What Is Enhanced Oil Recovery (EOR)?
Enhanced oil recovery (EOR), also called tertiary recovery, is the set of methods used to extract oil that remains in a reservoir after primary and secondary recovery stages. Primary recovery uses the natural pressure of the reservoir and pumps; secondary recovery typically injects water or gas to maintain pressure. EOR alters reservoir conditions or fluid properties (for example, reducing oil viscosity or changing wettability) to mobilize and produce oil that otherwise would remain trapped. (Source: Investopedia)
Key takeaways
– EOR is used only after primary and secondary methods have been largely exhausted because EOR methods are more complex and costly.
– The three main EOR families are gas injection (commonly CO2), thermal (steam or in‑situ combustion), and chemical (polymers, surfactants, alkaline).
– EOR can significantly increase ultimate recovery from a field, but whether it’s economical depends on reservoir characteristics, oil price, available infrastructure, and environmental/regulatory constraints.
– Newer approaches (e.g., CO2 foams/gels, plasma pulsing) aim to improve performance and/or reduce environmental impacts. (Source: Investopedia; U.S. DOE)
How Enhanced Oil Recovery works — the basic mechanisms
– Mobility control: EOR reduces the mobility ratio (oil mobility vs. displacing fluid) so injected fluids sweep the reservoir more uniformly and push more oil toward producers.
– Viscosity reduction: Heating (steam) or chemical agents lower crude viscosity so oil flows more easily.
– Miscibility/pressure effects: Injected gases (e.g., CO2) can become miscible with the oil (depending on pressure/temperature), swelling the oil, reducing interfacial tension, and improving flow.
– Wettability alteration: Chemical or thermal methods can change rock–fluid contact behavior to free trapped oil.
– Relative permeability modification: Chemicals or foams may block high‑permeability thief zones and direct displacement toward unswept oil.
Three main types of EOR techniques
1. Gas injection (miscible or immiscible)
– Commonly used gas: carbon dioxide (CO2); also nitrogen or natural gas in some cases.
– Miscible CO2 injection (requires sufficient reservoir pressure/temperature): CO2 dissolves into oil, reducing viscosity and interfacial tension, swelling oil and improving flow.
– Immiscible injection: gas drives oil by pressure/drive mechanisms but does not mix fully.
– Practical advantages: CO2 EOR is mature, can enable both oil recovery and CO2 storage (CCUS synergy).
– Challenges: CO2 sourcing and transportation (pipelines), containment, cost, potential leakage concerns.
2. Thermal methods
– Steam injection: cyclic steam (huff-and-puff) and steam flooding, and steam-assisted gravity drainage (SAGD) for heavy oil/bitumen.
– In‑situ combustion (fire flooding): ignite part of the reservoir ahead of the producers so heat reduces viscosity and combustion gases drive oil.
– Advantages: very effective in heavy oil reservoirs where viscosity is the main limitation.
– Challenges: high energy requirement, potential for reservoir damage, surface emissions.
3. Chemical EOR
– Polymer flooding: increases injected water viscosity to improve mobility ratio and sweep efficiency.
– Surfactant flooding (sometimes combined with alkaline): reduces oil-water interfacial tension to mobilize trapped oil.
– Alkaline flooding: reacts with certain heavy oils to generate surfactants in situ.
– Advantages: can be tailored to reservoir chemistry; effective in heterogeneous reservoirs.
– Challenges: chemical cost, chemical retention/adsorption in the rock, scaling, and handling of produced fluids.
Important considerations (when to use and what to evaluate)
– Reservoir suitability: porosity, permeability, oil viscosity, reservoir pressure and temperature, heterogeneity, thickness, and presence of fractures or thief zones strongly affect technique choice and success.
– Oil price and economics: EOR is capital- and energy‑intensive. Recovery factor uplift must justify capital and operating costs; projects often need higher oil prices or incentives to be economic.
– Infrastructure and utilities: availability/cost of injectants (CO2, steam generation fuels, chemicals), pipeline access, water supply, produced fluid handling and reinjection facilities.
– Regulatory and environmental constraints: permits for injection, groundwater protection, greenhouse gas emissions, CO2 storage regulations, and community considerations.
– Monitoring and conformance: need for reservoir surveillance (pressure, production data, tracers, 4D seismic) to detect bypassed oil and leakage.
– Risk profile: risks include reservoir damage, chemical contamination of groundwater, induced seismicity (in some injective operations), and operational complexities.
Using EOR methods — practical step‑by‑step roadmap
A practical, staged approach reduces risk and improves the chances of an economically successful EOR deployment.
1. Screening and high‑level feasibility
– Collect data: well logs, core data, PVT lab analyses, production history, pressure data, reservoir maps, and seismic.
– Screening metrics: oil viscosity, API gravity, reservoir pressure/temperature, permeability distribution, water saturation, and remaining oil in place (ROIP).
– Pre‑selection: match candidate fields to broad EOR classes (CO2 for light to medium oils at adequate pressure; thermal for heavy oil; chemical for moderate viscosity and heterogeneous reservoirs).
2. Detailed technical and economic evaluation
– Laboratory testing: corefloods, wettability tests, PVT with CO2 or chemicals, compatibility tests with brine and rock, adsorption studies for polymers/surfactants.
– Reservoir simulation: build/upgrade a reservoir model; run sensitivity cases for various injection scenarios, injection rates, patterns, and miscibility windows.
– Economic modelling: estimate capital expenditures (capex), operating expenditures (opex), NPV, IRR, break‑even oil price, payback, and sensitivity to oil price, injectant costs, and recovery factor.
– Regulatory assessment: identify permits, environmental baseline studies, and land access requirements.
3. Pilot test (field pilot)
– Design pilot: select a representative sector, determine injection pattern (huff‑and‑puff, five‑spot, line drive), injection rates, injector–producer pairs, and monitoring plan.
– Implement surface facilities for injectant preparation, measurement, and produced fluid handling.
– Run the pilot for a statistically significant duration to measure incremental oil, sweep efficiency, injectivity, and any adverse effects.
– Monitoring: pressure/temperature, production rates and composition, tracer studies, microseismic (if needed), and groundwater checks near wells.
4. Analysis and decision point
– Compare pilot incremental recovery vs. simulation predictions and economics.
– Identify technical problems (channeling, rapid decline) and adjust design or chemistry.
– If pilot is successful, scale up incrementally rather than full‑field roll-out immediately.
5. Full‑field implementation and optimization
– Phased implementation: prioritize areas with best deliverability and economic return.
– Optimization: control injection patterns, zonal isolation, conformance control (profile modification, gels), and cycle optimization (for steam/chemical huff‑and‑puff).
– Continuous surveillance and modeling updates (history matching 4D seismic, well tests, production logging).
– Decommissioning planning: prepare for end‑of‑life with well abandonment and site remediation plans.
Technique‑specific operational steps (concise)
– CO2 EOR:
1. Secure CO2 supply (natural sources, industrial capture/CCUS).
2. Design injection pressure to achieve miscibility if intended; if not, design for immiscible displacement.
3. Plan injection pattern and recycle handling for produced CO2.
4. Monitor CO2 breakthrough, volumes recycled, soil and groundwater for leakage.
– Steam/thermal:
1. Choose thermal scheme (cyclic steam, steam flood, SAGD).
2. Design steam generation and water treatment facilities.
3. Execute well pairs/horizontal wells and insulation/steam management.
4. Monitor temperature profiles, steam-oil ratio (SOR), and subsidence.
– Chemical (polymer/surfactant):
1. Design slug sizes and concentrations based on coreflood and adsorption tests.
2. Account for polymer shear degradation and brine salinity compatibility.
3. Monitor produced water handling, scaling, and injection pressures.
Environmental, safety and regulatory steps
– Baseline studies: groundwater, soil, air quality, seismicity, and ecological surveys before injection begins.
– Permitting: secure injection permits, environmental impact assessments (EIAs), and plan for public consultation.
– Leak prevention and monitoring: use well integrity programs, surface leak detection, pressure monitoring, tracers, and periodic 4D seismic surveys.
– Produced water and chemical handling: treat and dispose or reinject with appropriate permits; manage produced gas and emissions.
– CO2 storage considerations: if CO2 EOR is intended for net storage, follow regulations for long‑term monitoring, reporting and verification (MRV) and closure.
Economic decision metrics and KPIs
– Incremental recovery factor (percentage points or barrels over baseline).
– Break‑even oil price: minimum oil price required for a positive project NPV.
– Capital intensity per incremental barrel and operating cost per incremental barrel.
– Investment metrics: NPV, IRR, payback period under base and stress cases.
– Operational KPIs: injectant-to-oil ratio (e.g., tons CO2 per incremental barrel), steam‑oil ratio (SOR), chemical consumption per incremental barrel, produced water cut, and injector/productivity indices.
Risks and common failure modes
– Poor sweep due to heterogeneity or high-permeability thief zones — mitigations: conformance control (gels, foam), selective completion.
– Chemical loss to rock (adsorption) or degradation — mitigations: lab screening, adjust slug sizes and concentrations.
– Economic sensitivity to oil prices and injectant costs — mitigations: phased implementation, flexible contracts for injectants.
– Environmental incidents (leakage, contamination) — mitigations: robust well integrity, monitoring, emergency response plans.
Emerging techniques and innovations
– CO2 foams and gels: reduce CO2 mobility and improve conformance in heterogeneous reservoirs; enable CO2 use where pure CO2 source is distant.
– Plasma pulsing: a non‑injection approach developed in research settings that emits low‑energy waves to lower oil viscosity (may reduce environmental risk since no injectant is introduced).
– Integration with carbon capture, utilization, and storage (CCUS): CO2 EOR can provide economic offset while storing a portion of injected CO2, subject to measurement and regulation.
– Digitalization and 4D seismic: improved monitoring, real‑time control of injection, and better forecasting through data analytics.
Checklist — quick practical guide before you start
1. Gather reservoir and production data; calculate remaining oil in place.
2. Perform laboratory screening (PVT, corefloods, compatibility).
3. Run reservoir simulation scenarios for candidate EOR methods.
4. Conduct an economic analysis with sensitivity to oil price and injectant costs.
5. Obtain regulatory and environmental clearances and do baseline monitoring.
6. Design and run a field pilot with a clear monitoring and data‑collection plan.
7. Review pilot results; scale up in phased stages with continued optimization and monitoring.
References and further reading
– “Enhanced Oil Recovery (EOR)” — Investopedia. https://www.investopedia.com/terms/e/enhanced-oil-recovery.asp
– U.S. Department of Energy, Office of Fossil Energy & Carbon Management — Enhanced Oil Recovery. https://www.energy.gov/fe/science-innovation/oil-gas-research/enhanced-oil-recovery
If you’d like, I can:
– Run a sample screening checklist tailored to a particular reservoir description (porosity, permeability, oil API, temperature);
– Draft a pilot‑test design (objectives, size, injection plan, monitoring program) for CO2, steam, or chemical EOR; or
– Produce an economic sensitivity table that shows required oil prices to justify a typical CO2 EOR project given assumed capex/opex inputs. Which would you prefer?