Energy transition and CCUS

In short

The energy transition is the shift of the world's energy system from unabated fossil fuels towards low-carbon sources, with natural gas, biofuels and hydrogen as bridges, and it directly reshapes what a petroleum engineer does. CCUS (Carbon Capture, Utilisation and Storage) is the set of technologies that separate CO₂ from a flue or process gas stream, compress and transport it, and either use it (CO₂-EOR, urea, methanol, concrete) or inject it permanently into deep geological formations. For petroleum engineers it is the most transferable of all transition skills, because site selection, injection, reservoir simulation, well integrity and monitoring are classical reservoir and drilling engineering. It is examined in GATE PE (reservoir engineering, EOR, natural gas processing) and in university electives on energy management, EOR and environmental engineering; employers include ONGC, OIL, IOCL, BPCL, GAIL, Shell, Cairn (Vedanta), Tata Steel, NTPC, Dalmia Bharat, Carbon Clean and the DGH.

Explained

Why the transition, and India's commitments

• Drivers: the Paris Agreement's "well below 2 °C" goal, Nationally Determined Contributions (NDCs), investor and lender pressure, carbon pricing, and falling solar/wind/battery costs.
• India's Panchamrit (COP26, 2021) and updated NDC: net zero by 2070; 500 GW non-fossil power capacity by 2030; about 50% of installed capacity from non-fossil sources by 2030; reduce the emission intensity of GDP by 45% from 2005 levels by 2030.
• India is the third-largest energy consumer but has low per-capita emissions, so its policy is *decarbonise while growing* — hence CCUS rather than abandoning fossil assets.
• Hard-to-abate sectors — cement (process CO₂ from calcination is unavoidable), steel (coke as a reductant), refining, fertiliser, petrochemicals — cannot be electrified away; CCUS is the main option. Roughly these sectors plus power drive India's CCUS case.
• Policy instruments: National Green Hydrogen Mission (2023, ~₹19,744 crore outlay, 5 MMT/yr green hydrogen target by 2030); ethanol blending (E20 petrol now standard across the country); SATAT for compressed bio-gas; a target of about 15% natural gas in the primary energy mix by 2030 (currently roughly 6-7%); PAT and the Carbon Credit Trading Scheme (CCTS) under the Energy Conservation (Amendment) Act, 2022, administered by BEE with GHG-intensity targets for obligated entities — exact targets and compliance years are notified sector-wise and have been revised, so check the current notification.
• NITI Aayog's CCUS policy framework (2022) sketched a pathway of the order of 750 Mt CO₂ per year captured by 2050, with cost-plus incentives, viability-gap funding and CCUS hubs/clusters. These are indicative targets, not statute.
• EU CBAM (carbon border adjustment) entered its definitive, charging phase from 1 January 2026 for iron & steel, aluminium, cement, fertilisers, hydrogen and electricity — a direct commercial driver for Indian exporters to capture CO₂.

Carbon capture: routes and technologies

• Post-combustion capture: CO₂ (3-15 vol%) removed from flue gas after burning. Chemical absorption in aqueous amines (30 wt% MEA, or MDEA/piperazine blends) is the benchmark — absorber at 40-60 °C, stripper/regenerator at 100-140 °C. Retrofittable; penalty is the reboiler duty, about 3.0-4.0 GJ/t CO₂ for MEA, lower for advanced solvents.
• Pre-combustion capture: gasify or reform the fuel to syngas, shift it (CO + H₂O → CO₂ + H₂, water-gas shift), then remove CO₂ at high partial pressure with *physical* solvents (Selexol, Rectisol) and burn the hydrogen. This is how blue hydrogen / blue ammonia is made.
• Oxy-fuel combustion: burn in O₂ diluted with recycled CO₂, giving a flue gas of mostly CO₂ + H₂O; cheap separation but an expensive air-separation unit.
• Industrial/process capture: often the cheapest CO₂ in India — high-purity streams from ammonia/urea plants, ethanol fermentation, hydrogen units and natural-gas sweetening need little or no separation, only dehydration and compression.
• Other routes: pressure/vacuum/temperature swing adsorption on zeolites, activated carbon, MOFs; membranes (polymeric, facilitated transport); cryogenic separation; calcium/chemical looping; Direct Air Capture (DAC) of ambient 420 ppm CO₂ — technically proven, currently very costly and energy-intensive.
• Solvent chemistry (why amines work): CO₂ + 2R-NH₂ ⇌ R-NHCOO⁻ + R-NH₃⁺ — a reversible carbamate reaction, driven forward by low temperature and reversed by heat.
• Problems: solvent degradation (O₂, SO₂, NO₂), corrosion, amine aerosol emissions, foaming, large absorber size, water consumption. Flue gas must be desulphurised first.

Conditioning and transport

• CO₂ is dehydrated to < 50-500 ppmv water (specification varies by project) because water + CO₂ forms carbonic acid and corrodes carbon-steel pipelines; dry CO₂ is benign to carbon steel.
• CO₂'s critical point is 31.1 °C and 73.8 bar. Pipelines are run in the dense/supercritical phase, typically 85-150 bar, where density is 600-900 kg/m³ — far cheaper per tonne than gas-phase transport.
• Impurities (N₂, O₂, CH₄, H₂S, H₂) raise the bubble point and shift the phase envelope; this matters for pumps, compressors and for avoiding two-phase flow and Joule-Thomson freezing at valves.
• Compression: multi-stage intercooled compression to about 80 bar, then pumping as a dense liquid — roughly 90-120 kWh of electricity per tonne CO₂.
• Ship/road transport of liquid CO₂ at low temperature (around 15-18 bar, −30 °C for ships; 7 bar, −50 °C food-grade tankers) suits small or remote volumes.
• Standards: ISO 27913 (pipeline transportation), ISO 27914 (geological storage), ISO 27916 (quantifying storage associated with CO₂-EOR), DNV-RP-J203. In India, pipelines fall under PNGRB's technical standards and OISD codes; there is as yet no dedicated Indian Standard for CO₂ geological storage, so ISO practice plus DGH guidelines are used.

Geological storage: where, how, and how it stays put

• Options, in order of Indian relevance: depleted oil & gas reservoirs (proven seal, known geology, existing wells and data); deep saline aquifers (by far the largest capacity); basalt formations of the Deccan Traps (mineralisation into carbonates, as at CarbFix in Iceland); unmineable coal seams via ECBM.
• Depth > ~800 m is required so that pressure and temperature keep CO₂ in the dense phase (density ~600-800 kg/m³), minimising storage volume and buoyancy.
• Screening criteria: porosity > 10%, permeability > 50-100 mD, net thickness > 20-30 m, continuous low-permeability caprock (shale, evaporite) with high capillary entry pressure, no transmissive faults, no potable aquifer or mineral resource conflict, acceptable injectivity, and a defined pore-space ownership.
• Four trapping mechanisms, in increasing security and time scale:
• Structural/stratigraphic trapping — the caprock physically holds buoyant CO₂ (immediate, dominant at first).
• Residual (capillary) trapping — CO₂ snapped off as immobile droplets in pore throats behind the migrating plume (years to centuries).
• Solubility trapping — CO₂ dissolves in formation brine, making it denser so it sinks (centuries).
• Mineral trapping — carbonic acid reacts with Ca/Mg/Fe silicates to form stable carbonates (centuries to millennia; fast in basalt).
• Capacity estimation uses the volumetric efficiency-factor method (see Formulas). India's theoretical storage capacity is quoted in the hundreds of gigatonnes — published estimates range widely (roughly 100-400 Gt depending on whether basalts and offshore aquifers are counted), and only a small fraction is effective or matched to sources.
• Injection design: keep bottom-hole pressure below the formation fracture pressure (commonly a 90% limit) and below the caprock's capillary entry pressure; manage near-well salt precipitation and drying, relative-permeability hysteresis and thermal stress from cold CO₂.
• Risks: leakage along legacy/abandoned wells (the single biggest pathway — hence CO₂-resistant cements and corrosion-resistant alloys), caprock fracturing, induced seismicity from pressure build-up, brine displacement into aquifers, and surface asphyxiation (CO₂ is 1.5× denser than air and collects in low spots; occupational limit of the order of 5,000 ppm TWA).
• MMV (Measurement, Monitoring and Verification): 4D (time-lapse) seismic, downhole pressure/temperature gauges, wellhead metering, distributed temperature/acoustic sensing, micro-seismic arrays, soil-gas CO₂ flux, groundwater chemistry, tracers (SF₆, perfluorocarbons), InSAR/satellite surface deformation. Required before, during and post-closure.

CO₂-EOR and utilisation

• Mechanisms: CO₂ dissolves in oil, causing swelling and a large viscosity reduction; above the Minimum Miscibility Pressure (MMP) it becomes miscible, extracting intermediate hydrocarbons and reducing interfacial tension to near zero.
• MMP for light Indian crudes is typically 80-170 bar, so reservoir depth of roughly 900 m+ is needed; MMP rises with oil density/heaviness and reservoir temperature and falls with lighter C2-C6 content (Yellig-Metcalfe and Cronquist-type correlations).
• Injection schemes: continuous CO₂, WAG (water-alternating-gas) to control mobility, SWAG, and foam/gel for conformance. CO₂ has very low viscosity, so viscous fingering, gravity override and early breakthrough are the key problems; mobility ratio control is the design task.
• Typical performance: incremental recovery 8-20% of OOIP; gross utilisation 0.4-0.8 t CO₂/bbl with recycling of produced CO₂ reducing net purchased CO₂ to roughly 0.3-0.5 t/bbl.
• EOR vs dedicated storage: EOR gives revenue and reuses wells but requires surface separation and recycle, and its climate benefit must be netted against the emissions of the oil produced (ISO 27916 sets the accounting).
• Other utilisation: urea, methanol, salicylic acid, food/beverage CO₂, carbonated concrete curing and aggregates, polycarbonates/polyols, algae. Utilisation volumes are small compared with power/industrial emissions, and only durable products count as storage.
• Indian projects: ONGC's Gandhar CO₂-EOR scheme taking CO₂ from IOCL's Koyali refinery is India's first large CO₂-EOR/storage project; NTPC Vindhyachal's CO₂-to-methanol unit; Tata Steel Jamshedpur's blast-furnace gas capture unit; several cement-sector pilots (Dalmia, JSW, UltraTech) and refinery hydrogen-unit captures. Project stages change fast — verify current status before quoting capacities.

Law, regulation and commercial framework in India

• The Oilfields (Regulation and Development) Amendment Act (passed 2024-25) widened "mineral oil" and brought carbon capture, utilisation and storage within petroleum operations, decoupled petroleum leases from the old mining-lease regime and created an adjudication mechanism; the Petroleum and Natural Gas Rules, 2025 replaced the 1959 Rules. Details are still being operationalised — read the current gazette notification.
• Regulators: MoPNG and DGH (upstream, including storage in E&P blocks), PNGRB (pipelines, CGD), MoEFCC (EIA/consents under the Environment (Protection) Act, 1986 and the Air and Water Acts), CPCB/SPCB, BEE (CCTS), PESO (pressure vessels).
• Safety and labour: the four Labour Codes in force from 21 November 2025 replaced the Factories, Minimum Wages, Industrial Disputes and BOCW Acts — the Occupational Safety, Health and Working Conditions Code governs site safety duties; OISD standards and the Oil Mines Regulations apply to upstream CCUS facilities.
• Commercial gaps students should be able to name: no statutory CO₂ pipeline tariff/common-carrier regime yet, unsettled long-term liability transfer after site closure, pore-space ownership, and the absence of a high enough carbon price to make capture self-financing (capture costs of roughly ₹2,000-6,000 per tonne for high-purity streams and much more for dilute flue gas).

Key points

• Energy transition - system-wide shift to low-carbon energy; for India, decarbonisation alongside demand growth, net zero by 2070.
• CCUS - capture + compression + transport + utilisation or permanent geological storage of CO₂.
• Post-combustion - amine scrubbing of flue gas; retrofittable; 3-4 GJ/t CO₂ regeneration duty.
• Pre-combustion - shift syngas and strip CO₂ at pressure; produces blue hydrogen.
• Oxy-fuel - combustion in O₂/recycled CO₂; easy separation, costly air-separation unit.
• Cheapest CO₂ - high-purity process streams (ammonia, ethanol, hydrogen, gas sweetening), not dilute flue gas.
• Dense-phase transport - above 73.8 bar and 31.1 °C; dehydrate CO₂ to avoid carbonic-acid corrosion.
• 800 m minimum depth - keeps CO₂ supercritical so storage volume and buoyancy stay low.
• Four trapping mechanisms - structural, residual, solubility, mineral; security increases with time.
• Storage capacity - M = A·h·φ·ρ_CO₂·E; the efficiency factor E (1-4% in aquifers) dominates the answer.
• Fracture-pressure limit - inject below ~90% of fracture pressure and below caprock entry pressure.
• Legacy wells - the most likely leakage path; CO₂-resistant cement and corrosion-resistant alloys required.
• MMV - 4D seismic, downhole gauges, soil-gas flux, tracers, InSAR; mandatory before, during and after injection.
• CO₂-EOR - swelling, viscosity reduction and miscibility above MMP (80-170 bar); 8-20% incremental OOIP.
• Captured ≠ avoided - the energy penalty of capture means avoided CO₂ is always less than captured CO₂.
• Hard-to-abate - cement, steel, refining, fertiliser; CCUS is the main lever, not electrification.
• Policy - NITI CCUS framework (2022), CCTS under the Energy Conservation (Amendment) Act, 2022, EU CBAM charging from 1 Jan 2026.
• Oilfields (Regulation and Development) Amendment Act - CCUS now recognised within petroleum operations; DGH is the upstream regulator.

Formulas and examples

Example 1 - captured vs avoided CO₂ (the classic exam trap). A 500 MW (net) coal unit emits 900 g CO₂/kWh. A 90% amine capture plant is retrofitted; its steam and compression demand takes 125 MW, so net export falls to 375 MW.

• CO₂ generated = 500 MWh/h × 0.900 t/MWh = 450 t/h; captured = 0.90 × 450 = 405 t/h; vented = 45 t/h.
• New intensity = 45,000 kg ÷ 375 MWh = 120 g/kWh.
• CO₂ avoided = 900 − 120 = 780 g/kWh, i.e. 86.7% avoided though 90% was captured. The 3.3-point gap is the energy penalty.

Example 2 - energy penalty from first principles. Same 405 t/h of CO₂, solvent reboiler duty 3.6 GJ/t, steam-to-power equivalence 25%, compression 100 kWh/t.

• Thermal duty = 405 × 3.6 = 1,458 GJ/h = 1,458,000 MJ ÷ 3,600 s = 405 MW thermal.
• Lost electrical output ≈ 0.25 × 405 = 101 MW.
• Compression = 405 t/h × 0.100 MWh/t = 40.5 MW.
• Total ≈ 142 MW ≈ 28% of 500 MW — the same order as the 25% assumed in Example 1.

Example 3 - saline aquifer storage capacity. A = 100 km² = 1.0 × 10⁸ m², h = 50 m, φ = 0.20, ρ_CO₂ = 700 kg/m³ at depth, E = 2%.

• Pore volume = 1.0 × 10⁸ × 50 × 0.20 = 1.0 × 10⁹ m³.
• CO₂ mass if fully filled = 1.0 × 10⁹ × 700 = 7.0 × 10¹¹ kg = 700 Mt.
• Effective capacity = 700 × 0.02 = 14 Mt CO₂ — enough for a 1.4 Mt/yr capture plant for 10 years.

Example 4 - seal integrity. Caprock capillary entry pressure P_e = 15 bar; ρ_brine = 1,030 kg/m³, ρ_CO₂ = 700 kg/m³.

• Density difference = 330 kg/m³; buoyancy gradient = 330 × 9.81 = 3,237 Pa/m.
• For a 50 m CO₂ column: ΔP_b = 3,237 × 50 = 161,865 Pa ≈ 1.62 bar — far below 15 bar, so the seal holds.
• Maximum column: h_max = 15 × 10⁵ ÷ 3,237 ≈ 463 m.

Example 5 - CO₂-EOR economics. A mature field has 100 million bbl OOIP; a CO₂ flood recovers an incremental 10% OOIP at a net utilisation of 0.4 t CO₂/bbl. Oil at USD 70/bbl, exchange rate ₹88/USD, delivered CO₂ at ₹4,000/t.

• Incremental oil = 10 million bbl; net CO₂ stored = 10 × 10⁶ × 0.4 = 4.0 Mt.
• Gross revenue = 10 × 10⁶ bbl × (70 × 88) ₹/bbl = 10 × 10⁶ × 6,160 = ₹6,160 crore.
• CO₂ cost = 4.0 × 10⁶ t × ₹4,000 = ₹1,600 crore, i.e. ₹1,600/bbl of the ₹6,160/bbl revenue — leaving about ₹4,560/bbl for compression, recycle, wells, OPEX, royalty and profit petroleum.

Where it is used

• Upstream E&P: ONGC and Oil India screening depleted fields and offshore aquifers for storage; CO₂-EOR at Gandhar with refinery CO₂; reservoir simulation (CMG-GEM, Eclipse/E300, TOUGH) for plume and pressure forecasting.
• Refining and petrochemicals: IOCL, BPCL, HPCL and RIL capturing CO₂ from hydrogen/SMR units and FCC stacks; blue hydrogen and green-hydrogen blending into refinery hydrogen demand.
• Cement, steel and fertiliser: Dalmia Bharat, UltraTech, JSW, Tata Steel and urea plants — CCUS is driven by CBAM exposure and by process CO₂ that cannot be avoided.
• Power and gas: NTPC's CO₂-to-methanol and capture pilots; GAIL pipelines and CBG; the 15%-gas-in-the-mix target making LNG terminals and CGD a transition business.
• Job roles that use this directly: reservoir/storage engineer, well-integrity engineer, process engineer on capture units, HSE and carbon-accounting (Scope 1/2/3, BRSR reporting) analyst, MMV/geophysics specialist, and CCUS project-development roles with Shell, bp, Carbon Clean and consultancies.
• Finance and compliance: CCTS compliance and offset projects, BRSR Core assurance for listed companies, and CBAM reporting for exporters.

Interview questions

• Q: What is the difference between CO₂ captured and CO₂ avoided? A: Captured is what the plant removes from the stream; avoided is the reduction in emissions per unit of useful output after accounting for the extra energy the capture plant consumes, so avoided is always less.
• Q: Why is CO₂ transported in the dense/supercritical phase? A: Above 73.8 bar and 31.1 °C its density is 600-900 kg/m³ but its viscosity stays low, so a given pipeline moves far more tonnes per hour and avoids two-phase flow.
• Q: Why must CO₂ be dehydrated before pipelining? A: Free water with CO₂ forms carbonic acid that rapidly corrodes carbon steel; dry CO₂ is essentially non-corrosive.
• Q: Why is 800 m the minimum storage depth? A: Below about 800 m the pressure and temperature keep CO₂ dense (supercritical), which shrinks the storage volume needed and reduces buoyant drive on the seal.
• Q: Name the four trapping mechanisms in order of time scale. A: Structural/stratigraphic (immediate), residual capillary (years-centuries), solubility in brine (centuries), mineral carbonation (centuries-millennia).
• Q: What is MMP and why does it matter in CO₂-EOR? A: Minimum miscibility pressure — the pressure above which CO₂ and oil become fully miscible; below it the flood is only immiscible and recovery is much lower, so reservoir pressure and depth must support it.
• Q: What limits CO₂ injection rate in a well? A: Fracture pressure of the formation (usually capped at ~90%), caprock capillary entry pressure, near-well relative permeability and salt precipitation, and tubing/completion limits.
• Q: Which leakage pathway worries a storage engineer most? A: Old abandoned and legacy wells penetrating the caprock, because their cement and casings were never designed for CO₂; hence well inventories, logs and remediation before injection.
• Q: Why is CCUS considered essential for cement even if power goes fully renewable? A: About 60% of cement's CO₂ comes from calcining limestone, a chemical reaction independent of the fuel, so only capture removes it.
• Q: Why is amine capture expensive on coal flue gas but cheap on an ammonia plant? A: Flue gas is 3-15% CO₂ at atmospheric pressure and needs huge absorbers and a big reboiler duty; an ammonia plant already produces a near-pure, pressurised CO₂ stream needing only drying and compression.
• Q: Does CO₂-EOR reduce emissions? A: Net effect depends on accounting — the CO₂ retained underground is a credit, but the oil produced will itself be burnt; ISO 27916 and project boundaries decide whether it is net-negative.
• Q: How does a petroleum engineer's skill set transfer to CCUS? A: Site characterisation, PVT and phase behaviour, reservoir simulation, injection well design, cementing and integrity, pressure management and surveillance are the same disciplines applied to injecting rather than producing.

Common mistakes

• Quoting the capture rate (e.g. 90%) as the emissions reduction, ignoring the energy penalty.
• Forgetting the storage efficiency factor E in capacity calculations, which overstates capacity by one to two orders of magnitude.
• Using surface CO₂ density (~1.98 kg/m³) or liquid-water density instead of in-situ supercritical density (600-800 kg/m³) in storage mass estimates.
• Treating utilisation (urea, beverages, concrete) as permanent storage — most uses re-release the CO₂ within months.
• Mixing up pre-combustion with post-combustion capture, or claiming oxy-fuel is a separation technology rather than a combustion modification.
• Assuming any depleted reservoir is automatically a safe store, without checking legacy wells, residual pressure, and whether re-pressurisation exceeds the original seal capacity.
• Quoting policy numbers loosely — net zero is 2070 (not 2050) for India, and CCTS targets and project capacities change, so state them as current-as-of and verify.

Related topics

Enhanced oil recovery methods · Reservoir engineering and simulation · Natural gas processing and sweetening · Well integrity and cementing · Hydrogen and biofuels · Petroleum economics and project evaluation