Influx Types (Gas, Oil, Salt Water) & Influx Density Determination

When a kick occurs, formation fluid enters the wellbore. The type of fluid entering the well—whether gas, oil, or formation water—has a profound impact on how the kick will behave and the severity of the well control event. Identifying the influx type is one of the first and most critical steps in well control, allowing the drilling team to prepare the correct response, anticipate surface pressures, and properly size surface separation equipment.

Main Influx Types

There are three primary types of influxes encountered in drilling operations, each with specific fluid properties and hazards:

1. Gas: This includes hydrocarbon gases such as methane, hydrogen sulfide ($H_2S$), and carbon dioxide ($CO_2$). Gas is a significant type of influx due to its low density, high compressibility, and tendency to expand rapidly as it migrates to the surface. A gas influx can expand greatly as pressure falls, challenging pressure control and surface gas-handling capacity. Furthermore, sour gas kicks ($H_2S$) present severe toxicity hazards that require specialized breathing apparatus and appropriate equipment material qualification for the actual sour-service conditions to address sulfide stress cracking. Follow the approved gas-hazard and emergency plan, including its respiratory-protection requirements.
2. Oil: Crude oil influxes are less compressible than gas and have a higher density. While generally easier to handle than a pure gas kick, oil can still present significant challenges, especially if it contains dissolved gas that breaks out of solution near the surface. In deeper, hotter wells, the phase boundary between oil and gas can blur, resulting in volatile oil or rich condensate kicks that act like a liquid at the bottom of the well but transition to a highly gaseous state near the surface.
3. Formation water: Water can be fresh or saline and may carry dissolved gases or contaminants. Its density and hazard depend on composition and conditions, and a large water influx can still pose a serious control problem. Formation water is often highly saline (brine) and is the most dense of the common influx fluids. It is largely incompressible. A water kick is generally the easiest to circulate out because it does not expand significantly and therefore does not cause the drastic pressure increases associated with gas expansion. However, its higher density means it requires a much smaller underbalance (a smaller reduction in hydrostatic pressure relative to formation pressure) to cause a very large influx volume to enter the wellbore before the well is shut in.

Density and Gradient Comparisons

Initial pit gain is an estimate of influx volume after accounting for transfers, storage, compression and other relevant effects. The influx need not start around the collars: tripping, an off-bottom bit or another entry depth can change its location. Use the actual capacity profile and position. For the following worked exercise, assume a uniform vertical annulus, the stated influx location, reliable communicating pressures and no other density or gauge effects.

The inferred gradient is only a model-based estimate. A value such as 0.12 psi/ft is consistent with a low-density influx, but composition, phase and conditions prevent unique identification from that number. Prepare suitable gas handling and toxic-gas monitoring based on the potential hazards while the supervisor assesses the evidence.

Influx density depends on composition, pressure and temperature. Gas, oil, water or mixtures can enter, and no one surface-pressure difference uniquely identifies the composition. H2S and CO2 add toxicity or oxygen-displacement hazards, while hydrocarbons introduce flammability. Inflow rate depends on formation permeability, fluid mobility and pressure differential; water does not universally need less underbalance to create a large influx.

Determining Influx Volume

$$V_{\text{influx}} = \Delta V_{\text{pit}}$$

Calculating Influx Height

Once the volume is firmly established, the height the influx occupies in the annulus ($h_{\text{influx}}$) must be calculated. The height is highly dependent on the annular capacity of the specific section of the wellbore where the influx is located.

$$h_{\text{influx}} = \frac{V_{\text{influx}}}{\text{Annular Capacity (bbl/ft)}}$$

Determining Influx Gradient

The critical influx gradient ($g_{\text{influx}}$) can be calculated once the well is shut in and the surface pressures (both drill pipe and casing) have fully stabilized. This calculation relies fundamentally on the difference between the Shut-In Casing Pressure (SICP) and the Shut-In Drill Pipe Pressure (SIDPP). Assuming a clean drill string full of drilling mud, the difference in these two surface pressures is, under the stated simplified assumptions, attributed to the difference in hydrostatic pressure between the pure mud in the drill string and the mixed, lighter column of mud and influx fluid in the annulus.

The standard formula to determine the influx gradient is:

$$g_{\text{influx}} = \text{Mud Gradient} - \frac{\text{SICP} - \text{SIDPP}}{h_{\text{influx}}}$$

Where:

• Mud Gradient is the gradient of the current, uncontaminated drilling fluid in psi/ft.
• SICP is the Shut-In Casing Pressure in psi.
• SIDPP is the Shut-In Drill Pipe Pressure in psi.
• $h_{\text{influx}}$ is the calculated vertical height of the influx in ft.

Worked Calculation: Identifying the Influx Type

Let's apply these principles to a comprehensive practical example to determine the influx type in a real-world scenario.

Well Data:

• Well Depth (True Vertical Depth, TVD): 10,000 ft
• Mud Weight: 10.0 ppg (Mud Gradient = 0.52 psi/ft)
• Pit Gain: 15 bbls
• SIDPP: 500 psi
• SICP: 700 psi
• DC Length: 600 ft
• DC/Open Hole Annular Capacity: 0.03 bbl/ft

Step 1: Determine Influx Volume $V_{\text{influx}} = \text{Pit Gain} = 15 \text{ bbls}$

Step 2: Calculate Influx Height First, we must check if the influx fits entirely within the DC annulus. Total Volume of DC annulus = $600 \text{ ft} \times 0.03 \text{ bbl/ft} = 18 \text{ bbls}$. The 15 bbl influx is less than the 18 bbl maximum capacity, meaning it fits entirely around the drill collars. $h_{\text{influx}} = \frac{15 \text{ bbls}}{0.03 \text{ bbl/ft}} = 500 \text{ ft}$

The total vertical height of the influx is 500 ft.

Step 3: Calculate Influx Gradient Using the gradient formula: $g_{\text{influx}} = 0.52 \text{ psi/ft} - \frac{700 \text{ psi} - 500 \text{ psi}}{500 \text{ ft}}$ $g_{\text{influx}} = 0.52 - \frac{200}{500}$ $g_{\text{influx}} = 0.52 - 0.40 = 0.12 \text{ psi/ft}$