Study Quizzes

• Petroleum Geology Quiz — 15 questions on source rocks, migration and traps.
• Drilling Fluids Quiz — 10 questions on mud functions, rheology and solids control.
• Seismic Interpretation Quiz — 12 questions on horizons, faults and time-to-depth conversion.
• Looking for revision notes instead? See the study guides.

Covers: Source rocks and kerogen types · Primary and secondary migration · Structural and stratigraphic traps · Reservoir seals and cap rocks

1. Which kerogen type is most likely to generate oil rather than gas?

   Answer: Type II kerogen. It is hydrogen-rich (typically marine algal/bacterial origin) and lies in the oil window during catagenesis; Type III is gas-prone and Type IV is inert.

2. What is the difference between primary and secondary migration?

   Answer: Primary migration is expulsion of hydrocarbons out of the low-permeability source rock into a carrier bed; secondary migration is movement through permeable carrier beds and reservoirs along the buoyancy-driven pathway until a trap or the surface.

3. Give one example of a structural trap and one of a stratigraphic trap.

   Answer: Structural: anticline or fault-bounded block formed by tectonic deformation. Stratigraphic: pinch-out of a sandstone into shale, or an unconformity trap formed by depositional changes rather than deformation.

4. Why does a reservoir need a seal to hold hydrocarbons?

   Answer: Buoyancy pushes lighter hydrocarbons upward through water-saturated pore space. A low-permeability cap rock (e.g. shale or evaporite) has entry pressures high enough to stop this flow, so the column can accumulate beneath it.

5. What does TOC measure, and what minimum TOC is generally considered fair source-rock potential?

   Answer: Total Organic Carbon measures the weight percent of organic carbon in the rock. Around 0.5% is generally taken as the lower bound for fair source potential; >2% is good to excellent for oil-prone shales.

Covers: The functions of drilling mud · Rheology: yield point and gel strength · Overbalance and well control basics · Solids control equipment

1. List three key functions of drilling fluid in a normal rotary operation.

   Answer: Any three of: carry cuttings out of the hole (cuttings transport), cool and lubricate the bit, exert hydrostatic pressure to control formation fluids, stabilize the wellbore, form filter cake, transmit hydraulic energy to the bit.

2. What is the difference between yield point and gel strength?

   Answer: Yield point is the attractive-force-based resistance to initial flow under continuous circulation (measured from plastic viscosity at 600/300 rpm). Gel strength measures thixotropy — the fluid's ability to suspend cuttings when circulation stops.

3. What does 'overbalanced' drilling mean, and why is some overbalance normally desired?

   Answer: Mud hydrostatic pressure exceeds formation pore pressure. Overbalance prevents formation fluids flowing into the wellbore (kicks), at the cost of some filtrate invasion — so it is kept only slightly above pore pressure.

4. Name the solids-control equipment in the order mud passes after returning from the annulus.

   Answer: Shale shaker (first), then desander, desilter (hydrocyclones), and finally the centrifuge for the finest/density-recovery duty.

5. Why is a high mud pH maintained in many freshwater bentonite systems?

   Answer: Bentonite hydrates and yields best in alkaline conditions; higher pH also suppresses corrosion and helps control calcium contamination. Typically pH ~9.5–10.5 is targeted.

Covers: Two-way travel time and velocity · Picking horizons and faults · Zero-phase vs minimum-phase wavelets · Time-to-depth conversion

1. Why do seismic sections record two-way travel time rather than depth?

   Answer: The source wave travels down to a reflector and back up to the receivers, so recorded arrival times are round-trip. Depth requires dividing by velocity — which is only known accurately where wells or velocities are available.

2. A reflector sits at 1.5 s TWT with average velocity 3000 m/s. What is its approximate depth?

   Answer: Depth = v × TWT / 2 = 3000 × 1.5 / 2 = 2250 m.

3. How does a normal fault appear on a seismic section versus a reverse fault?

   Answer: A normal fault shows the hanging wall dropped relative to the footwall across a dipping reflector discontinuity; a reverse fault shows the hanging wall pushed up, often with repeated sections across the fault plane.

4. What is a 'flat spot', and why can it indicate a hydrocarbon contact?

   Answer: A flat spot is a near-horizontal reflector inside a tilted structure — the gas-oil or oil-water contact. Because the contact is controlled by gravity it stays flat even when bedding dips, making it a direct hydrocarbon indicator.

5. Why is time-to-depth conversion sensitive to interval velocity errors?

   Answer: Depth accumulates the product of each interval's velocity and travel time. A small systematic velocity error compounds over many intervals, so a few percent error can shift a prospect tens of metres vertically.

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