Enhanced oil recovery

In short

Enhanced oil recovery (EOR) is the injection of fluids or energy that are not naturally present in the reservoir - polymers, surfactants, alkali, miscible gases, steam, air, microbes - to mobilise the oil that primary depletion and waterflooding leave behind. It matters because primary plus secondary recovery typically yields only 25-40% of the oil in place, so a few percentage points of extra recovery from mature Indian fields is cheaper and faster than a new discovery. Technically it works by attacking two independent inefficiencies: poor microscopic displacement (capillary trapping of residual oil) and poor macroscopic sweep (viscous fingering, channelling, gravity override). It is a high-weight GATE (Petroleum Engineering) topic under reservoir engineering and the standard interview area for reservoir and production engineering roles at ONGC, Oil India, Cairn (Vedanta), Reliance-BP, Shell, Halliburton, SLB and Baker Hughes, and for DGH/MoPNG reservoir-management positions.

Explained

Recovery stages, targets and terminology

• Primary recovery: production on natural reservoir energy - solution gas drive, gas-cap expansion, aquifer influx, rock and fluid compaction, gravity drainage. Typical recovery 5-25% of OOIP (solution gas drive can be as low as 5-10%).
• Secondary recovery: pressure maintenance and displacement by injecting water or immiscible gas (fluids already native to the system). Takes cumulative recovery to roughly 25-45%.
• Tertiary / EOR: injection of non-native fluids or thermal energy to recover part of the remaining 55-75%. Incremental recovery of 5-20% of OOIP is the realistic target.
• IOR (improved oil recovery) is the wider term: it includes EOR plus infill drilling, horizontal and multilateral wells, intelligent completions, water-shutoff and conformance jobs, artificial-lift optimisation and better reservoir management. In Indian policy documents (DGH, MoPNG) "IOR/EOR" is used as one bracket.
• The stages need not be sequential - heavy-oil fields may start with thermal EOR from day one (EOR as primary).
• Target oil: residual oil saturation to water (Sorw, typically 0.20-0.40 in the swept zone) plus bypassed oil in unswept layers and pattern corners. These two require different cures - never confuse them.

Why oil is left behind: the two efficiencies

• Displacement (microscopic) efficiency E_D: fraction of oil mobilised where the injected fluid actually contacts the rock. Limited by capillary trapping - oil is held as discontinuous ganglia by interfacial tension (IFT) in pore throats.
• Areal sweep E_A: fraction of pattern area contacted, controlled by well pattern (line drive, 4-, 5-, 7-, 9-spot), mobility ratio and heterogeneity/fractures.
• Vertical sweep E_V: fraction of pay thickness contacted, controlled by permeability layering (Dykstra-Parsons coefficient), cross-flow and gravity segregation.
• Mobility ratio M = λ_displacing/λ_displaced. M ≤ 1 is favourable (piston-like front); M > 1 causes viscous fingering and early breakthrough. Heavy oil waterfloods often have M of 10-100.
• Capillary number N_c = vμ/σ - ratio of viscous to capillary forces. The capillary desaturation curve shows Sor stays flat until N_c exceeds roughly 10⁻⁵, then falls sharply. Since v and μ cannot be raised more than an order or two, σ must be cut by 3-4 orders of magnitude (from ~30 mN/m to ~10⁻³ mN/m) - the whole logic of surfactant flooding.
• Wettability controls where residual oil sits: water-wet rock traps oil as blobs in pore bodies; oil-wet rock holds oil as films on grains. Mixed/oil-wet carbonates give lower waterflood E_D and respond to wettability alteration.
• Bond number / gravity number describes gravity-versus-capillary effects, relevant to gravity-stable gas injection.

Classification of EOR methods

1. Chemical: polymer, surfactant, alkaline, alkali-surfactant-polymer (ASP), surfactant-polymer (SP), foam, gels (conformance), nanofluids.
2. Miscible / gas: CO₂, hydrocarbon (LPG slug, enriched gas, high-pressure lean gas), N₂, flue gas; continuous or WAG (water-alternating-gas).
3. Thermal: steam flooding, cyclic steam stimulation (CSS, "huff and puff"), steam-assisted gravity drainage (SAGD), hot water, in-situ combustion (ISC), electromagnetic/electrical heating.
4. Microbial (MEOR): injected or stimulated indigenous bacteria producing biosurfactants, biopolymers, gases and acids.
5. Other / emerging: low-salinity or "smart" water, engineered-salinity waterflooding, nanoparticle-stabilised foams, CO₂ foam, solvent-assisted SAGD (ES-SAGD).

Chemical EOR in detail

• Polymer flooding - raises the viscosity of injection water to lower M; it improves sweep, not E_D. It does not reduce Sor, it recovers the mobile oil sooner and more completely (and accelerates NPV).
  • Polymers: HPAM (partially hydrolysed polyacrylamide, degree of hydrolysis ~25-30%) is the workhorse - cheap, high viscosifying power, but sensitive to salinity/hardness (divalent Ca²⁺, Mg²⁺), shear degradation at the perforations and hydrolysis above ~70-90 °C. Xanthan (biopolymer) tolerates salinity and shear but is costly and prone to plugging and biodegradation. Newer: ATBS/sulfonated copolymers for high-temperature, high-salinity brine.
  • Key laboratory parameters: viscosity vs concentration and shear rate (pseudoplastic), resistance factor R_f (mobility reduction during flow) and residual resistance factor R_k (permanent permeability reduction after flow), inaccessible pore volume, adsorption/retention (µg/g rock), and in-situ shear thickening of HPAM at high rates.
  • Typical design: 500-2,000 ppm, target viscosity set so that M ≤ 1 (μ_p ≥ μ_o × k_rw/k_ro, in practice a fraction of to roughly the oil viscosity), slug 0.3-1.0 pore volume, followed by a taper and chase water.
• Surfactant flooding - reduces oil/water IFT to ultra-low values, raising N_c and lowering Sor towards near zero in the swept zone. Surfactants: sulfonates (petroleum/alpha-olefin sulfonates), ethoxylated sulfates, internal-olefin sulfonates; co-solvents (alcohols) added for phase behaviour.
  • Winsor phase behaviour: Type I (oil-in-water micelles, under-optimum salinity), Type II (water-in-oil, over-optimum), Type III middle-phase microemulsion at optimum salinity - where IFT is minimum and recovery maximum. Salinity scans in pipettes are the standard screening test.
  • Losses: adsorption on rock, partitioning into oil, chromatographic separation of the slug components, divalent-ion-induced precipitation.
• Alkaline flooding - NaOH, Na₂CO₃ or NaHCO₃ react in situ with naphthenic acids in the crude (saponification) to generate soap surfactant, lower IFT, alter wettability and, importantly, reduce surfactant and polymer adsorption by raising pH and sequestering divalent ions. Needs a crude with acid number typically > 0.2 mg KOH/g. Risk: scaling, silica dissolution, emulsion handling.
• ASP flooding - alkali (lowers chemical cost and adsorption) + surfactant (lowers IFT → E_D) + polymer (mobility control → E_A, E_V). The most powerful chemical method; also the most operationally demanding (produced emulsions, scaling, water treatment, polymer back-production).
• Conformance control (not strictly EOR but examined with it): polymer gels, crosslinked PAM-chromium acetate, colloidal dispersion gels, preformed particle gels and foams to plug high-permeability streaks, fractures and thief zones.

Gas and miscible EOR

• Miscibility: two fluids are miscible if they mix in all proportions with zero interfacial tension - then no capillary trapping, so E_D can approach 90-100% in the contacted zone.
  • First-contact miscible (FCM): LPG/propane slug, miscible immediately.
  • Multi-contact miscible (MCM): vaporising gas drive (lean gas/CO₂/N₂ strips intermediates C₂-C₆ from the oil, enriching the gas) and condensing gas drive (enriched gas donates intermediates to the oil). CO₂ works mainly by extraction/vaporisation plus oil swelling and viscosity reduction.
• Minimum miscibility pressure (MMP): the lowest pressure at which the injected gas becomes multi-contact miscible with the oil at reservoir temperature. Measured by slim-tube test (criterion: ~90-95% recovery at 1.2 PV injected), rising-bubble apparatus, or vanishing interfacial tension; estimated by correlations (Yellig-Metcalfe, Cronquist, Glaso, Alston) and EOS/slim-tube simulation.
  • MMP increases with reservoir temperature, with heavier oil (lower C₂-C₆ content, higher C₇₊ molecular weight) and with methane/N₂ content in the injected gas. CO₂ MMP is commonly 8-20 MPa; N₂ and flue gas need much higher pressures, so they suit deep, light-oil reservoirs. If MMP > fracture pressure, the flood must run immiscible (swelling, viscosity reduction and partial IFT reduction only).
• Immiscible benefits of CO₂: oil swelling (10-40%), viscosity reduction, IFT lowering, solution-gas drive on blowdown.
• Problems: gas is far less viscous and less dense than oil → severe viscous fingering, gravity override and channelling; hence WAG (typically 1:1 slug ratio, 0.1-0.3 PV cycles), foam-assisted WAG, horizontal/gravity-stable injection and down-dip placement. Also corrosion (wet CO₂ → carbonic acid, needs CRA/internally coated tubulars), asphaltene precipitation, hydrate and scale issues, and CO₂ recycling plants.
• CO₂-EOR with storage (CCUS): every barrel produced stores CO₂ permanently; net utilisation ~0.2-0.4 t CO₂/bbl. This is the main pathway linking EOR to India's net-zero-2070 commitment and the NITI Aayog CCUS roadmap (2022).

Thermal EOR

• Works on heavy and viscous oil (µ from hundreds to millions of cP) by cutting viscosity drastically - a 10 °C rise can halve heavy-oil viscosity; viscosity falls roughly exponentially with temperature.
• Cyclic steam stimulation (CSS): inject steam into one well for days-weeks, soak, then produce the same well; repeat for several cycles. Quick payback, single-well, but limited to a near-well radius; recovery 10-20% of OOIP.
• Steam flooding (steam drive): continuous injection in a pattern - steam zone, condensate hot-water bank, oil bank, then cold oil. Mechanisms: viscosity reduction, thermal expansion, steam distillation of light ends, gravity drainage, solution-gas drive. Recovery can reach 50-65% OOIP. Needs depth typically < 1,200-1,500 m (heat loss and wellbore pressure limits), pay > 6-10 m, low water saturation, no large gas cap or active aquifer.
• SAGD: a pair of parallel horizontal wells, injector ~5 m above producer; a steam chamber grows upwards and sideways and heated oil drains by gravity to the lower producer. Needs thick, high-permeability, continuous pay with no shale baffles. Dominant in Canadian bitumen; little applied in India so far.
• Steam quality, oil-steam ratio (OSR) and steam-oil ratio (SOR) are the economic metrics; SOR of 2-5 is viable, above ~6-8 usually not. Surface losses: generator efficiency, line heat loss, wellbore heat loss (Ramey), formation overburden/underburden losses (Marx-Langenheim heated-area model).
• In-situ combustion (ISC) / fire flooding: air or enriched air is injected and a fraction of the crude (fuel, the coke left by low-temperature oxidation) is burnt in situ at 350-700 °C; the combustion front drives a steam/water bank, a solvent bank and an oil bank ahead of it. Dry forward, wet combustion (water co-injected to recover heat behind the front, improving efficiency) and reverse combustion (rarely successful). THAI combines ISC with a horizontal producer.
  • Advantages: no surface fuel, no large heat loss to overburden, works deeper than steam. Risks: front control, gas channelling, corrosion from acidic/sour gases, well-bore burning, emulsion and sand issues, safety of air-compression systems.
• Thermal EOR is energy- and water-intensive; its CO₂ and water footprint is a live regulatory and ESG question.

MEOR, low-salinity water and screening

• MEOR: nutrient (usually molasses) injection to stimulate indigenous or injected bacteria that generate biosurfactants (IFT reduction), biopolymers (mobility control), CO₂/CH₄ (pressure, swelling), acids and solvents, plus selective plugging of high-permeability zones. Cheap, low capex, but hard to control and to attribute response; limited by temperature (< ~80-90 °C), salinity and pH. ONGC and TERI have run MEOR paraffin-control and huff-and-puff pilots in Gujarat and Assam fields.
• Low-salinity / smart waterflooding: injecting diluted water (typically < 5,000 ppm, with controlled SO₄²⁻/Ca²⁺/Mg²⁺ in carbonates) shifts wettability towards water-wet via multi-component ion exchange and double-layer expansion, giving 2-8% extra OOIP. Very low cost if a suitable water source exists; but needs a desalination/dilution plant and clay-swelling control.
• Screening criteria (indicative; always confirmed by core floods and simulation):

Indian practice, policy and codes

• Cairn Oil & Gas (Vedanta), Mangala field, Barmer, Rajasthan: full-field polymer flood since 2014, widely described as one of the world's largest; an ASP pilot followed (from around 2019) and ASP expansion is in the field development plan. The Barmer fields (Mangala-Bhagyam-Aishwariya) are the Indian textbook case for chemical EOR.
• ONGC, Gujarat (Mehsana/Ahmedabad asset): in-situ combustion at Balol and Santhal heavy-oil fields - among the few sustained commercial ISC projects worldwide; cyclic steam and hot-water pilots at Lanwa and nearby heavy-oil pools; polymer and ASP pilots in Cambay basin fields (e.g. Sanand, Jhalora, Bechraji) and at Ankleshwar/Gandhar.
• CO₂-EOR: ONGC has advanced CO₂-EOR projects taking captured CO₂ from refinery/fertiliser sources in Gujarat (notably for Gandhar) with a CCUS tie-up, and Oil India has studied CO₂-EOR in Assam. Scope and schedules keep changing - check DGH/company announcements for current status.
• Mumbai High and offshore: heavy water injection and advanced IOR (horizontal/multilateral wells, redevelopment phases) rather than chemical EOR; miscible gas and WAG have been studied.
• Policy and regulation:
  • MoPNG / DGH: the Directorate General of Hydrocarbons reviews and approves reservoir-management plans, Field Development Plans (FDP) and EOR/IOR proposals through the Management Committee under PSC/RSC/HELP contracts; it also maintains the National Data Repository.
  • EOR/IOR policy framework (approved 2018): encourages mandatory EOR/IOR screening of all fields and gives fiscal relief - royalty concession for approved EOR/IOR and unconventional projects for a defined period. Exact rates and eligibility are notified administratively; verify the current notification before quoting numbers.
  • HELP (2016) with revenue sharing and OALP rounds, and the Discovered Small Field policy, govern the contractual setting; marketing and pricing freedom improves EOR economics.
  • Oilfields (Regulation and Development) Act, 1948, as amended in 2025, broadens "mineral oils" to cover CBM, shale, gas hydrates and explicitly supports CCUS/EOR activity, and provides for updated petroleum lease rules; detailed rules were being notified - cite the amendment, not a specific rule number, unless verified.
  • Environment and safety: Environment (Protection) Act, 1986 with EIA Notification 2006 (as amended) and MoEFCC clearance for projects; OISD standards (e.g. OISD-STD-105, 118 and the series on onshore production and well-operations safety) are enforced by the Oil Industry Safety Directorate and PNGRB for midstream; CPCB consent for produced-water disposal and injection; PESO for pressure vessels and compressed gases. Occupational health, hours and welfare at installations now fall under the four Labour Codes in force from 21 November 2025 (which replaced the Factories Act and allied Acts).
  • GST on EOR chemicals, services and equipment falls in the current 5%/18%/40% slab structure effective 22 September 2025 - classification is item-specific.

Key points

• EOR - injection of fluids/energy not native to the reservoir to recover oil left after primary and secondary recovery.
• IOR ⊃ EOR - IOR includes infill drilling, horizontal wells and conformance work; EOR is specifically the non-native-fluid part.
• E = E_D × E_A × E_V - total recovery efficiency is the product of microscopic displacement and areal and vertical sweep.
• Residual oil - trapped by capillary forces; bypassed oil - never contacted. Chemicals with ultra-low IFT fix the first; mobility control and conformance fix the second.
• Mobility ratio M - M ≤ 1 gives a stable front; M > 1 gives viscous fingering and early water/gas breakthrough.
• Capillary number N_c = vμ/σ - Sor falls only above N_c ≈ 10⁻⁵, which needs IFT cut by 3-4 orders of magnitude.
• Polymer flooding - improves sweep (E_A, E_V) only; it does not lower Sor. HPAM is cheap but salinity-, shear- and temperature-sensitive.
• Surfactant flooding - lowers IFT to ~10⁻³ mN/m; the design target is Winsor Type III middle-phase microemulsion at optimum salinity.
• Alkali - generates in-situ soap from naphthenic acids and cuts surfactant/polymer adsorption; needs acidic crude.
• ASP - combines all three mechanisms; highest incremental recovery, highest operational complexity.
• MMP - minimum pressure for multi-contact miscibility; rises with temperature, oil heaviness and methane/N₂ in the gas; measured by slim-tube test.
• CO₂ EOR mechanisms - oil swelling, viscosity reduction, light-end extraction, IFT reduction, and permanent CO₂ storage (CCUS link).
• WAG - alternating water and gas slugs to control gas mobility, fingering and gravity override.
• Thermal EOR - the answer for heavy oil; CSS (single well, quick), steam flood (pattern, high recovery), SAGD (horizontal pair, gravity drainage).
• SOR - steam-oil ratio is the economic yardstick of a steam project; above roughly 6-8 it stops paying.
• In-situ combustion - burns 5-10% of the oil in situ as fuel; avoids surface heat loss, works deep, but is hard to control. ONGC Balol/Santhal is the Indian example.
• Screening then piloting - published screening criteria → core floods and phase behaviour → numerical simulation → single-well/pattern pilot → full-field FDP approved by DGH.
• Mangala (Barmer) - India's flagship polymer flood with an ASP follow-up; ONGC Gujarat heavy-oil fields are the thermal/ISC reference.

Formulas and examples

Example 1 - Recovery efficiency and the EOR target. A sandstone reservoir: bulk volume 50 × 10⁶ m³, φ = 0.22, S_wi = 0.25, B_oi = 1.25.

• OOIP N = 50×10⁶ × 0.22 × 0.75 / 1.25 = 8.25×10⁶/1.25 = 6.60 × 10⁶ m³ (stock tank) ≈ 41.5 million bbl (1 m³ = 6.2898 bbl).
• Waterflood: S_oi = 0.75, S_orw = 0.30 → E_D = (0.75 − 0.30)/0.75 = 0.60; E_A = 0.70, E_V = 0.80 → E = 0.60 × 0.70 × 0.80 = 0.336 → 0.336 × 6.60×10⁶ = 2.22 × 10⁶ m³.
• ASP flood reduces S_or to 0.15 and polymer improves sweep to E_A = 0.85, E_V = 0.85 → E_D = (0.75 − 0.15)/0.75 = 0.80; E = 0.80 × 0.85 × 0.85 = 0.578 → 0.578 × 6.60×10⁶ = 3.82 × 10⁶ m³.
• Incremental oil = 3.82 − 2.22 = 1.60 × 10⁶ m³ ≈ 10.0 million bbl, i.e. about 24% of OOIP extra. At a crude price of US$70/bbl that is roughly US$0.70 billion gross revenue (prices and the rupee rate vary, so treat this as an order of magnitude only).

Example 2 - Mobility ratio, polymer design and water cut. At the flood front: k_rw = 0.10, k_ro = 0.30, μ_o = 20 cP, μ_w = 0.5 cP.

• Water: M = (0.10/0.5)/(0.30/20) = 0.200/0.015 = 13.3 → strongly unfavourable, severe fingering.
• f_w = 1/[1 + (0.30 × 0.5)/(0.10 × 20)] = 1/[1 + 0.15/2] = 1/1.075 = 0.93 → 93% water cut at that saturation.
• Design a polymer solution of 20 cP: M = (0.10/20)/(0.015) = 0.005/0.015 = 0.33 → favourable, near piston-like.
• f_w = 1/[1 + (0.30 × 20)/(0.10 × 20)] = 1/[1 + 6/2] = 1/4 = 0.25 → 25% water cut, so the oil cut rises from 7% to 75% at the same saturation. Required viscosity = μ_o × (k_rw/k_ro) / M_target ⇒ 20 cP gives M = 0.33; 6.7 cP would give M = 1.0.

Example 3 - Capillary number: why surfactants are needed. Darcy velocity v = 1 m/day = 1/86,400 = 1.157 × 10⁻⁵ m/s; μ_w = 1 cP = 1 × 10⁻³ Pa·s.

• Plain water, σ = 30 mN/m = 0.030 N/m: N_c = (1.157×10⁻⁵ × 1×10⁻³)/0.030 = 1.157×10⁻⁸/0.030 = 3.86 × 10⁻⁷ - far below the 10⁻⁵ desaturation threshold, so S_or is untouched.
• Surfactant slug, σ = 3 × 10⁻³ mN/m = 3 × 10⁻⁶ N/m: N_c = 1.157×10⁻⁸/3×10⁻⁶ = 3.86 × 10⁻³ - a 10,000-fold increase, well past the threshold, so S_or can fall to near zero in the swept zone.
• Note what raising velocity alone would do: a 10× rate increase gives only 3.86 × 10⁻⁶ - still short. IFT is the only practical lever.

Example 4 - Steam project energy balance and SOR. Injection: 200 t/day of 80%-quality steam at 5 MPa (T_sat ≈ 264 °C; h_f ≈ 1,154 kJ/kg, h_fg ≈ 1,640 kJ/kg), feedwater at 25 °C (h ≈ 105 kJ/kg). Generator efficiency 85%, fuel gas CV 38 MJ/Sm³. Field SOR = 4.

• Injected enthalpy h = 1,154 + 0.8 × 1,640 = 1,154 + 1,312 = 2,466 kJ/kg; net heat added = 2,466 − 105 = 2,361 kJ/kg.
• Heat injected = 200,000 kg × 2,361 kJ/kg = 4.722 × 10⁸ kJ/day = 472 GJ/day.
• Fuel energy = 472/0.85 = 556 GJ/day → gas burnt = 556,000 MJ / 38 MJ/Sm³ ≈ 14,600 Sm³/day.
• Oil produced = water equivalent of steam / SOR = 200 m³/4 = 50 m³/day (≈ 315 bbl/day).
• Energy in that oil = 50 × 850 kg/m³ × 42 MJ/kg = 42,500 kg × 42 = 1.785 × 10⁶ MJ = 1,785 GJ/day.
• Fuel burnt as a share of produced-oil energy = 556/1,785 = 31% - viable. If SOR rose to 10, oil = 20 m³/day, oil energy = 714 GJ and fuel share = 78% - the project would be uneconomic and carbon-heavy. This is why SOR is watched daily.

Example 5 - CO₂ requirement and storage credit. A CO₂-EOR pattern is forecast to yield 1.2 million bbl incremental oil at a net utilisation of 0.30 t CO₂/bbl, with gross utilisation 8 Mscf/bbl (recycled).

• Net CO₂ permanently stored = 1.2 × 10⁶ × 0.30 = 360,000 t CO₂.
• Gross CO₂ circulated = 1.2 × 10⁶ × 8 = 9.6 × 10⁶ Mscf = 9.6 Bscf, so recycle compression must handle roughly (9.6 Bscf − purchased volume) - at a CO₂ density of about 1.87 kg/Sm³ at standard conditions, 360,000 t corresponds to ~6.8 Bscf purchased, leaving ~2.8 Bscf of recycle. The recycle plant, not the oil, usually sets the opex.

Where it is used

• National oil companies: ONGC and Oil India reservoir-management and IOR/EOR groups - screening mature Gujarat, Assam, Rajasthan and offshore fields, running pilots, and preparing FDPs and EOR revisions for DGH Management Committee approval.
• Private and JV operators: Cairn Oil & Gas (Vedanta) at Barmer - polymer and ASP; Reliance-BP, Vedanta and DSF operators for gas injection and IOR studies.
• Service companies and chemical suppliers: SLB, Halliburton, Baker Hughes (reservoir studies, core-flood labs, injection equipment); SNF, Kemira, BASF, Dow and Indian specialty-chemical firms supplying polymers and surfactants; Thermax/boiler vendors for steam generation.
• Laboratories and R&D: ONGC's Institute of Reservoir Studies (Ahmedabad) and KDMIPE (Dehradun), TERI (MEOR), IIT Bombay/ISM Dhanbad/Pandit Deendayal Energy University and IIPE Visakhapatnam - core floods, phase behaviour, slim-tube MMP, simulation.
• CCUS and energy transition roles: pairing refinery, fertiliser and cement CO₂ capture with EOR fields under the national CCUS push; carbon accounting and MRV (monitoring, reporting, verification) work.
• Job roles: reservoir engineer, EOR/IOR engineer, simulation engineer, production chemist, field operations engineer on an injection project, and regulatory/reservoir-audit roles at DGH.

Interview questions

• Q: Define EOR and distinguish it from secondary recovery. A: EOR injects fluids or energy not naturally present in the reservoir (polymer, surfactant, CO₂, steam, air) to alter interfacial, viscous or thermal properties; secondary recovery injects native fluids - water or gas - only for pressure maintenance and displacement.
• Q: Which EOR methods lower residual oil saturation and which only improve sweep? A: Surfactant/ASP, miscible gas and thermal methods lower S_or; polymer flooding and conformance gels only improve areal and vertical sweep, and produce the mobile oil faster and more completely.
• Q: What is the capillary number and what value matters? A: N_c = vμ/σ, the ratio of viscous to capillary forces; S_or begins to fall once N_c exceeds about 10⁻⁵, which is why IFT must be reduced to roughly 10⁻³ mN/m.
• Q: Why is a mobility ratio above one bad? A: The displacing fluid moves more easily than the oil, so the front is unstable - fingers break through to producers early, leaving large unswept volumes and high water or gas cut.
• Q: What is MMP and how is it measured? A: The minimum pressure at which the injected gas and reservoir oil become multi-contact miscible at reservoir temperature; measured by slim-tube displacement (90-95% recovery criterion), rising-bubble apparatus or vanishing-IFT, and estimated by correlations or EOS simulation.
• Q: Does MMP go up or down with temperature and oil gravity? A: It rises with reservoir temperature and with heavier, intermediate-poor oil; methane or nitrogen in the injected stream also raises it, while enriching the gas with C₂-C₄ lowers it.
• Q: Why is WAG used instead of continuous gas injection? A: Gas has very low viscosity and density, so water slugs alternated with gas reduce gas mobility, suppress fingering and gravity override, and improve both areal and vertical sweep.
• Q: What does the alkali do in an ASP flood? A: It saponifies naphthenic acids in the crude to generate in-situ soap that lowers IFT, raises pH to cut surfactant and polymer adsorption on the rock, and helps alter wettability - which reduces the costly surfactant loading.
• Q: Why does HPAM fail in some reservoirs? A: High salinity and divalent ions collapse its viscosity, high shear at perforations and pumps mechanically degrades it, and above roughly 70-90 °C it hydrolyses and can precipitate with calcium.
• Q: When would you choose in-situ combustion over steam flooding? A: For deeper reservoirs where surface and wellbore heat losses make steam uneconomic, where water or fuel for steam generation is scarce, and where the crude leaves enough coke as fuel - accepting much harder front control, as at ONGC's Balol and Santhal.
• Q: A heavy-oil field is at 2,500 m with oil of 5,000 cP. What do you propose? A: Steam is ruled out by depth-related heat loss, and chemical methods by viscosity; consider in-situ combustion or electrical/EM heating with horizontal wells, after core and combustion-tube tests - or accept cold production with mobility-controlled waterflood if nothing screens in.
• Q: Which Indian field is the reference for chemical EOR, and why is it cited? A: Mangala in the Barmer basin (Cairn Oil & Gas), one of the world's largest polymer floods since 2014, followed by an ASP pilot - it showed that a high-temperature, moderately saline sandstone can be polymer-flooded at full-field scale.
• Q: How does CO₂-EOR fit India's climate goals? A: Each barrel produced traps roughly 0.2-0.4 t of CO₂ in the reservoir, so EOR gives captured CO₂ from refineries and fertiliser plants a revenue-bearing sink, which is the commercial backbone of the CCUS pathway towards net zero by 2070.

Common mistakes

• Claiming polymer flooding reduces residual oil saturation - it changes mobility and sweep, not capillary trapping; the ultimate S_or in the swept zone is unchanged.
• Inverting the mobility ratio (writing displaced over displacing) and then calling M = 13 favourable.
• Mixing units in N_c: stay in one consistent set - viscosity in Pa·s with IFT in N/m (cP with mN/m happens to cancel, as both are 10³ off), but pairing cP with N/m makes the answer 10³ times too large.
• Treating a published screening table as a decision - core floods, phase-behaviour scans and simulation, then a pilot, are what justify an FDP.
• Forgetting that miscible flooding needs reservoir pressure above MMP but below fracture pressure; an "MMP-miscible" design that fractures the cap rock is not a design.
• Quoting air-free recovery figures for ISC or ignoring that 5-10% of the oil is burnt as fuel, and ignoring produced-gas corrosion and safety.
• Reporting an incremental-recovery percentage without saying whether it is of OOIP, of remaining oil, or of the pattern pore volume - the three differ by factors of two or more.
• Ignoring surface constraints: polymer back-production, produced-water treatment, de-emulsification and CO₂ recycle compression often decide whether an EOR project is viable.

Related topics

Reservoir rock and fluid properties · Reservoir engineering: material balance and decline curves · Waterflooding and immiscible displacement (Buckley-Leverett) · Reservoir simulation and history matching · Well stimulation: hydraulic fracturing and matrix acidising · CCUS and carbon storage in depleted reservoirs