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

What are typical matrix densities ($\rho_{ma}$) for sandstone, limestone and dolomite used in density-porosity?

Sandstone $\rho_{ma} = 2.65\ \mathrm{g/cm^{3}}$, limestone $= 2.71\ \mathrm{g/cm^{3}}$, dolomite $= 2.87\ \mathrm{g/cm^{3}}$ (fresh-water $\rho_f \approx 1.0\ \mathrm{g/cm^{3}}$).

What is the photoelectric factor (Pe) from the density tool used for, and give typical values for sandstone, limestone and dolomite.

Pe (in barns/electron) is a lithology indicator largely independent of porosity. Sandstone $Pe \approx 1.8$, dolomite $\approx 3.1$, limestone $\approx 5.1$; anhydrite $\approx 5.05$, barite very high.

What does the Neutron log measure and what does it actually respond to?

A neutron source emits fast neutrons that are slowed mainly by collisions with hydrogen. The detector response reflects the hydrogen index, so the neutron log reads liquid-filled porosity (water + oil), since H is concentrated in pore fluids.

Explain the 'gas effect' (crossover) seen on combined Neutron-Density logs.

Gas has low hydrogen density, so the neutron log reads too low a porosity while the density log reads too high a porosity. The curves cross over (neutron < density on compatible scales), indicating gas-bearing zones.

How is gas-corrected porosity often estimated from neutron and density porosities?

A common approximation in gas/light-hydrocarbon zones is $$\phi = \sqrt{\frac{\phi_{N}^{2} + \phi_{D}^{2}}{2}}$$ while in liquid zones $\phi \approx \dfrac{\phi_N + \phi_D}{2}$.

On what principle does the Acoustic (Sonic) log operate, and what does it measure?

It measures the interval transit time $\Delta t$ (slowness, in $\mu s/ft$) — the time for a compressional sound wave to travel one foot through the formation adjacent to the borehole, related to porosity and lithology.

State the Wyllie time-average equation for sonic porosity.

$$\phi_{S} = \frac{\Delta t_{log} - \Delta t_{ma}}{\Delta t_{f} - \Delta t_{ma}}$$ where $\Delta t_{ma}$ is matrix transit time and $\Delta t_{f}$ is fluid transit time ($\approx 189\ \mu s/ft$ for fresh mud filtrate).

Give typical matrix transit times $\Delta t_{ma}$ for sandstone, limestone and dolomite.

Sandstone $\Delta t_{ma} \approx 55.5\ \mu s/ft$ (or 51.0), limestone $\approx 47.5\ \mu s/ft$, dolomite $\approx 43.5\ \mu s/ft$. Fluid $\Delta t_f \approx 189\ \mu s/ft$.

When is the Raymer-Hunt-Gardner (RHG) sonic relation preferred over Wyllie?

RHG is preferred in unconsolidated/uncompacted sands and high-porosity rocks where Wyllie overestimates porosity. Wyllie requires a compaction correction $B_{cp}$ in shaly, undercompacted sands.

What is the purpose of the Cement Bond Log (CBL)?

To evaluate the quality of the cement bond between casing and cement (and indirectly cement-to-formation), confirming zonal isolation behind the casing by measuring the attenuation of an acoustic signal traveling along the casing.

On a CBL, what does a high (large) amplitude reading indicate versus a low amplitude reading?

High amplitude = free (unbonded) pipe — sound travels freely along casing, poor cement bond. Low amplitude = good cement bond — the cement attenuates the casing signal. The amplitude is measured at a fixed receiver (typically 3 ft).

What does the Variable Density Log (VDL) display and what is it used for?

The VDL is a full-waveform display (intensity-modulated 'wiggle' presentation, usually from a 5 ft receiver) showing casing, formation and fluid arrivals. Straight, parallel dark/light bands = free pipe; wavy formation arrivals indicate good casing-to-cement and cement-to-formation bonding.

On a VDL, what pattern indicates good cement-to-formation bonding versus a microannulus or channeling?

Strong, wavy formation arrivals (and weak straight casing lines) indicate good cement-to-formation bond. Strong straight casing arrivals with no formation signal indicate free pipe; a microannulus or channel shows persistent casing arrivals despite cement presence.

What does USIT (UltraSonic Imager Tool) measure and what advantage does it have over CBL?

USIT uses a rotating ultrasonic (pulse-echo) transducer to measure the acoustic impedance of material behind casing, providing a 360° azimuthal image. It distinguishes solid cement, liquid and gas behind pipe and detects channels and microannuli that the omnidirectional CBL averages out.

Acoustic impedance is the basis of USIT cement evaluation — write its definition.

$$Z = \rho \, v$$ the product of material density $\rho$ and acoustic velocity $v$. High Z indicates solid cement; low Z indicates liquid (good for spotting channels); very low Z indicates gas behind casing.

What is the SFT (Selective/Sidewall Formation Tester) and what does it obtain?

An early wireline formation tester that takes formation-fluid pressure measurements and recovers fluid samples at selected depths by setting a pad against the borehole wall, providing reservoir pressure and fluid type.

What does the RFT (Repeat Formation Tester) provide and what is its key advantage over the SFT?

The RFT measures formation pressure and takes fluid samples and, crucially, can take an unlimited number of repeat pretests on a single run. Its pressure-vs-depth profile yields fluid density gradients and fluid contacts (GOC, OWC).

How are fluid density and fluid contacts identified from RFT pressure-depth data?

Plotting pressure vs depth gives straight-line gradients whose slope $\dfrac{dP}{dD} = \rho g$ yields fluid density (gas < oil < water). Intersections of two gradient lines mark fluid contacts such as the gas-oil and oil-water contacts.

From RFT pretest data, how is reservoir flow capacity / drawdown mobility estimated?

From the pressure drawdown during the pretest, mobility $\dfrac{k}{\mu}$ is estimated via the spherical/steady-state relation $$\frac{k}{\mu} = \frac{C\,q}{\Delta p\, r_{p}}$$ relating flow rate q, drawdown $\Delta p$ and probe radius $r_p$ through a shape/flow constant C.

What is a Production Logging Tool (PLT) and what is its primary objective?

A combination of sensors run in a producing/injecting well (usually through tubing) to measure downhole flow contributions — identifying which zones produce or take fluid, the flow rate, and the type of fluid (oil/water/gas) from each interval.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.)

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.

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.

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).

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.

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.

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.

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.

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: $$\frac{1}{\sqrt{R_t}} = \left(\frac{V_{sh}^{(1-V_{sh}/2)}}{\sqrt{R_{sh}}} + \frac{\phi^{m/2}}{\sqrt{a R_w}}\right) S_w^{n/2}$$

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.

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.

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.