GATE Petroleum Engineering Petroleum Formation Evaluation: Evaluation of petrophysical of sub-surface formations Flashcards

24 sample cards from the Petroleum Formation Evaluation: Evaluation of petrophysical of sub-surface formations deck

Sampled from the end of the deck, so these are different cards from the ones shown on the syllabus page.

1. Name the principal sensors found in a typical Production Logging Tool string.

   Spinner flowmeter (velocity/flow rate), fluid-density (gradiomanometer), capacitance/water-hold-up meter, temperature sensor, pressure gauge, gamma ray and casing collar locator (CCL) for depth correlation.

2. How does a spinner (continuous) flowmeter determine downhole flow rate?

   The spinner rpm is proportional to fluid velocity past the tool. Multiple passes at different cable speeds are made and spinner response is plotted vs cable speed; the calibrated slope and zero-crossing give the apparent fluid velocity, which times the pipe area gives volumetric flow rate.

3. What does a gradiomanometer (fluid-density tool) measure and how is it used in production logging?

   It measures the pressure difference over a fixed vertical spacing, giving the in-situ fluid density (mixture density). This is used to determine fluid hold-up and identify water entry vs oil/gas in multiphase flow.

4. How is a Temperature log used qualitatively in production logging?

   Departures from the geothermal gradient localize fluid entry: gas entry causes cooling (Joule-Thomson expansion), liquid entry shows anomalies, and behind-pipe flow or injection zones create characteristic temperature anomalies — useful for detecting leaks and crossflow.

5. List two examples of 'Special Logging Tools' beyond standard porosity/resistivity logs and their function.

   Dipmeter / borehole imaging tools (formation dip and structural/sedimentary features), and the Geochemical/Spectroscopy logs (elemental capture spectroscopy for mineralogy); also NMR (free-fluid/permeability) and the Formation Micro Scanner are special tools.

6. What is the purpose of Casing Inspection Tools and name two operating principles they use.

   To evaluate the mechanical integrity of casing — detecting corrosion, pitting, holes, wear and wall-thickness loss. Principles: (1) electromagnetic — eddy-current/flux-leakage tools, and (2) mechanical multifinger caliper, plus ultrasonic thickness imaging.

7. How does an electromagnetic flux-leakage casing inspection tool detect defects?

   It magnetizes the casing wall; where corrosion, pits or holes reduce metal, magnetic flux 'leaks' out of the pipe and is sensed by detector coils. The leakage signal magnitude indicates metal loss and defect severity.

8. What is the Formation Micro Scanner (FMS) / micro-imager and what does it produce?

   A pad-mounted array of many small electrode 'buttons' that make high-resolution microresistivity measurements, producing an oriented electrical image of the borehole wall. It resolves fine features — fractures, vugs, bedding, dip — that conventional logs miss.

9. List three geological features that borehole image logs (FMS/FMI) are used to identify.

   (1) Open vs healed/natural fractures and their orientation, (2) sedimentary/structural dip and bedding (net-to-gross, thin beds), and (3) secondary porosity such as vugs and breakouts/stress-induced features for geomechanics.

10. On what physical principle does NMR (Nuclear Magnetic Resonance) logging operate?

    It measures the magnetic response of hydrogen nuclei (protons) in pore fluids. A static field aligns the protons, an RF pulse sequence tips them, and the decay of the resulting spin-echo signal (relaxation) is recorded — independent of rock matrix.

11. What petrophysical information does the NMR $T_2$ relaxation-time distribution provide?

    The $T_2$ distribution partitions porosity by pore size: short $T_2$ = clay-bound and capillary-bound water (BVI), long $T_2$ = free movable fluid (FFI/BVM). It yields total porosity (matrix-independent), bound-fluid volume, free-fluid volume and pore-size distribution.

12. Give the Timur-Coates permeability equation derived from NMR.

    $$k = \left(\frac{\phi}{C}\right)^{4}\left(\frac{FFI}{BVI}\right)^{2}$$ where $\phi$ is NMR porosity, FFI is free-fluid index, BVI is bulk-volume irreducible water and C is a calibration constant.

13. Give the SDR (mean-$T_2$) NMR permeability model.

    $$k = a\,\phi^{4}\,T_{2,\mathrm{lm}}^{2}$$ where $\phi$ is NMR porosity, $T_{2,\mathrm{lm}}$ is the logarithmic mean of the $T_2$ distribution and a is a formation constant. (Works best in water-saturated rock.)

14. Contrast 'deterministic' and 'statistical/probabilistic' log interpretation methods.

    Deterministic (quick-look) applies fixed equations zone-by-zone (e.g., Archie, density-porosity) solving for each unknown sequentially. Statistical/probabilistic (e.g., multimineral inversion like ELAN) simultaneously solves an over-determined set of tool-response equations minimizing error to give the best-fit volumetric model.

15. Describe the standard quick-look workflow for evaluating a clean reservoir from logs.

    (1) Use GR/SP to flag permeable, clean zones and $V_{sh}$; (2) compute porosity from density/neutron/sonic; (3) determine $R_w$ (SP or water zone); (4) read $R_t$ from deep resistivity; (5) apply Archie to get $S_w$; (6) flag pay where $\phi$, $S_w$ and $V_{sh}$ meet cutoffs.

16. What is the Pickett plot and what is it used to determine?

    A log-log crossplot of $R_t$ (x-axis) versus porosity $\phi$ (y-axis). Water-bearing points fall on a line of slope $-m$ whose intercept gives $R_w$; lines parallel above it are constant-$S_w$ lines. It yields m, $R_w$ and $S_w$ graphically (rearranged Archie).

17. How does the Hingle plot differ from the Pickett plot?

    The Hingle plot uses special resistivity-grid (linear in $R_t^{-1/m}$) versus a porosity-sensitive parameter; the $S_w = 100\%$ water line passes through the origin and its slope relates to $R_w$. Both determine $R_w$ and $S_w$, but Hingle plots a porosity log directly while Pickett uses log-log axes.

18. What is the purpose of a Neutron-Density crossplot?

    Plotting neutron porosity (x) vs density porosity/bulk density (y) lets you read true porosity and identify lithology: points fall on/between the sandstone, limestone and dolomite lithology lines. Departures indicate gas (toward density), shale (toward neutron) or mixed mineralogy.

19. What is the M-N crossplot used for, and how are M and N defined?

    It identifies lithology and secondary porosity using three porosity logs. $$M = \frac{\Delta t_{f}-\Delta t}{\rho_b - \rho_f}\times 0.01, \qquad N = \frac{\phi_{Nf}-\phi_N}{\rho_b-\rho_f}$$ Both M and N are largely porosity-independent, so cross-plotting them clusters points by mineral.

20. What does the MID (Matrix Identification) plot determine and what two parameters does it use?

    It identifies matrix mineralogy by plotting apparent matrix density $(\rho_{ma})_a$ against apparent matrix transit time $(\Delta t_{ma})_a$ — derived from density, neutron and sonic logs. Clusters reveal sandstone, limestone, dolomite or anhydrite and flag secondary porosity/gas.

21. How is the volume of shale combined into a shaly-sand water saturation model — name one such model.

    The Simandoux, Indonesia (Poupon-Leveaux), or Waxman-Smits models correct Archie for clay conductivity. E.g., the Indonesia equation: $$\frac{1}{\sqrt{R_t}} = \left(\frac{V_{sh}^{(1-V_{sh}/2)}}{\sqrt{R_{sh}}} + \frac{\phi^{m/2}}{\sqrt{a R_w}}\right) S_w^{n/2}$$

22. Define 'moveable hydrocarbon index' and how it is found from $S_w$ and $S_{xo}$.

    Moveable hydrocarbons exist when filtrate has displaced oil in the flushed zone, i.e. $S_{xo} > S_w$. The ratio $\dfrac{S_w}{S_{xo}}$: a value $\approx 1$ means hydrocarbons were not moved (low permeability/residual), while $< 0.7$ indicates moveable hydrocarbons.

23. What is 'net pay' and which three cutoffs are typically applied to define it from logs?

    Net pay is the cumulative reservoir thickness that can produce economically. It is defined by applying cutoffs on (1) porosity $\phi$ (minimum), (2) water saturation $S_w$ (maximum), and (3) shale volume $V_{sh}$ (maximum), summing only intervals meeting all three.

24. Why are combination tool runs (e.g., Triple Combo) used rather than single logs in formation evaluation?

    No single log gives all properties; combining GR, resistivity (shallow/medium/deep), density, neutron and sonic resolves lithology, porosity, $R_w$, $R_t$ and saturation simultaneously, allows crossplot lithology/gas identification, and provides redundancy to correct borehole and invasion effects.

What this deck covers

Petroleum Formation Evaluation: Evaluation of petrophysical of sub-surface formations flashcards FAQ