How to Calculate CO2 Injection Well Deliverability
Secure carbon storage projects live or die by dependable injection deliverability. Reservoir simulators may project high throughput, yet lenders and regulators ultimately demand verifiable calculations backed by pressure data, injectivity testing, and conservative safety margins. This walkthrough distils those expectations into a transparent workflow, complementing energy demand analytics captured in the direct air capture regeneration energy guide and operations planning insights from the solvent replacement walkthrough.
We define the injectivity-based deliverability formula, explain how to standardise pressure windows and dense-phase properties, and offer step-by-step guidance for integrating test results with commercial schedules. Validation checks tie calculated rates back to monitoring logs and contingency scenarios such as buffer storage requirements discussed in the cryogenic hydrogen boil-off guide.
Definition and scope
CO₂ injection well deliverability quantifies the sustainable mass or volumetric flow a well can inject while staying within regulatory pressure limits and mechanical constraints. The boundary covers the wellhead or downhole injection pressure limit, the reservoir pressure at which fracture or caprock integrity would be compromised, and any operator-imposed safety margin. Injectivity testing—the ratio between injection rate and pressure differential—serves as the backbone of the calculation.
Deliverability calculations assume single-phase dense CO₂ conditions. If a project experiences phase transitions or injects co-mingled gases, adapt the properties accordingly. Similarly, if multiple strings share a common manifold, compute deliverability per well and then adjust for interference effects captured in reservoir simulations.
Variables and units
Gather the following data points with consistent units:
- pinj – Maximum allowed injection pressure at surface or bottom-hole (bar).
- pres – Reservoir pressure limit or fracture threshold at the same depth reference (bar).
- J – Injectivity index (m³/day per bar) derived from step-rate or falloff tests.
- σ – Safety margin (%). Reduces the usable pressure window to maintain operating headroom.
- ρ – CO₂ density at reservoir conditions (kg/m³).
- qv – Volumetric deliverability (m³/day).
- qm – Mass deliverability (tonnes/day).
Ensure pressure data use the same datum. If pinj is logged at the wellhead while the reservoir limit references bottom-hole pressure, convert using hydrostatic gradients and frictional losses captured during testing. Density should come from an equation of state or high-fidelity simulation; when unavailable, start with dense-phase approximations between 600 and 750 kg/m³ and document the assumption.
Deliverability formulae
Δp = pinj − pres
Δpeff = Δp × (1 − σ)
qv = J × Δpeff
qm = qv × ρ ÷ 1,000
Δp represents the pressure window available for injection. Applying a safety margin shrinks the window to respect operational headroom, maintenance contingencies, and regulatory buffers. Multiplying the effective window by the injectivity index yields volumetric deliverability. Convert to mass rate by multiplying by density and dividing by 1,000 to express tonnes per day.
Injectivity indices derived from single-step tests may not capture long-term skin effects. Re-run the tests after stimulation, acidising, or extended shut-in to keep J current. For wells with non-linear injectivity, compute deliverability in pressure bands and adopt the lowest value across the anticipated operating range.
Step-by-step calculation
1. Consolidate pressure limits
Collect maximum allowable surface or bottom-hole pressures from regulatory permits, well integrity models, and surface equipment specifications. Align those limits to a common reference depth. When using surface pressure, subtract hydrostatic head and frictional losses measured during injectivity tests to approximate the reservoir pressure at the perforations.
2. Determine the reservoir threshold
Establish the pressure at which fracture propagation, caprock failure, or brine migration would breach containment. This often comes from geomechanical studies or mini-frac data. Adopt the most conservative value among regulatory caps, geological assessments, and operational experience.
3. Calculate injectivity index
Perform step-rate tests over multiple pressure increments, ensuring each step reaches steady state. Divide each stabilised volumetric rate by the net pressure difference to obtain injectivity values, then use the average of the linear portion of the curve. Update the index after stimulation or when reservoir pressure evolves materially.
4. Apply safety margin and compute rates
Choose a safety margin consistent with operating policies—5% is typical during steady-state operations, while early ramp-up periods may warrant 10% or more. Multiply the pressure window by (1 − σ), then apply the injectivity index and density to determine volumetric and mass deliverability. Our embedded calculator performs these steps with unit checks and caps the safety margin to prevent negative windows.
5. Integrate with project scheduling
Compare calculated deliverability with planned CO₂ capture rates from upstream facilities. If deliverability falls short, evaluate drilling additional wells, adding artificial lift, or staging buffer storage. Align the outputs with credit stacking or offtake models so financial projections reflect realistic injection throughput.
Validation and monitoring
Validate deliverability by comparing calculated rates with measured injection logs over multi-day periods. Plot actual pressure versus rate to ensure the operational slope matches the assumed injectivity. Investigate deviations beyond ±10%; they may signal scaling, skin growth, or instrumentation drift. Incorporate fibre-optic or distributed temperature sensing data if available to detect channeling or breakthrough.
Document every recalculation in a reservoir management plan. Include sensor calibration records, step-rate test dates, and any geomechanical updates. Link deliverability updates to emergency response plans so operators can throttle injection or divert to buffer storage when pressure approaches the margin.
Limitations and risk considerations
Deterministic calculations assume homogeneous reservoirs. Heterogeneities, faults, or baffles can localise pressure build-up, reducing effective injectivity. Use numerical reservoir models and history matching to refine the estimate over time. Thermal effects, impurities, and phase changes also influence density; update ρ as operating conditions evolve.
Regulatory frameworks may mandate additional safety factors or dynamic modelling. Treat this calculation as a baseline for operational planning, not a substitute for full compliance submissions. Maintain alignment with measurement, reporting, and verification (MRV) requirements so deliverability claims support carbon credit issuance or compliance reporting.
Embed: CO₂ injection deliverability calculator
Supply injection pressure, reservoir limit, injectivity index, safety margin, and density to compute volumetric and mass deliverability for a sequestration well.