Figure 3. Y axis – Traditional retort approach of fluid summation, where the porosity = (Gas + Water + Oil) / Vb; X axis – Bulk and grain volume method, where the porosity = (Vb – post closed retort Vg) / Vb. If the retort does not remove all of the actual pore fluids, the post retort Vg values will be artificially too high, and the resulting porosities too low.
- NMR T1/T2 acquisition and 2D map capability
- T2 distributions can be utilized for fluid-filled pore body quantification and understanding.
- T1/T2 results can be utilized for potential fluid typing and understanding of lost fluid fraction.
- Open and closed retort capability
- Assess the free versus bound water results (i.e. water partitioning). This can be compared to NMR results.
- Mobile versus immobile hydrocarbon fraction (i.e. hydrocarbon partitioning).
- Geochemical integration of TOC and programmed pyrolysis data (can be complimented by fluid property analysis)
- Differentiates the thermally versus chemically extracted results for an understanding of mobile versus immobile organic matrix components.
- Offers TOC calibration for all subdisciplines.
- Provides thermal maturity (Tmax) understanding, as well as volatile fluid fraction (S1 mg/g) versus remaining source rock potential constraint (S2 mg/g).
Full rock and fluid property assessment through the TruSat workflow aids subsurface investigators to measure improved constraint and understanding of the stratigraphy. The partitioning of both water and hydrocarbon phases is a critical facet of improved oil-in-place assessment for unconventionals. The ability of TruSat to bridge potential challenges among geological, geochemical, petrophysical, and engineering applied learnings and concepts is impactful. When considered in combination with additional critical information (i.e. PVT analyses), geoscientists can constrain the properties that lead to economic assessment and directly affect business decisions.
GeoMark continues to be focused on rock and fluid measurement interaction and integration through a combination of techniques and expertise applied to subsurface understanding. Challenges still remain and are identified by the scientific community, particularly pertaining to tight (<1 mD permeability) oil play types. Our approach is to concentrate on and advance currently applied rock volume investigation methods, while also focusing on the fluid components. This ensures we constrain the rock and fluid interactions critical to closing the gap between laboratory analysis and unconventional horizontal production. We are also continually improving upon laboratory measurements and execution to further refine and differentiate particular fluid phases associated with given pore spaces and volume. These efforts can lead the industry to more effectively distinguish between total oil-in-place assumptions versus what is physically producible; thereby, predicting a better estimate of recoverable hydrocarbon volume from forward modeling (subsurface to wellhead) rather than an inverse modeling (wellhead to subsurface) approach.
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TruSat Data Applications
- Do you have additional underexploited upside targets? If so, what are the rock and fluid properties related to the already identified targeted development to build a predictive understanding of potential production performance?
- Can I use my legacy rock volume to build an analog set for an unexplored or quantified play?
- Should I revisit my core volume to better understand the secondary and tertiary mobile versus immobile fluid fractions in my pore volume?
- After initial primary drainage, what chemical reagent would be most effective to sweep out additional ‘less mobile’ fluid volume?
- Could my rock be a candidate for enhanced oil recovery by investigating the efficiency of a thermal versus chemical extraction of fluid from the pore volume?
- How do I know if my initial targeting and production was efficient or left more fluid than I wanted behind in the subsurface? How much was left?
- The asset needs to better understand the engineering parameters of recovery, such as relative permeability and drainage, along with the primary properties of the rock and fluid volume? Can the technique help with the that when combined with complimentary capillary pressure data?
- How do re-saturated samples and results compare to as received samples and results leading to understanding of the total fluid-filled volume differences and possible wettability impacts to mobility?
- I need to calibrate my wireline NMR to a single phase re-saturated fluid-filled volume. I need to this in the laboratory setting so I can then better interpret by wireline data.
- My produced legacy target is now a candidate for injection (salt water or other). I need to measure the total porosity and permeability to provide to engineering for injection capacity modelling?
- Maybe I misunderstood my unconventional target or missed something critical in terms of it’s ability to produce. The technique can help me go back and look at that and explain the performance of the rock and fluid in a look-back analysis?
- I need to re-calibrate and re-calculate reserve estimates. The original estimates related to calibrated models do not agree and I need additional data to support the updated quantification.