Petroleum geology

In short

Petroleum geology is the study of how hydrocarbons form in sedimentary rocks, move through them and get trapped in commercially producible accumulations. It supplies the five conditions every prospect is judged on - source, reservoir, seal, trap and timing - and the rock properties (porosity, permeability, saturation) that fix how much oil or gas is in place and how much can be recovered. It is examined in the Geology and Exploration paper of every petroleum engineering degree and carries a solid block of marks in GATE PE (Section on petroleum exploration), plus ONGC/OIL/GAIL/IOCL graduate trainee and DGH technical interviews. Working geoscientists and reservoir engineers at ONGC, Oil India, Cairn (Vedanta), Reliance-BP, Vedanta and service companies use the same framework daily for basin screening, prospect ranking and volumetric estimation under the DGH's reserve-reporting rules.

Explained

Origin of petroleum and the source rock

• Organic (biogenic) theory is the accepted explanation: marine/lacustrine plankton, algae and land plant debris are buried with fine sediment in an oxygen-poor (anoxic) setting, preserved from decay, and converted by heat over millions of years.
• Inorganic theories (carbide, cosmic, Mendeleev's) are historical and examined only as rejected alternatives - they cannot explain optical activity, biomarkers, porphyrins and the invariable association with sedimentary basins.
• Source rock: fine-grained, organic-rich rock - typically black shale, marl or carbonate mudstone. Judged by three measures:
  • TOC (total organic carbon): below 0.5% poor, 0.5-1% fair, 1-2% good, above 2% very good to excellent.
  • Kerogen type (from H/C and O/C ratios, van Krevelen diagram): Type I lacustrine algal - strongly oil-prone; Type II marine - oil and gas; Type III terrestrial woody/humic - mainly gas; Type IV inert (residual), generates nothing.
  • Maturity: measured by vitrinite reflectance (Ro, %), Tmax from Rock-Eval pyrolysis, and spore colour.
• Rock-Eval pyrolysis gives S1 (free hydrocarbons), S2 (hydrocarbons from kerogen cracking), S3 (CO₂), from which HI = S2/TOC × 100 (hydrogen index, mg HC/g TOC) and PI = S1/(S1+S2) (production index) are computed.
• Diagenesis - catagenesis - metagenesis: at shallow depth and low temperature biogenic methane plus kerogen formation (diagenesis, Ro < 0.5%); catagenesis (roughly 60-150 °C, Ro 0.5-1.3%) is the oil window; wet gas and condensate follow (Ro 1.3-2.0%); metagenesis above ~200 °C leaves dry methane and graphitic residue.
• Geothermal gradient in Indian basins is typically about 2-3 °C per 100 m (higher in Cambay/Barmer rift basins, lower in thick foreland sections), so the oil window commonly sits roughly 2-4 km deep - depth alone never defines maturity, temperature history does.

Reservoir rock: porosity, permeability, saturation

• Reservoir rock must store and transmit fluid. Sandstones (about 60% of world reservoirs) and carbonates (limestone, dolomite) dominate; fractured basement and volcanics are rarer (Bombay High has fractured/weathered basement pay; Mumbai offshore's main pay is the Miocene Bombay Formation (L-III) limestone, with the Eocene-Oligocene Bassein limestone below).
• Porosity φ = pore volume / bulk volume, as a fraction or percent.
  • Total vs effective porosity: effective counts only interconnected pores - the only kind that produces.
  • Primary (intergranular, formed at deposition) vs secondary (fracture, vuggy, dissolution, dolomitisation).
  • Rough rating: <5% negligible, 5-10% poor, 10-15% fair, 15-20% good, >20% very good.
  • Controls: sorting (well-sorted is more porous), grain shape, packing, cementation, compaction. Porosity of a sand is independent of grain size; permeability is not.
• Permeability k = ability to transmit fluid, in darcy (D) or millidarcy (mD). 1 darcy ≈ 0.9869 µm² ≈ 10⁻¹² m².
  • Absolute (single fluid saturating the rock), effective (one phase at a given saturation) and relative (ke/k, a fraction) permeability.
  • Klinkenberg effect: gas permeability measured in the lab is higher than liquid permeability because of gas slippage at pore walls; it is corrected by extrapolating k against 1/pmean.
  • Typical good reservoir: 100-1,000 mD; tight gas and shale are in the microdarcy-nanodarcy range and need hydraulic fracturing.
• Saturation: Sw + So + Sg = 1. Irreducible water saturation (Swi) is the water held by capillarity that cannot be displaced; residual oil saturation (Sor) is the oil left after a waterflood.
• Capillary pressure Pc = 2σcosθ/r controls the height of the transition zone between water and hydrocarbon, and hence the free water level versus the oil-water contact.
• Wettability: water-wet rock (most clastics) produces oil better during waterflooding than oil-wet rock. Net-to-gross (N/G) is the fraction of gross interval meeting porosity/permeability/Sw cut-offs.

Cap rock (seal), migration and trap

• Cap rock / seal: low-permeability rock with high capillary entry pressure - shale, evaporite (salt, anhydrite), tight carbonate. It must be laterally continuous, ductile (resists fracturing) and thick enough; salt is the best seal because it flows rather than cracks.
• Primary migration: expulsion of hydrocarbons from the compacting source rock through microfractures and kerogen networks, driven by compaction, overpressure and the volume increase on generation. Short distance, inefficient (only a part of generated oil is expelled).
• Secondary migration: buoyancy-driven movement of a separate oil/gas phase through a carrier bed (or fault/unconformity) up-dip until a seal stops it. Opposed by capillary resistance; distances of tens to hundreds of kilometres are possible.
• Tertiary migration (remigration/seepage) occurs when a trap is breached - tilting, faulting or erosion - giving surface oil/gas seeps and tar mats, a classic surface exploration clue (seeps at Digboi, Assam, led to India's first oil well in 1889).
• Trap = geometry of reservoir plus seal that halts migration and holds hydrocarbons. Classification:
  • Structural traps (deformation): anticlinal/domal (commonest - Bombay High, Ankleshwar), fault traps, fault-and-dip, salt-dome related, fracture traps in brittle rock.
  • Stratigraphic traps (depositional/erosional): reef and carbonate buildups, channel and bar sands, pinch-out, lenticular sand bodies, unconformity and truncation traps, palaeogeomorphic (buried hills).
  • Combination traps: structure plus stratigraphy - most real fields, including many Cambay and KG fields.
  • Hydrodynamic traps: flowing formation water tilts the hydrocarbon-water contact and holds oil where there is no closure.
• Trap vocabulary: spill point (the lowest closing contour - oil spills beyond it), closure (vertical height from crest to spill point), GOC and OWC (gas-oil, oil-water contacts), gas cap, pay zone (gross pay vs net pay), column height.
• Timing (critical moment): the trap must exist before or during migration. A structure formed after generation and migration is empty however perfect it looks - a favourite interview and viva question.

Petroleum system and basin analysis

• Petroleum system elements: source, reservoir, seal, overburden rock; processes: trap formation, then generation-migration-accumulation; risk = any element or process missing or mistimed. An events chart plots all of them against geological time.
• Sedimentary basin types (plate-tectonic setting): rift (Cambay, Barmer, Narmada), passive-margin/divergent (KG, Cauvery, Mumbai offshore, Kerala-Konkan), foreland (Assam-Arakan, Ganga, Himalayan foothills), intracratonic/Gondwana (Damodar, Son-Mahanadi - mainly CBM), strike-slip and fore-arc (Andaman).
• DGH basin categorisation (India, 26 sedimentary basins, about 3.36 million km² including deepwater):
  • Category I - producing with established reserves: Cambay, Mumbai Offshore, Assam-Arakan (Assam Shelf), Krishna-Godavari, Cauvery, Rajasthan (Barmer-Sanchor).
  • Category II - known accumulation, commercial production awaited: Kutch, Mahanadi-NEC, Andaman-Nicobar.
  • Category III - prospective resources on geological analogy: Himalayan foreland, Ganga, Vindhyan, Saurashtra, Kerala-Konkan-Lakshadweep, Bengal-Purnea, Narmada, Deccan Syneclise, Karewa, Spiti-Zanskar, Satpura-South Rewa-Damodar, Bhima-Kaladgi, Cuddapah, Pranhita-Godavari, Bastar, Chhattisgarh. (Counts and some assignments have been revised as new finds are made; quote the current DGH report where a figure matters.)
• Age of Indian plays: Mesozoic to Tertiary mostly - Palaeogene-Neogene in Mumbai Offshore and Assam, Eocene-Miocene in Cambay, Cretaceous-Tertiary in KG and Cauvery, Palaeocene (Late Cretaceous-Palaeocene) Fatehgarh/Barmer Hill in Rajasthan.
• Unconventional resources: CBM (Jharia, Raniganj, Sohagpur - coal seam gas adsorbed on coal, produced by dewatering), shale gas/oil (Cambay, KG, Damodar - Barren Measures), tight gas, gas hydrates (large KG and Mahanadi deepwater resource; NGHP expeditions), heavy oil and basement plays.
• Reserve classification: SPE-PRMS framework used by DGH - reserves (1P/proved, 2P/proved+probable, 3P) are discovered and commercial; contingent resources discovered but not yet commercial; prospective resources undiscovered. Deterministic P90/P50/P10 maps to 1P/2P/3P in probabilistic estimation.

Reservoir fluids, drive mechanisms and regulation

• Reservoir fluid types by phase behaviour: dry gas, wet gas, gas condensate (retrograde), volatile oil, black oil, heavy oil - placed by the position of reservoir temperature relative to the critical point and cricondentherm on the P-T phase envelope.
• Crude classification: by API gravity - light >31.1, medium 22.3-31.1, heavy <22.3; by sulphur - sweet (<0.5% S) vs sour. Mumbai High crude is light and sweet (about 39-40° API); Rajasthan Mangala crude is waxy and needs heated pipelines.
• Natural drives (ranked by typical recovery factor): water drive 35-60%, gas-cap expansion 20-40%, gravity drainage 40-80% in steeply dipping reservoirs, solution-gas (depletion) drive 5-30%, rock/fluid compaction small. Combination drives are usual.
• Overpressure (abnormal pressure) from undercompaction, hydrocarbon generation, clay diagenesis or tectonics - critical for well design; normal hydrostatic gradient is about 0.098 bar/m (≈ 0.433 psi/ft) for fresh water, ~0.1 bar/m for typical formation brine.
• Indian regulation and practice: the Oilfields (Regulation and Development) Act, 1948 (amended 2024 to cover "mineral oils" including shale, CBM and gas hydrates and to introduce petroleum leases), the Petroleum and Natural Gas Rules, 2025 (which replaced the P&NG Rules, 1959), the DGH as the technical regulator, PNGRB for midstream/downstream, and OISD standards for safety. Acreage is awarded under HELP/OALP with revenue sharing and a single licence; DSF rounds monetise small discovered fields. Reserves are reported to DGH under PRMS.
• Environment and safety: prior Environmental Clearance under the EIA Notification, 2006 (as amended) from MoEFCC for exploration and development; CRZ clearance for coastal work; the four Labour Codes (in force from 21 November 2025) govern site safety and working conditions, having replaced the Factories, Minimum Wages, Industrial Disputes and BOCW Acts.

Surface and subsurface geological methods used in exploration

(The seismic and logging techniques themselves are a separate topic; what follows is the geologist's own toolkit.)

• Surface geology: geological mapping, dip and strike measurement, structural cross-sections, surface seeps, mud volcanoes, remote sensing and satellite imagery, aerial photo interpretation.
• Geochemical surveys: soil-gas, iodine and microbial anomalies above leaking accumulations; biomarker and isotope fingerprinting to tie oil to its source rock (oil-source correlation).
• Subsurface geology from wells: lithologs from cuttings, mud logging (gas chromatograph, cuttings description), core analysis (routine - φ, k, grain density; special - relative permeability, capillary pressure, wettability), formation tests (DST), and pressure data (RFT/MDT) to locate fluid contacts.
• Correlation and mapping: well-to-well lithostratigraphic correlation, structural contour maps on a marker, isopach (true thickness) and isochore maps, net-pay maps, fence diagrams, palaeogeographic maps.
• Dating and environment: biostratigraphy (foraminifera, nannofossils, palynology), sequence stratigraphy (systems tracts, flooding surfaces), sedimentary facies analysis to predict reservoir distribution.
• Basin modelling (1D/2D/3D): burial history curves, thermal history, Lopatin's TTI and kinetic maturity models, plus volumetric and risk analysis to produce a chance of success for each prospect.

Key points

• Petroleum system - source + reservoir + seal + trap + timing; any one missing makes a dry hole.
• Source rock - organic-rich fine-grained rock; needs TOC above about 1%, oil-prone kerogen and adequate maturity.
• Kerogen types - I algal oil-prone, II marine oil and gas, III terrestrial gas-prone, IV inert.
• Oil window - roughly 60-150 °C, Ro 0.5-1.3%; cooler is immature, hotter gives gas then dry methane.
• Porosity - storage capacity (effective porosity is what produces); primary at deposition, secondary from fractures and dissolution.
• Permeability - flow capacity in darcy/mD; depends on pore throat size and connectivity, not on porosity alone.
• Sorting beats grain size - porosity is grain-size independent; permeability rises strongly with grain (pore-throat) size.
• Saturation - Sw + So + Sg = 1; irreducible water saturation is never recovered as production.
• Cap rock - must be impermeable, continuous, ductile and have high capillary entry pressure; salt is the best.
• Migration - primary = expulsion from source; secondary = buoyant flow through carrier beds; tertiary = leakage/seepage.
• Traps - structural (anticline, fault, salt), stratigraphic (reef, pinch-out, unconformity), combination, hydrodynamic.
• Closure and spill point - closure is crest-to-spill-point height; it caps the possible hydrocarbon column.
• Timing - the trap must pre-date migration, or it stays empty.
• Recovery factor - the fraction of oil in place produced; water drive is the best natural drive, solution gas the poorest.
• API gravity - 141.5/SG − 131.5; higher API means lighter, more valuable crude.
• Indian basins - DGH Categories I to III; Cambay, Mumbai Offshore, Assam-Arakan, KG, Cauvery and Rajasthan are the producers.
• Regulation - Oilfields (Regulation and Development) Act, 1948 (amended 2024), P&NG Rules, 2025, DGH as technical regulator, HELP/OALP licensing, PRMS reserve reporting.
• Unconventionals - CBM, shale gas, tight gas and KG/Mahanadi gas hydrates extend the resource base beyond conventional traps.

Formulas and examples

• Porosity and saturation from core data. A core plug has bulk volume 25.0 cm³ and grain volume 20.5 cm³; extracted fluids are 2.7 cm³ of water and 1.8 cm³ of oil.
  • Vp = 25.0 − 20.5 = 4.5 cm³ → φ = 4.5/25.0 = 0.18 = 18% (good).
  • Sw = 2.7/4.5 = 0.60 = 60%; So = 1.8/4.5 = 0.40 = 40%; Sg = 0. Hydrocarbon pore volume = 4.5 × 0.40 = 1.8 cm³.

• Oil in place and recoverable reserves (metric). A KG-type sand: area 12 km², net pay 18 m, φ = 0.22, Sw = 0.30, Boi = 1.25 rm³/stm³, RF = 0.35.
  • A × h = 12 × 10⁶ × 18 = 2.16 × 10⁸ m³ bulk rock.
  • Pore volume = 2.16 × 10⁸ × 0.22 = 4.752 × 10⁷ m³.
  • Hydrocarbon pore volume = 4.752 × 10⁷ × 0.70 = 3.3264 × 10⁷ m³ (reservoir conditions).
  • N = 3.3264 × 10⁷ / 1.25 = 2.661 × 10⁷ stock-tank m³ ≈ 26.6 million m³ ≈ 167 million barrels (1 m³ = 6.2898 bbl).
  • Recoverable = 2.661 × 10⁷ × 0.35 = 9.31 × 10⁶ stm³ ≈ 58.6 million barrels.

• OOIP in oilfield units. A = 640 acres, h = 40 ft, φ = 0.20, Sw = 0.25, Boi = 1.30 rb/STB.
  • N = 7758 × 640 × 40 × 0.20 × 0.75 / 1.30.
  • 7758 × 640 = 4,965,120; × 40 = 198,604,800; × 0.20 = 39,720,960; × 0.75 = 29,790,720; ÷ 1.30 = 22.92 million STB.
  • At RF = 0.30, recoverable ≈ 6.88 million STB.

• Darcy's law - flow through a core. Core length 6 cm, cross-section 4 cm², brine viscosity 1.0 cP, pressure drop 2.0 atm, measured flow 0.5 cm³/s.
  • k = qµL/(A ΔP) = (0.5 × 1.0 × 6)/(4 × 2.0) = 3.0/8.0 = 0.375 darcy = 375 mD - a good reservoir sand.

• Maturity by depth and API gravity. Surface temperature 30 °C, geothermal gradient 2.6 °C/100 m.
  • Top of oil window (take 60 °C): depth = (60 − 30)/0.026 = 1,154 m; base (150 °C): (150 − 30)/0.026 = 4,615 m. So the oil window spans roughly 1.15-4.6 km here; a source rock at 800 m is immature.
  • A crude of SG 0.825: API = 141.5/0.825 − 131.5 = 171.52 − 131.5 = 40.0° API - light, sweet-type crude comparable to Mumbai High.

Where it is used

• E&P operators: ONGC, Oil India, Vedanta (Cairn, Barmer), Reliance-BP (KG-D6), GSPC and OALP licensees use basin and prospect evaluation to pick well locations and to book reserves with DGH.
• Job roles: exploration/development geologist, geoscientist, petrophysicist, mud logger, well-site geologist, reservoir engineer, basin modeller, reserves auditor - entry via ONGC GT, OIL GT, GATE-based PSU recruitment and service companies (SLB, Halliburton, Baker Hughes, Weatherford).
• Field development and reservoir management: volumetric estimates, static geological models (Petrel, Kingdom), net-pay and contact mapping feed simulation, well spacing, EOR screening (Mumbai High redevelopment, Mangala polymer flood).
• Unconventional and new energy: CBM blocks in Jharia/Raniganj, shale pilots in Cambay, NGHP gas-hydrate work in KG-Mahanadi, and CO₂ storage/geothermal site screening, which reuse the same seal and porosity analysis.
• Regulators and consultancies: DGH basin studies and National Data Repository, PNGRB, state geology departments, GSI and reserve-certification consultants.
• Allied industries: groundwater and hydrogeology, coal and mineral exploration, underground gas storage, and civil-geotechnical work all apply the same porosity-permeability and stratigraphy concepts.

Interview questions

• Q: What are the essential elements of a petroleum system? A: A mature source rock, a porous and permeable reservoir, an impermeable seal, a trap with closure, and correct timing so the trap exists before migration.
• Q: Why can a perfect anticline with good reservoir and seal still be dry? A: Timing or charge failed - the structure may have formed after migration, the source may be immature, or the trap may have been breached and the oil leaked away.
• Q: Differentiate total and effective porosity, and say which matters. A: Total porosity counts all pore space; effective porosity counts only interconnected pores. Only effective porosity contributes to flow and to recoverable volumes.
• Q: Does porosity depend on grain size? A: No - for the same sorting and packing, porosity is independent of grain size; permeability however increases sharply with grain and pore-throat size.
• Q: What is the oil window and how is maturity measured? A: The temperature-depth range, roughly 60-150 °C and Ro 0.5-1.3%, in which kerogen cracks to oil; maturity is measured by vitrinite reflectance, Rock-Eval Tmax and biomarker ratios.
• Q: Which kerogen type would you want for an oil play? A: Type I (lacustrine algal) is best, Type II (marine) next; Type III is gas-prone and Type IV is inert.
• Q: Why is salt considered the best cap rock? A: It is effectively impermeable with very high capillary entry pressure and it deforms plastically, so it seals without fracturing even under tectonic strain.
• Q: Explain primary and secondary migration. A: Primary migration is expulsion of hydrocarbons out of the compacting source rock over short distances; secondary migration is buoyancy-driven movement of the free hydrocarbon phase through carrier beds up-dip to a trap.
• Q: What are spill point and closure? A: The spill point is the lowest closing contour of a trap, beyond which hydrocarbons escape; closure is the vertical distance from the crest to the spill point and limits the maximum column.
• Q: State Darcy's law and its assumptions. A: q = −(kA/µ)(dP/dL); it assumes laminar, steady, single-phase flow of an incompressible, non-reactive fluid through a homogeneous porous medium with no slippage.
• Q: Which Indian basins are DGH Category I, and what is the main pay in Mumbai Offshore? A: Cambay, Mumbai Offshore, Assam-Arakan, Krishna-Godavari, Cauvery and Rajasthan. Mumbai High produces mainly from the Miocene Bombay Formation (L-III) limestone and the underlying Eocene-Oligocene Bassein limestone, with additional fractured-basement and clastic pay.
• Q: Why is the Klinkenberg correction needed? A: Gas slips along pore walls, so gas-measured permeability is too high; extrapolating k against 1/pmean to infinite pressure gives the equivalent liquid permeability.
• Q: How do reserves differ from resources? A: Under PRMS, reserves are discovered, recoverable and commercial (1P/2P/3P); contingent resources are discovered but not yet commercial; prospective resources are undiscovered.

Common mistakes

• Treating depth as a proxy for maturity - maturity depends on the temperature and time history, so geothermal gradient and burial curve must be used.
• Confusing porosity with permeability, or assuming high porosity guarantees high permeability (shales and chalk are porous but tight).
• Forgetting Boi in volumetric calculations, or reporting reservoir-condition volumes as stock-tank oil in place.
• Using (1 − Sw) with total instead of effective porosity, or ignoring net-to-gross and the transition zone when computing net pay.
• Mixing unit systems - 7758 is for acres, feet and STB; metric volumetrics need m², m and m³ with no constant.
• Calling the trap itself a "reservoir", or treating the structure alone as a prospect without checking charge, seal and timing.
• Quoting oil-in-place as if it were reserves - reserves require a recovery factor and commerciality.

Related topics

Exploration methods: seismic and well logging · Reservoir engineering: fluid flow and material balance · Drilling engineering and well completion · Formation evaluation and petrophysics · Enhanced oil recovery methods · Sedimentology and stratigraphy.