Petrophysical Study of Reservoir Rocks: Use of Image Analysis Software (IAS) and Mercury Injection Capillary Pressure (MICP) Data
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Petrophysical Study of Reservoir Rocks: Use of Image Analysis Software (IAS) and Mercury Injection Capillary Pressure (MICP) Data
- 1. Petrophysical Study of Reservoir Rocks: Use of Image Analysis Software (IAS) and Mercury Injection Capillary Pressure (MICP) Data Cristian R. Medina April 2015 1
- 2. Acknowledgements John Rupp, Barb Hill, Carley Gasaway, and Drew Packman (IGS) Steve Greb and Dave Harris (KGS) Ron Riley and Matt Erenpreiss (ODNR)
- 5. Why Porosity (∅)? Storage Capacity: 𝑀 = 𝐴𝑟𝑒𝑎 ∗ 𝑇ℎ𝑖𝑐𝑘𝑛𝑒𝑠𝑠 ∗ 𝜌 𝐶𝑂2 ∗ ∅ Units: 𝑘𝑔 = 𝑚2 ∗ 𝑚 ∗ 𝑘𝑔 𝑚3 ∗ − Other geologic aspects where porosity is relevant: • Oil and gas reservoir • Groundwater • Injection of waste fluids • Gas storage
- 7. Pore Characterization: Instrumentation • Helium porosimetry • Helium/N/CO2 adsorption • Scanning Electron Microscopy (SEM) • (Ultra) Small Angle Neutron Scattering (SANS/USANS) • Optical Microscopy and Image Analysis Software (IAS) • Mercury Injection Capillary Pressure (MICP)
- 8. Scale and Instruments 8SEM images taken by Carley Gasaway
- 9. Methodology ImageJ is a public domain image processing program developed at the National Institutes of Health. The source code for ImageJ is freely available. Porosity (f) • f from core analysis • Two-Dimensional f ~1 mm
- 12. Methodology: Thin Sections, Photomicrographs, and Pre-processing Thin Section (30 mm) 1mm=103 microns (mm)
- 14. 14 Identifying Micro- Versus Macro- Porosity Using ImageJ
- 15. Optical Microscopy and Image Analysis Software: Visualizing Porosity, Permeability, and Depth in Sandstones 15
- 16. Petrophysics Study on Carbonates from the Cambro-Ordovician Knox Supergroup Measured depth, Top of Knox (ft) 0 2500 10000 15000
- 17. Optical Microscopy and Image Analysis Software: Visualizing Porosity and Permeability in Carbonates 17
- 18. What can we Measure?
- 19. Elements of a Pore Measured on ImageJ 19 • Area (A) • Perimeter (P) • Major/Minor Axis • Circularity (C) • Aspect ratio (AR) • Roundness (R) 𝐶 = 4 ∗ 𝜋 ∗ 𝐴 𝑃 𝑅 = 4 ∗ 𝐴 𝜋 ∗ (𝑀𝑎𝑗𝑜𝑟 𝐴𝑥𝑖𝑠)2 2 mm.
- 20. Results: Porosity from Core Analysis vs. IAS 20 #1 #2 #3 0 1 10 0.1 1 10 2DPorosity(AllPores) Core Porosity (%) Sandstones Carbonates
- 21. Resolving Discrepancy #1 21 F = 0.3 F = 1.9
- 22. 22 ID #162029 Depth: 1646 ft Fcore = 1.4 Resolving Discrepancy #2 Pore Throat Radius (microns)
- 23. Effect of Dual Porosity in Carbonates 23 Resolving Discrepancy #3 Fcore = 2.6
- 25. 25 0 1 10 0.1 1 10 2DPorosity(AllPores) Core Porosity (%) Sandstones Carbonates Results: Porosity from Core Analysis vs. IAS
- 26. Porosity from IAS and its Dependency With Pore Size
- 29. Mercury Injection Capillary Pressure (MICP) 29 Source: Crain's petrophysical handbook (www.spec2000.net)
- 30. Data Interpretation and Analysis 30 Source: Bliefnick and Kaldi, 1996
- 31. Theory and Key-Parameters ∆𝑃 = 2 𝛾 cos 𝜃 𝑟𝑝𝑜𝑟𝑒 31 Contact Angle (θ)
- 32. Limitations: It Measures the Largest Entrance Towards a Pore. 32
- 33. 33
- 34. 34 Results from MICP (Indirect Method) Pore Size between ~[0.1 - 25] microns Results from ImageJ (Direct Method) Pore Size between ~[15 - 300] microns
- 35. Conclusions • Image Analysis Software provides a good porosity estimator. • The study of micro- vs. macro- porosity is limited by instrument resolution. Therefore, multiple techniques should be used in a complementary way. • Pore shape descriptors and pore size distribution can shed light on reservoir performance. • ImageJ measures pores, whereas MICP describes the pore throats. • Pore systems in carbonates are more complex than those in clastics. Therefore their characterization is more challenging. • MICP advantages: rock type, reservoir quality, and pore size distribution. • Value of a thin section: $30. One MICP test: $500-900. 35
- 36. Questions? 36
- 37. References Archie, G.E., 1950, Introduction to petrophysics of reservoir rocks: AAPG Bulletin, v. 34, p. 943-961. Bliefnick, D.M., and Kaldi, J.G., 1996, Pore geometry; control on reservoir properties, Walker Creek Field, Columbia and Lafayette counties, Arkansas: AAPG Bulletin, v. 80, p. 1027-1044. Grove, C., and Jerram, D.A., 2011, jPOR: An ImageJ macro to quantify total optical porosity from blue- stained thin sections: Computers & Geosciences, v. 37, p. 1850-1859. IPCC, 2005, IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change: Cambridge, UK, Cambridge University Press. Rasband, W.S., ImageJ, US National Institutes of Health, Bethesda, Maryland, USA, http://rsb.info.nih.gov/ij/, 1997–2009.
Editor's Notes
- The term petrophysics was first invented by Gus Archie. Why petrophysics?
- He compares the term petrophysics with geophysics and points out the difference in term of the scale of study
- One of the main petrophysical parameter is porosity…
- End up with “How do we understand the factors that control the residual trapping?”
- CONSIDER DELETING THIS
- CONSIDER DELETING THIS
- 30 samples from Indiana 10 from OK 12 from KY
- Area: Area of selection in square pixels or in calibrated square units (e.g., mm2, μm2, etc.) Perimeter The length of the outside boundary of the selection. Shape descriptors: Calculates and displays the following shape descriptors: Circularity 4p × [Area]/[Perimeter]2 with a value of 1.0 indicating a perfect circle. As the value approaches 0.0, it indicates an increasingly elongated shape. Values may not be valid for very small particles. Uses the heading Circ. Aspect ratio: The aspect ratio of the particle’s fitted ellipse, i.e., [Major Axis]/[Minor Axis] . If Fit Ellipse is selected the Major and Minor axis are displayed. Uses the heading AR. Roundness 4 × [Area]/( p ×[Major axis]2) or the inverse of Aspect Ratio. Uses the heading Round. 2.3 Porosity Determination The best way of determining porosity is to carry out experiments on core extracted from the well. These techniques will be examined in detail in the Formation Evaluation course later in the MSc. However, the basic techniques will be described here. It should be noted that core determined porosities have a much higher degree of accuracy than porosities determined from down-hole tools, but suffer from sampling problems. Taken together core and borehole determined porosities optimize accuracy and high resolution sampling. There are at least 4 common methods of measuring the porosity of a core. These are: · Buoyancy · Helium porosimetry · Fluid saturation · Mercury porosimetry
- SS higher Carbonates has dual porosity
- Note the bi-modal distribution of pore size from MICP analysis. Since ImageJ only picks the larger volume of these ranges…(possible cause)
- SS higher Carbonates has dual porosity As I mention before, what would be the minimum pore size that ImageJ is detecting as true porosity?
- >0.000144 mm2 (2 by 2 pixels)
- Capillary pressure is a measurement of the force that draws a liquid up a thin tube, or capillary. Fluid saturation varies with the capillary pressure, which in turn varies with the vertical height above the free water level. Typically, laboratory measurements of capillary pressure are plotted on linear X - Y coordinate graph paper, as shown at the right. Capillary pressure measured in the laboratory can be performed using air-brine or mercury injection (MICP) methods. The later is usually used in poorer quality reservoirs. The pressures involved are quite different so the graphs from the two methods are difficult to compare directly. By converting the pressure axis to height above free water (described later on this page), comparisons can be made quite easily. Petrophysicists use cap pressure water saturation, adjusted for height above the free water level, and residual oil saturation (Sor) to help calibrate log derived water saturation in oil and gas reservoirs above the transition zone, and to help detect depleted reservoirs. It will not help calibrate SW in partially depleted zones. Accumulation of hydrocarbon in a reservoir is a drainage process and production by aquifer drive or waterflood is an imbibition process. The capillary pressure curve is different for these two processes. DRAINAGE •Fluid flow process in which the saturation of the nonwetting phase increases. Mobility of nonwetting fluid phase increases as nonwetting phase saturation increases. IMBIBITION •Fluid flow process in which the saturation of the wetting phase increases. Mobility of wetting phase increases as wetting phase saturation increases https://www.spec2000.net/09-cappres.htm
- A key assumption in mercury porosimetry is the pore shape. Essentially all instruments assume a cylindrical pore geometry. Limitation 1: It measures the largest pore throat. Limitation 2: Destructive method.
- Schematic representation of pores. It can measure diameters that range from 0.003 microns to 360 microns.
- Unlike sandstones, carbonate pore systems do not generally exhibit a relationship between pore throat size and pore body size. The connectivity between pores in carbonates is generally fairly chaotic.