In a coal bed methane reservoir most of the gas is stored

adsorbed on the internal surfaces of the coal matrix

as free gas in large intergranular pores

The typical early production history of a coal bed methane well is

high water rate with little gas, followed by rising gas and falling water

high gas rate that declines steadily from the start, with no water

constant gas and water rates for many years

Oil shale differs from tight (shale) oil in that oil shale

contains immature kerogen that must be heated (retorted) to yield oil

contains light oil that flows after hydraulic fracturing

Which features are characteristic of shale gas production? (More than one option may be correct.)

Long horizontal wells with multistage hydraulic fracturing

Very low (nanodarcy-range) matrix permeability

Gas stored both as free gas and as gas adsorbed on kerogen

Long horizontal wells with multistage hydraulic fracturing

Very low (nanodarcy-range) matrix permeability

Gas stored both as free gas and as gas adsorbed on kerogen

A flat production profile with almost no decline

Natural gas hydrates are stable under conditions of

low pressure and high temperature

high pressure and high temperature

In steam-assisted gravity drainage (SAGD), oil is produced by

heated oil draining by gravity along the edge of a steam chamber to a horizontal producer beneath the injector

injecting steam and producing from the same vertical well in cycles

burning part of the oil in situ with injected air

producing sand deliberately with the cold oil

Which of the following are CHEMICAL (rather than physical) trapping mechanisms for CO₂ stored in a saline aquifer? (More than one option may be correct.)

Solubility trapping by dissolution in brine

Mineral trapping by precipitation of carbonates

Solubility trapping by dissolution in brine

Mineral trapping by precipitation of carbonates

Structural trapping beneath a caprock

Residual trapping of disconnected droplets by capillary forces

Over the long term, the most permanent and slowest-acting CO₂ trapping mechanism is

hydrodynamic flow in the aquifer

Latest Trends in Petroleum Engineering: Coal Bed Methane, Shale Gas, Oil Shale, Gas Hydrates, Heavy Oil and the Trapping of CO₂ Underground

Section 11 of the GATE Petroleum Engineering (PE) paper is a single line — coal bed methane, shale gas, oil shale, gas hydrate, heavy oil, and the physical and chemical trapping of CO₂ in underground reservoirs — and this chapter is sized to it. Each resource is unconventional for a different reason: the gas is adsorbed rather than free (coal bed methane), the rock is too tight to flow without fracturing (shale gas), the organic matter has not yet become oil (oil shale), the gas is locked in an ice-like solid (hydrate), or the oil is too viscous to flow cold (heavy oil). The last item reverses the direction of the industry, putting a fluid back into the ground and keeping it there. The chapter teaches the mechanisms; it states no project figures, field names or dates.

1. Coal bed methane

In coal bed methane (CBM) the coal is both source and reservoir, and most of the gas is not in pore space at all: it is adsorbed on the enormous internal surface of the coal’s micropores, at a density far higher than free gas at the same pressure. The amount held follows the Langmuir isotherm, V = V_L p/(p_L + p), where V_L (the Langmuir volume) is the maximum adsorbed gas content and p_L (the Langmuir pressure) is the pressure at which half of it is held. Flow reaches the well through the coal’s natural fracture system, the cleats — the continuous face cleats and the shorter butt cleats at right angles to them — which are usually water-filled. So a CBM well is first dewatered: pumping water off lowers the pressure, gas desorbs from the matrix, diffuses to the cleats and flows as free gas. The production profile is the reverse of a conventional gas well’s — high water and little gas at first, then rising gas and falling water — and produced-water handling is a major cost and environmental issue.

🧠 Langmuir arithmetic

With V_L = 800 scf/ton and p_L = 400 psia, the coal holds 800 × 400/800 = 400 scf/ton at 400 psia and 800 × 200/600 = 266.7 scf/ton at 200 psia; halving the pressure releases 133.3 scf/ton. The isotherm is steepest at low pressure, which is why the last stage of depressurisation yields the most gas per psi.

2. Shale gas and oil shale

Shale gas is natural gas produced from organic-rich shale that is at once source, reservoir and seal. Its matrix permeability is in the nanodarcy range, far too low for economic flow, and the gas is stored both as free gas in small pores and natural fractures and as adsorbed gas on the kerogen. What made it producible is the combination of long horizontal wells and multistage hydraulic fracturing, which creates a large network of fracture surface in contact with the rock; good shales are rich in organic carbon, thermally mature and brittle (quartz- or carbonate-rich rather than clay-rich), so that they fracture rather than deform. Wells show very high initial rates and steep early decline, so a play is sustained by continuous drilling; water sourcing and disposal, surface footprint and induced seismicity from waste-water injection are the main concerns. Tight oil (sometimes called shale oil) is light oil produced from similar low-permeability rocks by the same technology.

Oil shale is a different thing despite the name: a fine-grained rock rich in immature kerogen that has never been buried deeply or long enough to generate oil. There is no oil to produce until the kerogen is pyrolysed — heated to several hundred degrees Celsius in the absence of air — which cracks it into shale oil and gas. This is done by retorting, either at the surface after the rock is mined and crushed, or in situ by heating the formation slowly over a long period. The energy needed for heating, the large volume of spent rock, water use and emissions are what limit it; in effect oil shale is a source rock that industry must mature artificially.

Shale gas, tight oil and oil shale distinguished
Resource	What is in the rock	How it is produced
Shale gas	Generated gas, free and adsorbed, in a mature shale	Horizontal wells with multistage hydraulic fracturing
Tight (shale) oil	Generated light oil in a low-permeability rock	The same horizontal-well and fracturing technology
Oil shale	Immature kerogen; no oil yet	Mining and surface retorting, or in-situ heating (pyrolysis)

3. Gas hydrates and heavy oil

Gas hydrates are crystalline solids in which water molecules form cages (clathrates) around small gas molecules, chiefly methane. They are stable only at high pressure and low temperature, so they occur naturally in two settings: beneath permafrost and in marine sediments below deep water, within a hydrate stability zone whose base is set by the rising geothermal temperature. Hydrate is a very compact store of gas — on dissociation a unit volume of hydrate releases of the order of a hundred and sixty volumes of methane at standard conditions. Production concepts all move the hydrate out of its stability field: depressurisation (the most energy-efficient), thermal stimulation (hot fluid injection), inhibitor injection (methanol or glycols), and CO₂-CH₄ exchange, which swaps CO₂ into the cages. Dissociation absorbs heat, and loss of the solid can weaken the sediment, so seafloor stability, sand production and wellbore integrity are central problems; hydrates are also a drilling hazard in deep water.

Heavy oil is classified by API gravity: heavy oil lies between 10 and 22.3 °API and extra-heavy oil below 10 °API (denser than water), while bitumen (natural bitumen, oil sands) is so viscous that it does not flow at reservoir conditions at all. The obstacle is viscosity, not quantity, so the methods either heat the oil, dilute it, or produce it with the sand. Cold heavy oil production with sand (CHOPS) deliberately produces sand with progressing-cavity pumps, creating high-permeability channels ("wormholes") and foamy oil flow. Thermal methods — cyclic steam stimulation, steam flooding and steam-assisted gravity drainage (SAGD), in which steam injected from an upper horizontal well forms a chamber and heated oil drains by gravity to a parallel producer beneath it — and in-situ combustion reduce viscosity by heating. Solvent methods (vapour extraction and solvent-assisted steam) dilute it. Shallow oil sands can be mined and the bitumen separated with hot water. Heavy oil also needs upgrading or diluent to be transported and refined.

4. Physical and chemical trapping of CO₂ in underground reservoirs

Geological storage of CO₂ puts captured carbon dioxide into deep saline aquifers, depleted oil and gas reservoirs (often combined with CO₂-EOR, which uses the gas while storing much of it), and unmineable coal seams (where CO₂, adsorbed more strongly than methane, can displace it). Storage is normally deep enough for CO₂ to be supercritical — above its critical point of about 31 °C and 7.4 MPa — so that it is dense, occupying far less pore volume than a gas. It is still lighter than brine, so it rises until something stops it. The mechanisms that stop it are grouped as physical and chemical, and they become more secure with time.

CO₂ trapping mechanisms
Mechanism	Type	How the CO₂ is held
Structural and stratigraphic trapping	Physical	Buoyant free-phase CO₂ held beneath a low-permeability caprock in a trap, as oil and gas are
Residual (capillary) trapping	Physical	As brine re-enters behind the migrating plume, CO₂ is left as immobile, disconnected droplets in the pores
Solubility (dissolution) trapping	Chemical	CO₂ dissolves in the formation brine; the CO₂-laden brine is denser and sinks, driving convective mixing
Mineral trapping	Chemical	Dissolved CO₂ reacts with minerals (calcium, magnesium and iron silicates) to precipitate stable carbonates — slowest and most permanent
Adsorption trapping	Physical	CO₂ adsorbed on the organic surfaces of coal

The security of storage rises with time as CO₂ moves from the structural trap, where it depends entirely on the caprock, into residual, dissolved and finally mineral forms that do not depend on it. The risks are leakage through faults, fractured caprock and, above all, old wells whose cement or casing may fail, and pressure build-up that could fracture the seal or reactivate faults. Projects therefore need site characterisation, injectivity and capacity estimates, and monitoring, measurement and verification — time-lapse seismic to image the plume, pressure and geochemical monitoring, and surface and near-surface checks. A first estimate of storage capacity is the pore volume multiplied by a storage-efficiency factor and the CO₂ density at reservoir conditions.

⚠️ Oil shale is not shale oil

Shale (tight) oil is oil that has already been generated and is produced by horizontal wells and fracturing. Oil shale holds only kerogen, which has to be heated before any oil exists. A question that offers fracturing as the way to produce oil shale, or retorting as the way to produce shale oil, is testing exactly this.

Key takeaways

CBM gas is adsorbed on coal, V = V_L p/(p_L + p); wells are dewatered to desorb it, and flow comes through cleats — water first, gas later.
Shale gas needs horizontal wells and multistage fracturing in brittle, organic-rich, mature shale, and declines steeply; oil shale is immature kerogen that must be retorted.
Hydrates are gas-in-ice cages stable at high pressure and low temperature, under permafrost and deep-water sediments; they are produced by depressurisation, heating, inhibitors or CO₂ exchange.
Heavy oil is 10-22.3 °API, extra-heavy below 10; CHOPS, steam (CSS, steamflood, SAGD), combustion, solvents and mining overcome its viscosity.
Stored CO₂ is trapped physically (structural, residual, adsorption) and chemically (solubility, mineral); security grows with time, and old wells are the main leakage risk.

Practice questions (11)

Attempt each one before opening the answer. Every explanation names the tempting wrong option as well as the right one, because that is where marks are lost.

In a coal bed methane reservoir most of the gas is stored
1. adsorbed on the internal surfaces of the coal matrix
2. as free gas in large intergranular pores
3. dissolved in oil
4. as solid hydrate
Show answer
Answer: A — adsorbed on the internal surfaces of the coal matrix
Coal has an enormous micropore surface area on which methane is adsorbed at near-liquid density; the cleats hold mostly water and little free gas. That is why production requires depressurisation by dewatering, so that gas desorbs.
A coal has Langmuir volume V_L = 800 scf/ton and Langmuir pressure p_L = 400 psia. If dewatering lowers the reservoir pressure from 400 psia to 200 psia, the gas desorbed is ______ scf/ton (to one decimal place).
Numerical answer — type the value.
Show answer
Answer: 133.3
V = V_L p/(p_L + p). At 400 psia: 800 × 400/800 = 400 scf/ton. At 200 psia: 800 × 200/600 = 266.7 scf/ton. Desorbed = 400 − 266.7 = 133.3 scf/ton. At p = p_L the coal holds exactly half of V_L, which checks the first value.
The typical early production history of a coal bed methane well is
1. high water rate with little gas, followed by rising gas and falling water
2. high gas rate that declines steadily from the start, with no water
3. oil first, then gas
4. constant gas and water rates for many years
Show answer
Answer: A — high water rate with little gas, followed by rising gas and falling water
The cleats are water-filled and the gas is adsorbed, so the well must first pump water to lower pressure below the desorption pressure; gas then rises as more of the coal desorbs, while water production falls. A conventional gas well starts at its peak and declines.
Oil shale differs from tight (shale) oil in that oil shale
1. contains immature kerogen that must be heated (retorted) to yield oil
2. contains light oil that flows after hydraulic fracturing
3. is produced by dewatering
4. is a gas hydrate deposit
Show answer
Answer: A — contains immature kerogen that must be heated (retorted) to yield oil
Oil shale has never been buried deeply enough to generate oil; its kerogen yields oil only on pyrolysis, by surface or in-situ retorting. Tight oil has already been generated and is released by horizontal wells and fracturing.
Which features are characteristic of shale gas production? (More than one option may be correct.)
1. Long horizontal wells with multistage hydraulic fracturing
2. Very low (nanodarcy-range) matrix permeability
3. Gas stored both as free gas and as gas adsorbed on kerogen
4. A flat production profile with almost no decline
Show answer
Answer: A — Long horizontal wells with multistage hydraulic fracturing; B — Very low (nanodarcy-range) matrix permeability; C — Gas stored both as free gas and as gas adsorbed on kerogen
The tight matrix makes fracturing from horizontal wells essential, and gas is held both in pores and on organic matter. Shale wells are known for high initial rates followed by steep early decline, not a flat profile.
Natural gas hydrates are stable under conditions of
1. high pressure and low temperature
2. low pressure and high temperature
3. high pressure and high temperature
4. any conditions, once formed
Show answer
Answer: A — high pressure and low temperature
Hydrate cages form and persist only where pressure is high and temperature low, which is why they occur beneath permafrost and in cold sediments under deep water, and why depressurisation or heating dissociates them.
A crude oil has a specific gravity of 0.96 at 60 °F. Its API gravity, °API = 141.5/SG − 131.5, is ______ (to one decimal place).
Numerical answer — type the value.
Show answer
Answer: 15.9
141.5/0.96 = 147.40, and 147.40 − 131.5 = 15.9 °API. That lies between 10 and 22.3 °API, so the crude is a heavy oil. As a check, SG = 1 gives exactly 10 °API.
In steam-assisted gravity drainage (SAGD), oil is produced by
1. heated oil draining by gravity along the edge of a steam chamber to a horizontal producer beneath the injector
2. injecting steam and producing from the same vertical well in cycles
3. burning part of the oil in situ with injected air
4. producing sand deliberately with the cold oil
Show answer
Answer: A — heated oil draining by gravity along the edge of a steam chamber to a horizontal producer beneath the injector
SAGD uses a pair of parallel horizontal wells: steam from the upper one forms a rising chamber, and oil heated at its boundary drains downward by gravity to the lower producer. The other options describe cyclic steam stimulation, in-situ combustion and CHOPS.
Which of the following are CHEMICAL (rather than physical) trapping mechanisms for CO₂ stored in a saline aquifer? (More than one option may be correct.)
1. Solubility trapping by dissolution in brine
2. Mineral trapping by precipitation of carbonates
3. Structural trapping beneath a caprock
4. Residual trapping of disconnected droplets by capillary forces
Show answer
Answer: A — Solubility trapping by dissolution in brine; B — Mineral trapping by precipitation of carbonates
Dissolution and reaction to carbonate minerals change the CO₂’s chemical state, so they are chemical trapping. Structural trapping (a caprock seal) and residual trapping (capillary snap-off in pores) hold CO₂ as a separate phase by physical means.
A saline aquifer target is 10 km² in area and 20 m thick with porosity 0.20. Taking a storage-efficiency factor of 0.05 and a CO₂ density of 700 kg/m³ at reservoir conditions, the CO₂ storage capacity is ______ million tonnes (to one decimal place).
Numerical answer — type the value.
Show answer
Answer: 1.4
Bulk volume = 10 × 10⁶ m² × 20 m = 2 × 10⁸ m³; pore volume = 0.20 × that = 4 × 10⁷ m³; usable = 0.05 × 4 × 10⁷ = 2 × 10⁶ m³; mass = 2 × 10⁶ × 700 = 1.4 × 10⁹ kg = 1.4 million tonnes. The efficiency factor, not the pore volume, is the most uncertain input.
Over the long term, the most permanent and slowest-acting CO₂ trapping mechanism is
1. mineral trapping
2. structural trapping
3. residual trapping
4. hydrodynamic flow in the aquifer
Show answer
Answer: A — mineral trapping
Reaction of dissolved CO₂ with silicate minerals to form carbonates can take very long periods, but the carbon is then locked in solid rock and cannot leak. Structural trapping acts at once but depends entirely on the seal; residual and solubility trapping come in between.