Pressure Regimes

Oil and gas are fluids. Pressure is one the main elements characterizing the physical behavior of fluids in the subsurface. Understanding pressure concepts and their applications is critical to effective petroleum exploration. This section discusses different pressure regimes, mainly concentrating on formation fluid pressures.it also discusses the characteristics and behavior of fluids (liquids and gases) and how an understanding of fluid pressure can be applied to oil and gas exploration.

Pressure is a measure of force per unit area. Pressure in the subsurface is a function of the densities of rocks and fluids. 

1. Normal Hydrostatic Pressure:

Fluids  :  Afluid is “a substance (as a liquid or gas) tending to flow or conform to the outline of its container” (Webster, 1991). Thus, the explorationist should think of oil, gas, and water as fluids to understand their behavior in the subsurface. 

Fluid pressure : is that pressure exerted at a given point in a body of fluid.

Hydrostatic pressure:   Normal hydrostatic pressure is the sum of the accumulated weight of a column of water that rises uninterrupted directly to the surface of the earth. Normally pressured fluids have a great degree of continuity in the subsurface through interconnected pore systems. 

Abnormally pressured fluids can occur where fluids are completely isolated in containers (compartments) that are sealed on all sides.

Hydrostatic mud pressure :  The geological definition of “hydrostatic” differs from the engineering definition. Engineers use “hydrostatic” to refer to the pressure exerted by the mud column in a borehole at a given depth. Hydrostatic mud pressures are found on DST (drill-stem test) reports and on scout ticket reports of DSTs.

Properties of hydrostatic pressure :  

Normal hydrostatic pressure has the following properties (Dahlberg, 1994): 

        •  Amount of pressure increases with depth. 

        •  Rate of pressure change depends only on water density. 

        •  Vector representing the direction of maximum rate of pressure increase is vertical (i.e., the fluid is not flowing laterally). 

        •  The pressure–depth relationship is completely independent of the shape of the fluid container.

Static vs. dynamic fluid : 

Fluid pressure is nondirectional if the fluid is static. If a pressure imbalance exists in any direction, the fluid moves in the direction of lower fluid pressure. The diagrams below illustrate balanced and unbalanced pressures.

2. Geostatic and Lithostatic Pressure : 

Definition:  The geostatic pressure at a given depth is the vertical pressure due to the weight of a column of rock and the fluids contained in the rock above that depth. Lithostatic pressure is the vertical pressure due to the weight of the rock only. 

Geostatic variables : 

Three variables determine geostatic pressure: 

• Densities of formation waters as related to salinities 

• Net thickness of different lithologies, e.g., sandstone, shale, limestone 

• Porosities of different lithologies

Calculating geostatic pressure : 

We can calculate geostatic pressure using the formula below:

PG = [weight of rock column] + [weight of water column] 

PG = [ρm × (1 – φ) × d ] + [ρw ×φ×d]

where: 

PG = geostatic pressure (psi) 

ρm = weighted average of grain (mineral) density (sandstone and shale = 2.65 g/cm3, limestone = 2.71 g/cm3) 

ρw = weighted average of pore-water density (g/cm3)

φ = weighted average of rock porosity 

d = depth (ft) 

To calculate weighted averages, use 1000-ft (300-m) increments

Geostatic gradient : 

Geostatic gradients vary with depth and location. The gradient increases with depth for two reasons: 1. Rock bulk density increases with increasing compaction. 2. Formation water density increases because the amount of total dissolved solids (TDS) in the water increases with depth. For example, in the Cenozoic of Louisiana, the geostatic gradient is 0.85 psi/ft at 1000 ft and 0.95 psi/ft at 14,000 ft.

3. Normal Hydrostatic Pressure Gradients: 

Definition: The hydrostatic pressure gradient is the rate of change in formation fluid pressure with depth. Fluid density is the controlling factor in the normal hydrostatic gradient. 

Factors controlling fluid density: 

Fluid density changes with depth as a result of changes in the following factors:

• Temperature 

• Pressure 

• Fluid composition (including dissolved gases and solids) 

• Fluid phase—gaseous or liquid 

These factors must be taken into account when estimating fluid pressure at depth. The small amount of dissolved gas contributes little to the density and can be ignored in the exploration state.

Factors controlling oil density:

Oil density varies greatly because of the large variety of oil compositions and quantity of dissolved gases. Also, oil composition is inherently much more variable than formation water composition.

Factors controlling gas density :

Gas density is strongly affected by pressure, temperature, and composition. In the reservoir, gas may be in the liquid phase; if so, we should treat it as a very light oil. Predicting gas phase can be complicated. Consult an experienced reservoir engineer when making this prediction.

Ranges of fluid density and gradient variation: 

Oil-field liquids and gases occur in a wide range of compositions. The table below shows typical density ranges and gradients for gas, oil, and water. However, because exceptions occur, have some idea of the type of fluid(s) expected in the area being studied and use appropriate values. 

Fluid	Normal density range (g/cm3)	Gradient range (psi/ft)
Gas (gaseous * )	0.007-0.30	0.003-1.130
Gas (liquid )	0.2-0.4	0.090-0.174
Oil	0.4-1.12	0.174-0.486
Water	1-1.15	0.433-0.5

(*) Varies with pressure , temperature , and composition .