Formerly Known as GRI+
TruSat™ Rock Properties
Overview
As the early days of unconventional play discovery and understanding has now surpassed a decades worth of learnings and laboratory to in situ understanding, operators and researchers are left with remaining legacy whole core or sidewall core material remnants. Where the subsurface rock material was originally acquired to address the immediate asset related questions at hand, the reuse and revisiting of legacy material to open up new ideas, opportunities, understandings, as well as enhanced oil recovery applicability are gaining momentum into this new decade. While operator’s would have utilized that core originally for in place quantification and validation of go forward horizontal target line selection, applicability beyond those initial investigative objectives is critical. GeoMark’s TruSat technique and quantitative work flow are best-suited to aid the operator in quantification, value of information and applied understanding from the exploration to appraisal and development as well as post production life cycle.
One of the best qualities of our TruSat work flow is the ability to customize at each step of what is a critical quantitative measurement along the way. For example, we are able to perform thermal versus chemical extractions separately, helping to differentiate the primary versus secondary fluid recovery quantification. We are also able to perform our chemical extraction with a variety of chemical reagents and can customize per the client’s needs to mimic secondary or tertiary extraction mechanisms. This can aid in the client understanding how certain downhole/subsurface chemical compositions will interact with their development wells or post production abandonment fields where flooding may be a possibility.
GeoMark is also positioned to combine our TruSat work flow and application to our enhanced oil recovery capabilities in combination with our PVT laboratory. The powerful integrative combination can aid in those later life cycle projects, goals and objectives.
Executive Summary
Over the last 10 years, E&P industry investigators have been looking at oil and gas service laboratories, comparing their ‘unconventional’ core analysis methods and resultant data. This core analysis review called for GeoMark and other labs to develop better unconventional-conventional rock and fluid property analyses. The TruSat workflow is our answer to that call. The value add of rock property constraint measured on subsurface mass should yield no debate regarding the overall evaluation and beneficial insights into uncertainty reduction and, thereby, risk assessment — particularly for an investigator trying to constrain original oil-in-place estimates. Without constraint from laboratory measurements, the evaluation of hydrocarbon potential could be significantly off-base and misleading. However, the accuracy in quantification and validation of the laboratory measurements performed does matter, and can significantly vary depending on the rock and fluid property measurement workflows.
Methodology Overview
The TruSat workflow was developed by first attempting to understand the competing retort and extraction processes, followed by rigorous experimental standard trials conducted to determine needed improvements. The result was the development and application of a workflow that is unique and more accurate than any other method practiced in the oil and gas laboratory market to date. TruSat greatly improves the accuracy of porosity and saturation data through increased process controls, and the integration of multiple independent tools and methods, including as-received nuclear magnetic resonance (NMR) and geochemistry (TOC/HAWK), while also allowing for customization of analytical programs. The unique workflow uses a dual-retort process to quantitatively measure total, free, and bound water, alongside the accurate hydrocarbon saturation measurements with a closed retort collection efficiency average of ~99%+. Figure 1 represents this workflow in two forms that can be used to fully assess the rock and fluid volumetric space.
Results and Why it Matters
- Fluid loss correction — this quantifies the lost fluid volume during the laboratory preparation process for crushed rock investigation. It allows an investigator to correct for the lost fluid fraction impacting fluid saturated results. (Figure 2)
Click the learn more button to read about improvements over historical methods.
Figure 2. Intact rock mass NMR fluid quantification (cc/g) versus crushed rock mass NMR fluids (cc/g). Variance along the 1:1 indicates lost fluid fraction during laboratory preparation of crushed mass. Quantification of this loss allows the correction for the missing fluid fraction.
- Acquisition of both bulk density (g/cc) and grain density (g/cc) measurements — provides the needed data to calibrate multimineral petrophysical models, as well as report two independent assessments of total porosity. (Figure 3)
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. [/av_textblock] [/av_section] [av_section min_height='' min_height_pc='25' min_height_px='500px' padding='default' custom_margin='0px' custom_margin_sync='true' color='main_color' background='bg_color' custom_bg='' background_gradient_color1='' background_gradient_color2='' background_gradient_direction='vertical' src='' attachment='' attachment_size='' attach='scroll' position='top left' repeat='no-repeat' video='' video_ratio='16:9' overlay_opacity='0.5' overlay_color='' overlay_pattern='' overlay_custom_pattern='' shadow='no-border-styling' bottom_border='no-border-styling' bottom_border_diagonal_color='#333333' bottom_border_diagonal_direction='' bottom_border_style='' custom_arrow_bg='' id='sectionfour' custom_class='icon-text padded-section padded-section--flush-bottom' aria_label='' av_element_hidden_in_editor='0' av_uid='av-a5u2'] [av_textblock size='' av-medium-font-size='' av-small-font-size='' av-mini-font-size='' font_color='' color='' id='' custom_class='' av_uid='av-kljzrrv9' admin_preview_bg='']
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.
Contact Us
GeoMark Research, Ltd.
9748 Whithorn Drive | Houston, Texas 77095