s techniques are well-suited to "tight" rocks. The long centrifuge equilibrium time makes traditional centrifuge capillary pressure tests extremely time-consuming (over a month, vs. 7 days for GIT-CAP). GIT has successfully tested several examples of unconventional shale gas reservoirs, with permeabilities in the nano-Darcy range. Currently, there is no specific test available for heavy oil reservoirs, although it remains a focus of research.

Porous plate is considered the gold standard for calculating capillary pressure, but it is extremely slow. Mercury injection is very fast, and requires only a small sample, but it is destructive and uses a non-representative fluid. Traditional centrifuge techniques may still take several weeks to generate a full capillary pressure curve, as one spin is required to obtain each point (7- 10 in all) on the curve. GIT’s technique is not only faster (2 spins), but also more accurate as it does not require the same assumptions as the traditional centrifuge method. Rather than measuring expelled water, our technique measures actual in-place water saturation at 30 to 40 points along the core plug non-destructively, and in a single spin.

A common question about our NMR techniques is "what about fluid redistribution?". Over time, it just makes sense that fluid within a core plug will redistribute once the rock has been removed from the centrifuge. GIT has tested numerous rocks of varying permeabilities and found that redistribution does occur, but over time frames much longer than those necessary to obtain the NMR measurement. Please click here for further information on redistribution.

As in medicine, CT and NMR/MRI are complementary, rather than competitive techniques. Depending on the application, one modality will be more appropriate than the other. In medicine, for example, CT is typically better for examining bones, whereas MRI would be the scan of choice to examine soft tissues. When it comes to rocks, GIT’s technique measures the actual fluid in the rock. CT, by comparison, measures the matrix of the rock, but results in modeled (not measured) fluids.

For a number of years, the industry has used 33ms as a standard T₂ cut-off for sandstones. While appropriate for the conventional sandstones on which it was originally measured (Dunn et al., 1994), in today’s unconventional reservoirs, this number is not appropriate. In GIT tests, T₂ cut-offs for "tight" sands have been measured at as low as 0.5 msec. Redefining cut-offs based on core measurements may have a significant impact on the calculated reserves.

GIT requests that you provide four pieces of information, if possible:

• desired brine composition
• desired pressure for desaturation
• porosity
• permeability

Unless otherwise specified, we will use 2% KCl brine, and can estimate the pressure to use if unknown. Porosity and permeability are helpful, but not mandatory, inputs to our process.

All GIT specialty SCAL tests are carried out in our own testing facility located in Fredericton, New Brunswick, Canada.

Below are some basic definitions of terms found on the web site, and in GIT reports. For more in-depth technical information, please consult one of the excellent references listed here.

BVI
Bulk Volume Irreducible. Proportion of the formation fluid volume that is capillary-bound, and therefore not available for flow.

CBW
Clay Bound Water. Proportion of the formation fluid (water) volume that is adsorbed to clays, and therefore not available for flow.

Effective Porosity
A porosity value obtained by disregarding all pore size values below a certain T₂ (or T₁) threshold value. It refers to connected pores, and excludes the water adsorbed by clays. It may include water that is bound only at a particular capillary pressure or saturation.

FFI
Free Fluid Index. An estimate of the "producible" porosity in a rock. Fluids that are available to flow, and not bound either by adsorption to clays or by capillary pressure.

The following diagram (after G.R. Coates et al, NMR Logging Principles & Applications, 1999) depicts these definitions graphically.



NMR Porosity
The "total" porosity of the rock, measured using NMR. It accounts for both clay and capillary-bound fluids, as well as free fluid.

T₁
Longitudinal, or spin-lattice, relaxation time. A time constant that characterizes the alignment of spins with the external static magnetic field.*

T₂
Transverse, or spin-spin, relaxation time. A time constant that characterizes the loss of phase coherence that occurs among spins oriented at an angle to the main magnetic field and that is due to interactions between spins.* It is always shorter than T₁.

T₁ or T₂ cut-off
On a T₁ or T₂ distribution, the point that defines the boundary between bound and free fluid. Determined by projecting a horizontal line from the maximum, cumulative S_wr value, across to the intersection with the cumulative, 100% saturated curve, then dropping a vertical line to the x-axis (relaxation time, T₁ or T₂ in ms), where the cut-off value is read.



S_w
Water Saturation. The fraction of water in a given pore space, expressed in volume/volume, percent or saturation units. The saturation is known as the total water saturation if the pore space is the total porosity, and the effective water saturation if the pore space is the effective porosity. **

S_wr
Residual Water Saturation. The lowest water saturation that can be achieved in a core plug by displacing the water by oil or gas, usually achieved by flowing oil or gas through a water-saturated sample, or spinning it in a centrifuge to displace the water with oil or gas. Synonymous with connate water saturation, which is the lowest water saturation found in situ. Somewhat different from irreducible water saturation, which depends on the final drive pressure (when flowing oil or gas) or the maximum speed of rotation (in a centrifuge). **

*from G.R. Coates et al, NMR Logging Principles & Applications, 1999

**from or after Schlumberger Oilfield Glossary