An Interactive 5-Day Training Course
Carbonate Reservoir Quality for Hydrocarbon & CO2 Storage
One Rock, Two Storage Requirements
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Duration
5 Days
Price
$ 3,500
Starting From
10 May 2027
Home Geology and Geoscience Carbonate Reservoir Quality for Hydrocarbon & CO2 Storage
Carbonate Reservoir Quality for Hydrocarbon & CO2 Storage
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Carbonate Reservoir Quality for Hydrocarbon & CO2 Storage - GG-CRQ-PEA27
| Code | Date | Time | Duration | Location | Currency | Early Bird Fee Per Person |
|---|---|---|---|---|---|---|
| GG-CRQ-PEA27 | 10 - 14 May 2027 | 10 AM CST | 4 Hours Per Day |
Online |
USD |
3500 |
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Carbonate Reservoir Quality for Hydrocarbon & CO2 Storage
Description
A carbonate reservoir evaluated for hydrocarbon production and the same reservoir evaluated for CO2 storage are assessed against different criteria. Production requires deliverability and recoverable volume; storage requires injectivity at pressures below fracture gradient, capacity measured as accepted volume rather than produced volume, and containment that must be demonstrated in advance and monitored afterwards. Carbonates add a complication that sandstones largely avoid: carbonate minerals react with CO2 bearing brine, so the rock itself can change during injection.
This training develops both assessments together. Carbonate reservoir quality is established first, covering pore types, the pore system control on permeability, rock typing, and the depositional and diagenetic controls on quality distribution. The hydrocarbon requirement is then developed: deliverability, recovery mechanisms, sweep and the properties that matter for production. The storage requirement follows: injectivity and its pressure limits, capacity estimation including pressure-limited capacity, plume migration and the trapping mechanisms available in carbonates. CO2 carbonate interaction is then treated in detail, covering carbonic acid formation, calcite and dolomite dissolution kinetics, the conditions under which dissolution enhances or impairs injectivity, wormholing and preferential pathway development, and the potential for later precipitation. Caprock integrity under acidic conditions follows, together with the risk of seal degradation. Geomechanical response to injection is then addressed. The training closes with site screening, monitoring requirements and the comparison of carbonate against sandstone storage reservoirs.
Carbonate reactivity cuts both ways and the direction depends on conditions. CO2 dissolved in formation brine forms carbonic acid, which dissolves calcite and dolomite. Near the injection well, where CO2 is continuously supplied and brine is being displaced, dissolution dominates and can enhance permeability substantially, improving injectivity. Further out, where the acid has been partly neutralised by reaction, the brine can become supersaturated and precipitate carbonate, reducing permeability. The same process therefore improves injectivity in one place and impairs it in another, and the balance is specific to the mineralogy, the flow rate and the brine chemistry.
Wormholing is the characteristic carbonate injectivity behaviour. Dissolution in a heterogeneous carbonate is unstable: flow concentrates in the highest permeability paths, more acid passes through them, they dissolve faster and become more permeable still. The result is a small number of highly conductive channels rather than uniform permeability enhancement. For injectivity this is beneficial in the short term. For containment and sweep it is a concern, because the injected CO2 travels along a few preferential paths rather than filling the pore volume, reducing effective storage efficiency and concentrating the plume.
Caprock integrity under acidic conditions is the distinctive carbonate storage risk. Where the seal is a carbonate or contains carbonate cement, CO2 bearing brine in contact with it can dissolve that cement, potentially increasing permeability and reducing capillary entry pressure at the base of the seal. The reaction is slow and typically affects only a thin zone, but the obligation to demonstrate containment over long periods means it must be assessed rather than assumed negligible. Shale and evaporite seals above carbonate reservoirs avoid most of this concern.
Finally, the trapping mechanisms differ in their reliance on rock properties. Structural trapping depends on the seal; residual trapping depends on relative permeability hysteresis and the pore system; solubility trapping depends on brine volume contacted, which depends on sweep; mineral trapping depends on the availability of reactive cations, and in carbonates that reaction largely returns the CO2 to carbonate rather than fixing additional carbon. Carbonate reservoirs therefore rely more heavily on structural and residual trapping than silicate-rich sandstones do.
By the end of this training, participants will be able to:
- Assess carbonate pore systems and their control on permeability
- Compare the reservoir requirements of hydrocarbon production and CO2 storage
- Evaluate injectivity and pressure-limited capacity in carbonate reservoirs
- Explain CO2 carbonate reaction chemistry and its kinetics
- Assess dissolution and precipitation effects on injectivity and permeability
- Evaluate wormholing and preferential pathway development
- Assess caprock integrity under CO2 bearing acidic conditions
- Evaluate trapping mechanisms available in carbonate reservoirs
- Assess geomechanical response to injection including fault and caprock stability
- Screen carbonate reservoirs for storage and specify monitoring requirements
Organisations sending participants to this training will:
- Assess carbonate reservoirs correctly for storage as well as production
- Avoid applying hydrocarbon screening criteria to storage projects
- Anticipate reactivity effects on injectivity and containment
- Assess caprock integrity in carbonate dominated sections
- Screen depleted carbonate fields for repurposing
- Build capability for carbonate storage projects
Participants will:
- Assess carbonate reservoir quality against two different sets of criteria
- Evaluate injectivity and capacity for storage applications
- Understand CO2 carbonate reactivity and its consequences
- Assess containment risk in carbonate systems
- Screen carbonate storage candidates
- Transfer carbonate expertise into storage projects
- Carbonate reservoir geologists and engineers
- Geoscientists moving into carbon storage projects
- Petrophysicists assessing storage reservoir quality
- Reservoir engineers evaluating injectivity and capacity
- Geochemists working on fluid rock interaction
- Project staff screening storage sites
- Technical staff assessing depleted field repurposing
Module 1 - Carbonate Reservoir Quality Fundamentals
- Carbonate pore type classification
- Pore throat control on permeability
- Porosity permeability decoupling in carbonates
- Rock typing approaches
- Depositional control on reservoir quality
- Diagenetic control and its unpredictability
- Dolomitisation and its property effects
- Fracture contribution to permeability
- Heterogeneity scales in carbonates
- Reservoir quality distribution and its prediction
- Data requirements for quality assessment
Module 2 - Requirements of Each Application
- Hydrocarbon production requirements
- Deliverability and well productivity
- Recoverable volume and recovery factor
- Sweep and displacement efficiency
- CO2 storage requirements
- Injectivity and its maintenance
- Capacity: volumetric and pressure limited
- Containment and its demonstration
- Timescale and reversibility differences
- Regulatory requirements for storage
- Where a good producer is a poor store and the reverse
- Screening criteria compared
Module 3 - CO2 Properties and Behaviour
- CO2 phase behaviour and supercritical conditions
- Density and viscosity at storage conditions
- CO2 brine mutual solubility
- Interfacial tension and wettability
- Relative permeability of CO2 and brine
- Hysteresis and residual trapping
- Buoyancy and plume migration
- Viscous fingering and gravity override
- Impurities in the CO2 stream and their effects
- Temperature effects including Joule Thomson cooling
- Hydrate and dry-out near wellbore effects
Module 4 - CO2 Carbonate Reactivity
- Carbonic acid formation and pH
- Calcite dissolution kinetics
- Dolomite dissolution and its slower rate
- Mineralogy control on reactivity
- Dissolution near the injection well
- Acid neutralisation along the flow path
- Precipitation in the far field
- Reactive transport modelling
- Core flood experimental evidence
- Timescales of reaction
- Impurity effects on reactivity
- Net permeability change and its prediction
Module 5 - Injectivity and Wormholing
- Injectivity determinants in carbonates
- Fracture pressure constraint on injection rate
- Dissolution enhanced injectivity
- Wormholing mechanism and instability
- Wormhole geometry and its controls
- Flow rate dependence of dissolution pattern
- Compact dissolution against wormholing against uniform dissolution
- Preferential pathways and sweep efficiency
- Near wellbore dry-out and salt precipitation
- Injectivity decline mechanisms
- Injectivity testing and monitoring
- Well design for carbonate injection
Module 6 - Containment and Caprock Integrity
- Caprock types above carbonate reservoirs
- Carbonate caprocks and their vulnerability
- Evaporite caprocks and their advantages
- Shale caprocks over carbonate reservoirs
- Capillary entry pressure and column retention
- Caprock reaction with CO2 bearing brine
- Carbonate cement dissolution in seals
- Depth of seal alteration and its rate
- Fault and fracture leakage pathways
- Legacy wells as leakage risks
- Karst and dissolution features as pathways
- Containment demonstration requirements
Module 7 - Geomechanics and Trapping
- Stress state and pore pressure change during injection
- Caprock stress response to injection
- Fault stability and reactivation potential
- Induced seismicity risk assessment
- Chemical weakening from dissolution
- Compaction and subsidence in depleted fields
- Structural trapping in carbonates
- Residual trapping and hysteresis
- Solubility trapping and sweep dependence
- Mineral trapping and its limits in carbonates
- Trapping evolution with time
- Security of storage over long periods
Module 8 - Screening, Monitoring and Application
- Carbonate storage site screening criteria
- Saline carbonate formations
- Depleted carbonate hydrocarbon fields
- Data requirements for site characterisation
- Capacity estimation methods and their uncertainty
- Storage efficiency factors in carbonates
- Reservoir modelling for storage
- Monitoring, measurement and verification design
- Seismic monitoring in carbonate reservoirs and its difficulty
- Pressure and geochemical monitoring
- Well integrity monitoring
- Comparing carbonate and sandstone storage options
Upon successful completion of this training course, delegates will be awarded an official Certificate of Completion issued by the Petroleum Engineers Association (PEA), an ISO 9001:2015 certified training organization. The certificate carries 10 Credits and formally records the total learning hours completed.
Each certificate is signed by the Course Facilitator and the CEO of the Petroleum Engineers Association, and serves as verifiable proof of professional training that delegates can present to employers and professional bodies worldwide.
Frequently Asked Questions
All course bookings made through PEA are strictly non-refundable. By registering for a course, you acknowledge and accept that all fees are payable in full and are not subject to refund under any circumstances, including changes in personal or professional commitments or partial attendance.
PEA reserves the right to make reasonable adjustments to course content, trainers, or schedules where necessary, without entitling delegates to a refund. Comprehensive details of each course — including objectives, target audience, and content — are clearly outlined before enrolment, and it is the responsibility of the delegate to ensure the course's suitability prior to booking.
For any inquiries related to cancellations or bookings, please contact our support team, who will be happy to assist you.
