injectivity test, Oil & Gas Glossary

What Is an Injectivity Test?

Injectivity test (also called an injection well test or constant-rate injection test) is a pressure transient test conducted on an injection well by injecting fluid at a constant rate and measuring the resulting increase in bottomhole pressure over time. The test is the injection-well analog of a drawdown test on a production well. Engineers use injectivity tests to determine formation permeability near the wellbore, skin factor, injectivity index, and whether the formation can accept the planned injection volumes at acceptable wellhead pressures without fracturing the rock.

Key Takeaways

An injectivity test is run at a constant injection rate while bottomhole pressure (BHP) is recorded continuously, mirroring a production drawdown test in reverse.
The injectivity index (II) is calculated as II = q / (Pwf - Pi), expressed in barrels per day per psi (bbl/day/psi), quantifying how readily the formation accepts fluid.
Semi-log analysis of BHP versus time yields permeability-thickness (kh) and skin factor using the same equations as a drawdown test, substituting injection rate for production rate.
The Hall integral method monitors long-term injectivity from cumulative injection and pressure data; a rising slope indicates plugging while a falling slope suggests fracture extension.
U.S. EPA Underground Injection Control (UIC) Class II regulations require injectivity testing before commencing disposal operations and periodically thereafter to protect underground sources of drinking water.

How an Injectivity Test Works

Before the test begins, the injection well is shut in long enough for bottomhole pressure to stabilize at the static reservoir pressure (Pi). A high-resolution electronic pressure gauge — typically a quartz crystal gauge with resolution of 0.01 psi or better — is positioned in the wellbore near the perforations. Injection begins at a carefully controlled constant surface rate, and BHP is recorded continuously from the moment fluid reaches the formation. The test continues for hours to days depending on well spacing, formation permeability, and the minimum pressure signal needed to characterize the reservoir.

During injection, BHP rises above Pi as the injected fluid pressurizes the near-wellbore rock. On a semi-log plot of BHP versus log(time), the data follow a straight line during the transient radial flow period. The slope of this line (m, in psi/log cycle) is used in the Theis equation to calculate the permeability-thickness product: kh = 162.6 q mu B / m, where q is injection rate in bbl/day, mu is fluid viscosity in centipoise, and B is formation volume factor. Skin factor (s) is derived from the y-intercept of the straight line relative to Pi, indicating whether the wellbore region is damaged (positive skin) or stimulated (negative skin). After the constant-rate injection period, the well is shut in for a pressure falloff test — the injection analog of a buildup test — which provides a cleaner analysis because wellbore storage effects diminish rapidly when injection stops.

Fast Facts: Injectivity Test

Primary output: Injectivity index (II), permeability (k), skin factor (s)
Injectivity index units: bbl/day/psi (field) or m3/day/kPa (SI)
Typical II range: 0.5 to 50 bbl/day/psi depending on formation
Gauge resolution required: 0.01 psi or better for reliable analysis
Companion test: Step-rate test to locate fracture extension pressure
Long-term monitoring: Hall integral method using cumulative data
Regulatory requirement: EPA UIC Class II for disposal wells; Class I for hazardous waste
Key distinction from production test: BHP rises during injection vs. falls during production

Field Tip:

Always run a step-rate test before or immediately after the injectivity test. The step-rate test incrementally increases injection rate in fixed steps (5 to 10 minutes each) and plots wellhead injection pressure versus rate. The rate at which the pressure-rate relationship changes slope is the fracture extension pressure. Knowing this value tells operators the maximum safe injection rate that avoids inadvertent hydraulic fracturing — critical for disposal well compliance and waterflood design. Running both tests in sequence saves rig time and provides a complete picture of wellbore and formation behavior.

Injectivity Index and Semi-Log Analysis

The injectivity index (II) is the fundamental performance metric for any injection well. It is defined as II = q / (Pwf - Pi), where q is the steady-state injection rate (bbl/day), Pwf is the flowing (injecting) bottomhole pressure (psi), and Pi is the original static reservoir pressure (psi). A high II means the formation readily accepts fluid at low pressure differentials; a low II indicates tight rock, damage, or plugging that restricts fluid entry. For waterfloods, operators target an II that allows the planned injection rate without exceeding the fracture pressure. For disposal wells, a declining II over time is an early warning of formation plugging by suspended solids, bacteria, or scale.

Semi-log analysis follows the same mathematical framework as the drawdown test. During radial flow, BHP = Pi + m log(t) + c, where m is the slope of the semi-log straight line. Permeability is extracted from m using the transmissibility equation. The departure of the first data points from the straight line reflects wellbore storage (the compressibility of fluid in the wellbore); this period must be excluded from the straight-line fit. Type-curve matching using Bourdet derivative plots is the modern refinement that identifies radial flow and other flow regimes unambiguously, particularly useful when storage effects are large or when reservoir boundaries affect the pressure response.

Hall Integral Method for Long-Term Monitoring

The Hall integral method is a simple graphical technique for monitoring injectivity over the life of an injection well without requiring a formal pressure transient test. It is widely used in waterflood operations. The Hall plot graphs cumulative injection pressure (the integral of injection pressure over time, in psi-days) on the y-axis against cumulative injection volume (barrels) on the x-axis. Under steady-state conditions with constant formation properties, the data plot as a straight line. A steepening slope (increasing resistance) signals formation plugging caused by suspended solids, bacterial growth, scale deposition, or clay swelling. A flattening slope (decreasing resistance) indicates that the injection pressure has exceeded the fracture extension pressure and the formation is being fractured, providing a preferential flow path. The Hall plot is not a substitute for a pressure transient test but serves as an inexpensive surveillance tool between formal tests.

EPA UIC Requirements and Disposal Well Testing

In the United States, the Environmental Protection Agency's Underground Injection Control program regulates injection wells under the Safe Drinking Water Act. Class II wells (used for oilfield brine disposal and enhanced recovery) must demonstrate mechanical integrity and adequate injectivity before receiving an operating permit. An injectivity test is required to show that the receiving formation has sufficient capacity and that the injection pressure will not drive fluid into underground sources of drinking water (USDWs). Operators must also demonstrate that the confining zone above the injection interval is competent to contain the injected fluid. Periodic mechanical integrity tests are required during the operating life of the well. State regulatory agencies (for example, the Texas Railroad Commission, the Colorado Oil and Gas Conservation Commission, and the Oklahoma Corporation Commission) administer UIC Class II programs under EPA primacy agreements and may impose additional testing requirements.

Injectivity Decline and Formation Plugging

One of the most common problems in water injection operations is the progressive decline of injectivity over time. The primary causes are suspended solids in the injection water (formation fines, iron oxides, pipe scale), bacterial growth that forms biofilms at the formation face, incompatibility between injected water and formation water that precipitates mineral scale (calcium carbonate, barium sulfate), and clay swelling caused by low-salinity water contacting swelling clays. Engineers monitor injectivity by tracking the injection pressure required to maintain a constant rate or, equivalently, by tracking the rate achievable at the maximum permitted wellhead pressure. Periodic workover treatments — acid stimulation to dissolve carbonate scale, biocides to kill bacteria, or mechanical cleanout of perforations — can partially restore injectivity. Source water filtration and biocide treatment are the most effective preventive measures.

Injectivity test is also referred to as:

Injection well test — the general term for any pressure transient test on a well receiving fluid rather than producing it.
Constant-rate injection test — emphasizes the test condition of maintaining a fixed injection rate throughout the measurement period.
Injectivity survey — sometimes used in regulatory contexts to describe both the pressure transient analysis and the mechanical integrity assessment performed together on a disposal well.
Pressure falloff test — technically the shut-in phase that follows the constant-rate injection period; it is the injection analog of a pressure buildup test and usually provides cleaner data than the injection phase itself.

Frequently Asked Questions About Injectivity Tests

How long does an injectivity test take?

Test duration depends on formation permeability, injection rate, and the depth of investigation required. In high-permeability sandstone formations (100+ millidarcies), a useful injectivity test may take only 4 to 12 hours to reach radial flow. In tighter formations (1 to 10 millidarcies), tests of 24 to 72 hours may be needed. The subsequent pressure falloff period is typically run for at least as long as the injection period. A complete injectivity test plus falloff test in a moderate-permeability disposal zone typically takes 2 to 4 days from start to finish, including gauge deployment and retrieval.

What is the difference between an injectivity test and a pressure falloff test?

An injectivity test refers to the injection phase — fluid is pumped into the well at a constant rate while BHP is recorded rising over time. A pressure falloff test is the subsequent shut-in phase — injection stops and BHP is recorded falling back toward Pi. Both phases provide information about permeability and skin, but the falloff test is generally preferred for analysis because wellbore storage effects (the compressibility of the wellbore fluid column) decay quickly after shut-in, allowing the reservoir signal to emerge sooner. In practice, both phases are analyzed together for the most complete characterization.

Can an injectivity test detect faults or reservoir boundaries?

Yes, but only if the test is run long enough for the pressure pulse to reach the boundary and return a detectable signal at the injection well. A sealing fault appears as a doubling of the semi-log slope (the boundary effect), while a constant-pressure boundary (such as a large aquifer or strong pressure support) causes the BHP to stabilize. Detecting boundaries typically requires test durations significantly longer than those needed just to characterize permeability and skin. For interwell connectivity, an interference test — which monitors pressure in a separate observation well — is more effective than a single-well injectivity test.

Why Injectivity Tests Matter in Oil and Gas

Injectivity tests are the foundation of sound injection well management. Without accurate knowledge of the injectivity index, skin factor, and fracture extension pressure, operators risk either under-injecting (leaving recoverable oil behind in a waterflood) or over-pressuring the formation (fracturing the cap rock, contaminating drinking water aquifers, and triggering induced seismicity). For enhanced recovery projects, the injectivity test confirms that the reservoir will accept the design injection volume at pressures below fracture gradient, ensuring that flood patterns will develop as planned. For disposal wells handling produced water — a volume that can reach 10 barrels of water per barrel of oil in mature fields — injectivity determines the well's daily capacity and the number of wells needed. Regulators, investors, and reservoir engineers all rely on injectivity test data to make decisions that affect field economics and environmental compliance for the life of the asset.