Injectivity Index Calculator
Calculate injectivity index, maximum injection rate before fracturing, and compare measured vs. theoretical injectivity for skin estimation.
Injection Parameters
Reservoir Properties (for Theoretical II)
II = q / (Pinj - Pr) [bbl/d/psi]
qmax = II × (Pfrac - Pr)
IItheo = 0.00708 kh / (μ Bw ln(re/rw))
Injectivity Index (Measured)
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Max Rate Before Fracturing
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Theoretical II (No Skin)
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Estimated Skin Factor
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Operating Margins
ΔP Injection
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Margin to Frac
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% of Frac Limit
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II Ratio (Meas/Theo)
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How this was calculated
Injectivity Index: II = q / (Pinj - Pr). Measures how easily fluid can be injected into the formation. Typical values: 1-50 bbl/d/psi for water injection.
Maximum rate: q_max = II * (Pfrac - Pr). The maximum injection rate before exceeding fracture pressure. Operating above this risks uncontrolled fracture propagation.
Theoretical II: From Darcy's radial flow equation: II_theo = 0.00708*k*h / (mu*Bw*ln(re/rw)). This assumes zero skin (undamaged wellbore).
Skin from injectivity: If measured II < theoretical II, the well has positive skin (damage). S = (II_theo/II_meas - 1) * ln(re/rw). Negative skin indicates stimulation.
Hall plot: Cumulative (Pinj - Pr) * dt vs. cumulative injection. A straight line indicates constant injectivity. Steepening slope means plugging; flattening means fracturing.
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Book a free strategy call →Understanding Injectivity in Waterflood Operations
The injectivity index is a critical parameter in waterflood and enhanced oil recovery (EOR) operations. It quantifies the relationship between injection rate and pressure differential, telling engineers how efficiently water (or other fluids) can be pushed into the formation. A declining injectivity index often signals near-wellbore damage from suspended solids, scale, or bacterial growth, which can severely impact waterflood efficiency and sweep.
Monitoring injectivity over time via Hall plot analysis is standard practice in waterflood management. The Hall plot (cumulative pressure-time integral vs. cumulative injection) provides a straightforward visual indicator of changes in well performance. A steepening slope indicates increasing resistance (plugging), while a flattening slope suggests fracture development or improved injectivity.
Comparing measured injectivity to theoretical injectivity (calculated from Darcy's law with known reservoir properties) allows estimation of wellbore skin. Positive skin values indicate damage that may be treatable with acid stimulation or mechanical cleaning, potentially recovering significant injection capacity without drilling new wells.
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