Geoscience & Geophysics

How to read this #

Geoscience is the foundation the rest of petroleum engineering stands on. You cannot plan a well without knowing what rock it will pass through, you cannot evaluate a log without knowing what the formation is, and you cannot complete a lateral without knowing the target layer is there and continuous. So we start here.

The module runs in four movements. First, where the oil is and why — the petroleum system, the chemistry that makes hydrocarbons, and the rocks that hold them. Second, structure and pressure — the traps that catch oil and the pressures that make drilling dangerous. Third, geophysics — how seismic lets us see two miles down without drilling. Finally, putting it together — turning a basin into a drillable prospect, and the specific geology that decides whether you can land a horizontal well.

The petroleum system #

A petroleum system is the complete natural plumbing that puts producible hydrocarbons in one place. For oil or gas to exist where you can drill it, five things must all be present, and a sixth — timing — must line them up correctly. Miss any one and there is no accumulation. This is the single most important framework in exploration; everything else is detail hanging off it.

The five elements and one process

• Source rock — an organic-rich rock (typically shale) that, when buried and heated, generates hydrocarbons. No source, no oil.
• Migration — the pathway, usually buoyant upward movement through permeable rock and along faults, that carries hydrocarbons from source to trap.
• Reservoir rock — a porous, permeable rock (sandstone or carbonate) that can store and transmit fluids.
• Seal (cap rock) — an impermeable rock (shale, salt, anhydrite) above the reservoir that stops the buoyant hydrocarbons from escaping.
• Trap — a geometry that holds the hydrocarbons in place: the reservoir-plus-seal arranged so oil collects rather than leaks away.
• Timing (the process) — the trap and seal must exist before the source rock finishes generating and migrating. Generate before you have a trap and the oil simply escapes to surface.

Why timing is the silent killer

Exploration failures are usually not "no source rock" — that is easy to check. They are timing failures and seal failures. A perfect trap that formed ten million years after the source finished generating catches nothing. A perfect reservoir under a seal with one open fault leaks dry over geologic time. When you read that a prospect is "high risk," the risk is almost always concentrated in one or two of these elements — and a good prospect summary tells you which.

Kerogen & maturation #

Oil is cooked, not born. It starts as the organic remains of microscopic life — mostly algae and plankton — that settled into oxygen-starved mud where it could not rot. Buried under more sediment, that organic matter compresses into kerogen, the solid, insoluble precursor of all petroleum. Heat the kerogen enough, for long enough, and it breaks down into oil and gas. This is maturation, and it is governed almost entirely by temperature and time.

The four kerogen types

What a source rock produces depends on the kind of organic matter it started with. The classification, from the Van Krevelen diagram (hydrogen-to-carbon vs oxygen-to-carbon ratios):

The windows: oil, then wet gas, then dry gas

As burial deepens and temperature rises, the same source rock passes through distinct stages. The temperatures are approximate; the principle is exact — deeper and hotter means lighter hydrocarbons.

Vitrinite reflectance (Ro) is the workhorse maturity measurement: you polish a sample, shine light on the vitrinite (woody) particles, and measure how reflective they are. More cooking means more reflective. Ro of 0.6% marks the top of the oil window; 1.3% marks the transition to dry gas. It is the first number a geochemist looks at.

Source-rock geochemistry #

How do you know a rock is a good source — how much organic matter it holds, what type, and whether it has generated yet? Two cheap, fast lab measurements answer almost everything: total organic carbon (TOC) and Rock-Eval pyrolysis. Together they cost a few hundred dollars per sample and are run on cuttings from nearly every well.

TOC — is there enough fuel?

TOC is the weight percent of organic carbon in the rock. The rough scale: below 0.5% is a non-source, 0.5–1% is poor, 1–2% is good, 2–5% is very good, and above 5% is excellent. The Bakken and Eagle Ford run several percent; the Kimmeridge Clay that sourced the North Sea hits double digits. Note TOC measures what is there now — a spent source that already gave up its oil reads lower than it started.

Rock-Eval — how good and how cooked?

Rock-Eval heats a crushed sample in steps and measures what comes off. It produces a pyrogram with three peaks and a temperature:

• S1 — free hydrocarbons already present (oil the rock has generated but not expelled), released by gentle heating (~300 °C).
• S2 — hydrocarbons cracked from kerogen at higher heat (300–600 °C). This is the remaining generative potential.
• S3 — CO₂ released, a proxy for oxygen content.
• Tmax — the temperature of peak S2 release; a maturity indicator (≈435 °C is the top of the oil window).

From these you derive the diagnostic ratios. The hydrogen index (HI = 100·S2/TOC) separates oil-prone Type I/II (HI > 300) from gas-prone Type III (HI < 200). The production index (PI = S1/(S1+S2)) rises as the rock matures and starts generating. A geochemist reads TOC, HI, Tmax, and Ro together — never one alone — to say "good Type II source, early oil window, lightly charged." That one sentence can be worth a basin.

Sedimentology & depositional environments #

Reservoir quality is inherited from the day the sediment was laid down. A river channel, a beach, a deep-sea fan, and a reef all make rock — but rock with wildly different porosity, permeability, and geometry. Sedimentology is reading those origins from the rock, and it is how a geologist predicts where the good reservoir is before drilling it.

Clastics vs carbonates

Two great families of reservoir rock. Clastics (sandstones, from broken-up older rock transported by water and wind) dominate most of the world's production. Carbonates (limestones and dolomites, built in place by marine organisms and chemistry) hold the giant Middle East fields. They behave differently: clastic quality is mostly about grain sorting and burial; carbonate quality is dominated by post-depositional chemistry — dissolution that creates vugs, dolomitization that creates porosity, cementation that destroys it.

The energy gradient

The single most useful idea: grain size tracks the energy of the environment. High-energy settings (rivers, beaches, shallow shelves with waves) winnow out the mud and leave clean, well-sorted sand — excellent reservoir. Low-energy settings (lagoons, deep basins) drop fine mud — future seal and source. Read the grain size and you have read the environment, and the reservoir potential with it.

A related discipline, sequence stratigraphy, tracks how rising and falling sea level shifts these environments back and forth over time, stacking reservoir and seal in predictable patterns. It is how a geologist correlates the same productive sand from well to well across a field — and how they predict where it pinches out.

Reservoir rock: porosity & permeability #

Two properties decide whether a rock is a reservoir. Porosity is how much it can hold; permeability is how easily fluid moves through it. A rock can have one without the other — chalk is porous but barely permeable; a fracture is permeable but holds nothing. You need both.

Porosity (φ)

Porosity is the fraction of rock volume that is pore space: φ = V_pore / V_total. Sandstone reservoirs run 10–30%; tight shales are 4–10%. The distinction that matters for production is total vs effective porosity — effective porosity counts only connected pores that can actually flow, excluding isolated voids and clay-bound water. Logs in Module 3 measure porosity; this is where you learn what the number means.

Permeability (k)

Permeability, measured in darcies (usually millidarcies, md), quantifies flow capacity and appears directly in Darcy's law. The range across reservoirs is staggering — fourteen orders of magnitude:

Two more properties round out the rock description. Capillary pressure governs how oil and water distribute in the pores and sets the height of the transition zone above the water contact. Wettability — whether the rock surface prefers water or oil — controls how much oil you can ever recover. Both return with force in Module 4.

Traps #

A trap is the geometry that stops migrating hydrocarbons from reaching the surface and pools them where you can drill. Traps fall into three families, and recognizing which one you are chasing changes everything about how you explore for it and how risky it is.

Structural traps

Formed by deformation of the rock after deposition — folding and faulting. The classic is the anticline: an upfold where buoyant oil collects at the crest under a sealing layer. Most of the world's early giant fields were anticlines because they are big, simple, and easy to see on seismic. Fault traps rely on a fault juxtaposing reservoir against an impermeable rock, sealing the side.

Stratigraphic traps

Formed by changes in the rock itself rather than deformation — a sand that pinches out laterally into shale, a reef encased in mud, or an erosional unconformity truncating a reservoir under younger seal. These are harder to find (they don't show as obvious structure) and are where modern exploration increasingly lives.

Combination & salt

Many real traps mix mechanisms. Salt tectonics deserves special mention: salt is buoyant and mobile, and as it rises it pierces and folds the overlying rock, creating a whole family of traps around salt domes. This is the dominant trapping style in the deepwater Gulf of Mexico (Module 6).

Sedimentary basins #

Everything so far happens inside a sedimentary basin — a region of the crust that subsided over geologic time and filled with sediment kilometers thick. Basins are where source rocks get buried deep enough to cook and where reservoirs accumulate. The kind of basin tells you what to expect: its heat flow, its source rocks, its reservoir types, and its structural style.

How basins form

Two mechanisms make the crust subside. Stretching thins the crust (it floats lower, like a thinned raft) — this makes rift basins. Loading presses the crust down under the weight of mountains or thick sediment — this makes foreland and passive-margin basins. Heat flow follows: stretched crust is hot (good for maturing source rock quickly), loaded crust is cooler.

The payoff is predictive. Tell an explorer "rift basin" and they immediately think: lacustrine or marine source in the deep graben, fault-block traps, good heat flow. Tell them "passive margin" and they think: deltaic and turbidite reservoirs, possible salt, stratigraphic traps. The basin type is the first-order filter on every other decision.

Pore pressure & geomechanics #

This is the chapter that keeps people alive. The fluids in the pores of a deep rock are under pressure, and if you drill into a formation whose pressure you misjudged, the well either collapses on you or blows out. Understanding subsurface pressure is the bridge between geology and drilling — and it defines the narrow corridor a drilling engineer has to thread.

The three pressures

• Overburden (lithostatic) pressure — the weight of all the rock above, roughly 1 psi per foot of depth. It is the total load the formation carries.
• Pore (formation) pressure — the pressure of the fluid in the pores. Normal pore pressure is just the weight of a column of formation water, about 0.433–0.465 psi/ft. The rock matrix carries the rest.
• Fracture pressure — the pressure at which the formation cracks and your drilling fluid escapes into the rock. It sits between pore and overburden pressure.

Abnormal pressure and the mud window

When formation fluid cannot escape as fast as the rock is buried — sealed by overlying shale — it starts carrying part of the overburden load, and pore pressure climbs above normal. This is overpressure, and it is common in young, rapidly buried basins (GoM, Niger Delta) and in the heart of generating source rocks. Underpressure (depleted reservoirs) also exists. Predicting pore pressure before drilling — from seismic velocities and offset wells — is a whole sub-discipline, because the drilling mud weight has to be set against it.

The drilling fluid in the hole exerts hydrostatic pressure that must stay above pore pressure (or the formation flows into the well — a kick) and below fracture pressure (or you lose mud into the formation). That corridor is the mud window, and it narrows with depth. When it pinches shut, you must set casing and change mud weight — which is why casing programs look the way they do.

The stress state

Rock at depth is squeezed by three principal stresses: one vertical (the overburden) and two horizontal. Their relative sizes — Anderson's classification — set the faulting style and, crucially for completions, the direction a hydraulic fracture will open. A frac always opens against the least principal stress, so it grows perpendicular to it. Knowing the stress azimuth is how you decide which way to point a lateral so its transverse fractures are widest.

Seismic acquisition #

Seismic reflection surveying is how we see kilometers into the earth without drilling. The idea is simple: make a sound, time how long its echo takes to return from each rock layer, and from those times reconstruct the layering. Doing it well — across hundreds of square kilometers, resolving features tens of meters thick — is one of the great feats of applied physics.

The physics: acoustic impedance and reflection

A sound wave traveling through rock partly reflects wherever it crosses a boundary between rocks of different acoustic impedance (Z = density × velocity). The size of the reflection — the reflection coefficient — depends on the impedance contrast:

No contrast, no reflection. A big contrast — say, gas-charged sand under shale — makes a strong reflection, sometimes a "bright spot." This single equation is the foundation of both interpretation and the AVO analysis in Chapter 12.

Sources and receivers

On land the source is usually a vibroseis truck (a vibrating plate that sweeps frequencies) or, historically, dynamite; receivers are geophones that sense ground velocity. At sea a ship tows air-gun arrays (a sharp bubble pulse) and long streamers of hydrophones that sense pressure. Modern surveys are 3D: a dense grid of sources and receivers builds a data cube you can slice in any direction.

The key acquisition concept is common midpoint (CMP): many different source-receiver pairs whose rays bounce off the same subsurface point. Recording that point many times, at many offsets, is what gives seismic its signal-to-noise — and, in Chapter 12, its ability to detect fluids from how amplitude changes with offset.

Seismic processing #

Raw seismic is unreadable — a mess of noise, multiples, and energy arriving at the wrong place. Processing turns it into an image. You do not need to run the algorithms, but you must know what each step assumes, because every processing choice can create or destroy an apparent reservoir.

The processing chain

1. Deconvolution — sharpens the wavelet, compressing the source signature so closely spaced reflectors separate.
2. Statics — corrects for the irregular surface and weathered near-surface layer (land especially).
3. Velocity analysis — finds the velocity of each layer, the single most important and most uncertain quantity in the whole chain.
4. Normal moveout (NMO) & stack — flattens reflections recorded at different offsets to a common time, then sums all the CMP traces into one high-quality trace. This is where the signal-to-noise gain happens.
5. Migration — moves dipping reflectors and diffractions to their true subsurface positions and collapses them to a focused image. Pre-stack depth migration is the modern gold standard.

One concept to keep straight: seismic is recorded in two-way time, not depth. Converting time to depth requires the velocity model, and errors there move a reservoir hundreds of feet vertically. A "depth-converted" map is only as good as its velocities — which is why interpreters tie seismic to well control wherever they can.

Seismic interpretation #

Interpretation is where the processed image becomes geology. The interpreter picks reflectors, maps faults, ties the seismic to wells, and turns a time image into a depth structure map that says "drill here, the crest is at 9,200 feet." It is equal parts pattern recognition and discipline.

The core tasks

• Horizon picking — tracking a single reflector (a specific rock boundary) across the whole survey to map its shape.
• Fault interpretation — finding the breaks and offsets where reflectors are displaced; faults both trap and leak, so getting them right is everything.
• The well tie — building a synthetic seismogram from a well's sonic and density logs and matching it to the seismic, so you know which reflector is which rock. Without a tie you are guessing.
• Depth conversion — applying the velocity model to turn the time map into a depth map for the drillers.

Resolution sets the limits of what you can interpret. Seismic typically resolves beds down to about a quarter of the dominant wavelength — tens of meters at reservoir depths. Below that, beds blur together (the "tuning" effect). This is exactly why a 30-foot shale target that is unmistakable in a horizontal well's logs can be nearly invisible on the seismic used to plan it — and why geosteering (Chapter 14) exists.

Seismic attributes, DHIs & AVO #

Structure tells you where oil could be trapped. Amplitude can tell you whether it is. Direct hydrocarbon indicators (DHIs) and amplitude-versus-offset (AVO) analysis squeeze fluid information out of the seismic itself — the closest thing geophysics has to seeing the oil before drilling. It is also where overconfidence has drilled many dry holes, so it is taught with caution.

Direct hydrocarbon indicators

• Bright spot — an anomalously strong reflection where gas lowers the sand's impedance, sharpening the contrast with the shale above. The classic DHI.
• Flat spot — a horizontal reflection cutting across dipping beds: a fluid contact (gas-oil or oil-water), which is flat regardless of structure. One of the most reliable DHIs.
• Dim out, phase reversal — other amplitude effects of fluids depending on the rock contrast.

AVO: amplitude as a function of angle

The reflection coefficient from Chapter 9 was the simple, straight-down case. In reality the reflection strength changes with the angle (offset) of the ray, and how it changes depends on the rock and fluid. Plotting reflection amplitude against offset and fitting intercept (A) and gradient (B) reveals diagnostic behavior. The standard Rutherford-Williams classes:

A Class III AVO anomaly — a strong negative amplitude that gets stronger with offset, plotting in the lower-left of the A-B crossplot — is the classic gas-sand signature that made AVO famous in the Gulf of Mexico. But shales and brine sands can mimic it, so a disciplined interpreter treats AVO as evidence, not proof. Finally, 4D (time-lapse) seismic repeats a survey years apart to watch fluids move as a reservoir produces — a reservoir-management tool covered in Module 4.

From play to prospect #

All the geoscience converges on one deliverable: a prospect ready to drill, with a volume estimate and a probability of success. This is where the geologist has to commit to a number the company will spend money against.

The exploration hierarchy

• Basin → play (a family of prospects sharing the same petroleum-system elements) → lead (an immature idea) → prospect (a mapped, risked, drillable target).
• A play fairway map shows where all the elements are simultaneously present — the area worth exploring.

Volumetrics

The standard estimate of oil initially in place (STOIIP), in stock-tank barrels:

where 7758 converts acre-feet to barrels, A·h is the rock volume, φ the porosity, (1−Sw) the hydrocarbon fraction, and Bo the formation volume factor (how much the oil shrinks coming to surface). Recoverable reserves are STOIIP times a recovery factor — typically 5–15% for shale, 20–40% for good conventional, higher with EOR (Module 4).

Because each input is uncertain, modern prospect evaluation is probabilistic: run the volumetric equation thousands of times with distributions on each variable (a Monte Carlo simulation) to get a range — P90 (conservative), P50 (median), P10 (optimistic). The economics of drilling that risked, ranged prospect — expected value, the cost of a dry hole — is the domain of the Upstream Field Manual and the capstone in Module 6.

The geoscience of laterals #

This is where Module 1 pays off for the shale era. A horizontal well lives or dies on geology that a vertical well barely cares about. The whole game is to drill a two-mile lateral and keep it inside a target layer that may be only twenty or thirty feet thick — and that layer is rarely flat.

Picking the landing zone

The landing zone is the sweet spot within the target formation where you want the lateral to run: the interval with the best combination of organic richness, porosity, hydrocarbon saturation, and — critically — rock that fractures well (brittleness). In the Wolfcamp or the Bakken middle member this is a specific few-foot window picked from logs and core. Land too high or too low and you are in rock that won't produce or won't frac. Module 3 is how you identify it; this chapter is why it matters.

Structural dip and continuity

Two geological facts decide whether a lateral is even possible. First, continuity: the target must persist laterally for thousands of feet without pinching out or being cut by a fault. Second, dip: the target tilts, and the well must tilt with it to stay in zone. A fault across the lateral can drop the target out of reach entirely. This is why exploration-quality seismic and offset-well correlation precede every horizontal program.

Equations & glossary #

The equations of this module

Glossary