Gas Behavior in Drilling — An Integrated View
1. Introduction and Key Concepts
A gas influx (“kick”) occurs when formation pressure exceeds the bottom-hole pressure (BHP) in the wellbore, causing gas to enter the well. As that gas moves upward, the pressure of the fluid column above it falls, and the gas expands, changing its volume and density. If not controlled, this process can escalate to a blowout. The behavior of that influx depends strongly on the drilling fluid system, the mud weight, and the thermodynamic properties of the gas under well conditions.
In this article, we will examine:
How gas influx behaves in different mud systems and at varying mud weights
The governing equations and how real gas behavior modifies them
The compressibility factor (z), expansion ratio, and methods of computation
2. Influx Dynamics: How Gas Enters and Moves
2.1 Kick Initiation
A kick begins when:
The mud hydrostatic + friction + pressure due to suspended cuttings in the annulus is less than the formation pore pressure, or
Operations such as tripping (swabbing), underbalanced drilling, loss of drilling fluid, or drilling into high-pressure zones reduce the Bottom Hole Pressure (BHP) below the formation pressure.
At that point, gas (or formation fluid) flows into the wellbore. If the formation fluid is gas, it initially enters in a compressed, dense state.
2.2 Migration and Rise
Once inside, the gas moves upward because of buoyancy and pressure gradients. In the annulus, different multiphase flow regimes may occur (bubble flow, slug flow, churn, annular) depending on gas fraction, mud rheology, geometry, etc.
Bubble flow: Small gas bubbles move upward smoothly through the drilling mud.
Slug flow: Big gas pockets rise and push columns of mud above them.
Churn flow: Gas and mud mix in a rough, swirling, and unstable way as they move upward.
Annular flow: Gas rushes up through the center while a thin layer of mud sticks to the walls.
The slip velocity (i.e., the velocity of the gas relative to the liquid) can vary; typical values in vertical annuli might be on the order of 0.1–1 m/s, depending on mud viscosity, pressure/temperature, and gas void fraction.
Gas behaviour is also affected by upward movement depending on the operation, whether it is being circulated or migrates within a closed system. In the case of circulation, the pressure above the gas continually decreases, and the gas volume increases. In a closed system, if the gas is not allowed to expand, it migrates up with a constant bubble pressure (close to the entry/formation pressure), increasing the surface shut-in pressure and the Bottom Hole Pressure (BHP).
Transient multiphase models (e.g., drift-flux or two-phase flow models), which capture the time-dependent interactions between gas and liquid phases, are often used in simulators to predict the mixture velocity, void fraction, and pressure profile during a kick.
2.3 Gas Behaviour in Different Mud Systems (WBM vs OBM)
The way gas behaves during an influx depends greatly on whether the mud system is water-based (WBM) or oil/synthetic-based (OBM/SBM).
In water-based muds, gas solubility is very low — almost negligible. As a result, gas entering the wellbore stays as bubbles or slugs rather than dissolving into the mud. This makes the gas expansion and surface behavior more predictable. Early warning signs of a kick, such as pit gain, flow increase, or pressure changes, are usually easier to detect because the gas remains visible in the system.
In contrast, oil-based muds can dissolve a large amount of gas as the influx moves upward. This continues until the pressure drops below the bubble point of the gas–mud mixture. At that point, the gas suddenly comes out of solution (flashes) and forms free gas bubbles.
Studies indicate that 60–80% of the gas from an influx can dissolve before being released, which can mask early warning signs. Because much of the gas remains hidden in solution, pit gains or surface flow increases may appear minimal until the gas breaks out near the surface — sometimes causing a sudden pressure surge.
Modern kick simulators and research now account for gas solubility, gas transfer between phases, and interaction with formation flow to predict this behavior more accurately.
Therefore, OBM systems pose greater challenges in kick detection and control, as gas dissolution can delay visible signs of an influx until it is much closer to the surface.
2.4 Influence of Mud Weight (Density)
Mud weight plays two key roles in well control and pressure management:
1. Preventing Influx:
A higher mud weight increases the hydrostatic pressure in the wellbore, keeping the bottomhole pressure (BHP) above the formation pressure. This helps prevent formation fluids from entering the wellbore and causing a kick.
2. Affecting Gas Expansion and Compressibility:
Heavier mud creates higher initial pressure on any gas bubble present in the wellbore. This compresses the gas, reducing its volume and limiting its expansion ratio as it rises compared to a lighter mud.
However, there is always a trade-off.
If the mud weight is excessive, it may fracture the formation, leading to lost circulation.
If it is too low, it increases the risk of an influx.
The goal is to select an optimal mud weight that maintains well control while avoiding formation damage and drilling inefficiencies.
In deep or high-pressure wells, operators typically maintain an overbalance margin of approximately 200–500 psi above the expected formation pressure to compensate for minor pressure fluctuations or swabbing effects.
3. Governing Equations & Real Gas Behavior
3.1 The Ideal Gas Approximation
At low pressures and moderate temperatures, a gas behaves approximately ideally, following:
PV=nRT
Or equivalently, for a given amount of gas (n constant),
P1*V1 /T1 = P2*V2/T2
If we assume isothermal conditions (T ≈ constant), then Boyle’s law applies:
P1*V1 = P2*V2 ⟹ V1/V2 = P2/P1
In a drilling context, we sometimes simplify. If temperature variation is small or assumed linear, then expansion approximates inverse pressure scaling. However, in deep wells with high pressure/temperature, real gas deviations become significant, so corrections are necessary.
3.2 Real Gas Law and the Compressibility Factor
To account for non-ideal behavior, we use:
PV=z nRT
or per unit mass / per mole:
Pv=zRT
where:
z = compressibility factor (dimensionless)
v = specific volume (volume per mole or per unit mass)
R = gas constant appropriate to units
T = absolute temperature
If z=1, the gas behaves ideally. Deviations in real gases come from intermolecular forces and finite molecular volumes.
The compressibility factor z is often less than 1 at moderate pressures (due to attractive forces dominating), and greater than 1 at high pressures (repulsive forces dominating). It varies with pressure and temperature and must be determined via generalized compressibility charts or equations of state (e.g. Peng–Robinson, Redlich–Kwong).
A generalized definition:
z=Pv/RT
Often, practitioners use compressibility correlations or look up z from tables.
4. Gas Expansion Ratio and Its Calculation
The expansion ratio (ER) is a key parameter as it defines how much the gas volume increases as it moves from formation / bottom conditions to surface (or any intermediate section).
4.1 Definition
ER=Vfinal/Vinitial
In drilling terms, one often quotes how many barrels of gas a unit volume at depth would become at the surface.
4.2 Ideal vs Real Gas Expansion Ratio (ER)Equation
Ideal gas (simplified):
ERideal=P1/P2
or if temperature varies,
V2/V1=(P1/P2)*(T2/T1)
Real gas (with z):
Using compressibility, the gas expansion ratio (from point 1 to point 2) is given by:
V2/V1=(P1 *Z2* T2)/(P2* Z1* T1)
Consider Pb, Vb, Tb and Zb as bottom hole conditions at the point of gas entry and Ps, Vs, Ts and Zs as the respective surface conditions:
(Ps Vs) / (Ts Zs) = (Pb Vb) / (Tb Zb)
Vs = (Pb Vb Zs Ts) / (Ps Zb Tb)
The atmospheric conditions are considered as Pressure of 14.695 psia ≈ 14.70 psia, temperature as 60°F ≈ 520° R and the value of Zs is taken as 1. The volume of gas under these conditions will be 1 cu ft.
Vs = (Pb Vb x 1 x 520) / (14.70 x Zb Tb)
Vs = (35.37 x Pb Vb) / (Zb Tb)
4.3 Real Gas Expansion: Theory vs. Field Observations
In practice, the expansion ratio in a real well is often lower than the ideal P1/P2 by 10–30%, especially in HPHT scenarios, due to z deviations. In extreme cases, deviations can be even larger.
1. Theoretical Expansion (Thermodynamic View)
From pure gas laws, the expansion ratio (considering real gas effects) is:
V2/V1 = (P1*z2)/(P2*z1)
If:
Z1 < 1 at high pressure (gas is compressed more than ideal),
Z2 ≈1 at low pressure, then Z2/Z1 > 1
So, mathematically, the real-gas expansion ratio is greater than the ideal P1/P2.
In other words, the real gas expands more than ideal because it was initially “super-compressed” at high pressure (Z₁ < 1).
Conclusion (theoretical): Real gas expansion > ideal expansion.
2. Observed Expansion in Real Wells (Field/Practical View)
However, in real wellbore conditions, the gas is not expanding freely in an ideal environment. The actual measured or effective expansion tends to be less than the ideal ratio, and here’s why:
a) Frictional Pressure Losses
As the gas moves upward through the mud-filled annulus, friction between gas, liquid, and the wellbore wall creates additional backpressure, reducing the effective expansion.
b) Heat Transfer
Gas cools as it expands (Joule–Thomson effect).
Cooling lowers its temperature and partially offsets expansion, so the observed volume increase is smaller than the ideal estimates for isothermal conditions.
c) Gas Entrapment in Mud
In WBM, gas is trapped in bubbles; in OBM, some gas dissolves and later flashes out.
This phase interaction slows down or masks the expansion.
d) Transient Flow Effects
The expansion occurs dynamically as gas migrates, not instantaneously, and part of the energy is used to move the mud column, rather than solely for volume increase.
Conclusion (practical/field): Real well conditions cause less observable expansion than the simple P1/P2 prediction.
4.4 Gas Expansion in Deep and HPHT Wells
In deep wells, gas can expand significantly as it travels from the bottom hole to the surface. Depending on well depth, pressure drop, and gas composition, expansion ratios (ER) of 50× to 200× are not uncommon.
In HPHT wells, real-gas effects can reduce the expansion somewhat compared to the ideal gas assumption. For example, detailed HPHT kick analyses often show the expansion factor may be 15–25% lower than the ideal prediction. Despite this reduction, the resulting gas volumes at the surface remain significant and require careful monitoring.
Special Considerations for Oil-Based Mud (OBM):
In OBM, gas can dissolve into the mud oil phase, complicating the apparent expansion behavior.
While dissolved, gas is effectively compressed by the oil, so the “apparent” expansion ratio may appear lower than the true potential.
Once the pressure drops below the bubble point and gas flashes out, the local expansion ratio can spike suddenly, creating a sharp increase in free gas volume.
Understanding these dynamics is critical for accurate well-control planning, early detection of kicks, and effective response strategies, particularly in deep and HPHT wells where significant gas expansions can rapidly overwhelm surface handling capacity.
Key Citations: