PVT Properties Volume Factors

Picture hydrocarbons in a reservoir as a dynamic fluid, shrinking or expanding as they travel from deep underground to the surface. Understanding PVT properties—pressure, volume, and temperature relationships—is like having a blueprint for how oil, gas, and water behave. In this chapter, we’ll dive into volume factors ($B_o$, $B_g$, $B_w$), which tell us how much hydrocarbons change in volume between reservoir and surface conditions. These factors are critical for calculating reserves and designing production facilities. We’ll explore their impact with real-world examples and compare values for light and heavy crudes, bringing the math to life with practical insights.

What Are Volume Factors?

Volume factors describe how the volume of oil ($B_o$), gas ($B_g$), or water ($B_w$) changes from reservoir conditions (high pressure and temperature) to standard surface conditions (14.7 $psia$, 60$^\circ$F). Think of them as conversion factors that help engineers translate what’s in the ground to what’s in the tank.

Definitions

• Oil Formation Volume Factor ($B_o$): The ratio of oil volume at reservoir conditions to its volume at standard conditions (stock tank barrels, STB). Units: $\text{bbl/STB}$.
• Gas Formation Volume Factor ($B_g$): The ratio of gas volume at reservoir conditions to its volume at standard conditions (standard cubic feet, SCF). Units: $\text{ft}^3/\text{SCF}$.
• Water Formation Volume Factor ($B_w$): The ratio of water volume at reservoir conditions to its volume at standard conditions. Units: $\text{bbl/STB}$.

Why Are They Important?

• Reserve Calculations: Volume factors convert in-place volumes to surface volumes, determining how much oil or gas is economically recoverable.
• Facility Design: They help size pipelines, separators, and storage tanks to handle the actual volumes produced.
• Production Optimization: Understanding volume changes ensures efficient flow from reservoir to surface.

Role in Reserve Calculations

Volume factors are central to estimating Original Oil in Place (OOIP) and Original Gas in Place (OGIP), which are the total hydrocarbons in a reservoir before production. The basic volumetric equation for oil is:

Where:

• $N$: Original oil in place ($\text{STB}$)
• $A$: Reservoir area ($\text{acres}$)
• $h$: Reservoir thickness ($\text{feet}$)
• $\phi$: Porosity (fraction)
• $S_o$: Oil saturation (fraction)
• $S_w$: Water saturation (fraction)
• $B_o$: Oil formation volume factor ($\text{bbl/STB}$)

For gas, the equation is similar:

Where:

• $G$: Original gas in place ($\text{SCF}$)
• $S_g$: Gas saturation (fraction)
• $B_g$: Gas formation volume factor ($\text{ft}^3/\text{SCF}$)

Example

In the Ghawar field (Saudi Arabia), a light crude reservoir has $B_o = 1.4 \, \text{bbl/STB}$, meaning 1.4 barrels of oil in the reservoir shrink to 1 barrel at the surface due to gas coming out of solution. If the reservoir has 1 billion barrels in place, the recoverable oil (after applying $B_o$) is:

This shows why $B_o$ is crucial for realistic reserve estimates.

Role in Facility Design

Volume factors guide the design of surface facilities like separators, pipelines, and storage tanks. For example:

• Separators: $B_o$ and $B_g$ determine how much gas separates from oil at surface conditions, affecting separator size and stage design.
• Pipelines: $B_g$ predicts gas expansion, ensuring pipelines are sized to handle high gas volumes without blockages.
• Storage: $B_w$ helps size tanks for produced water, critical in fields with high water cuts.

For instance, in the Permian Basin (USA), engineers use $B_g$ to design flowlines for shale gas, where gas expands significantly as pressure drops.

Typical Values for Light and Heavy Crudes

The value of volume factors depends on the fluid type (light vs. heavy crude) and reservoir conditions. Here’s a comparison:

• Light Crude (e.g., Brent, North Sea): Higher $B_o$ due to dissolved gas, which expands significantly at the surface. $B_g$ is lower because gas is less compressed in the reservoir.
• Heavy Crude (e.g., Orinoco Belt, Venezuela): Lower $B_o$ because heavy oil has less dissolved gas, and $B_g$ is higher due to lower gas solubility.

Math Insight: Calculating $B_g$

The gas formation volume factor is calculated as:

Where:

• $B_g$: Gas formation volume factor ($\text{ft}^3/\text{SCF}$)
• $z$: Gas compressibility factor (dimensionless)
• $T$: Temperature in Rankine ($\text{R} = ^\circ\text{F} + 459.67$)
• $P$: Pressure (psia)

For a gas reservoir at 3000 psia and 200$^\circ$F ($T = 660 \, \text{R}$) with $z = 0.9$, the $B_g$ is:

This means 0.01 cubic feet of gas in the reservoir becomes 1 $\text{SCF}$ at the surface, guiding pipeline sizing.

Putting It Into Practice

Imagine you’re a production engineer in the Permian Basin. Your reservoir has a light crude with $B_o = 1.5 \, \text{bbl/STB}$. You calculate OOIP as 500 million barrels, but after applying $B_o$, the surface volume is 333 million STB. Using this, you design a separator to handle the high gas content (from a low $B_g$) and size storage tanks for produced water ($B_w \approx 1.05$). In contrast, for a heavy crude field like Orinoco, you’d expect a lower $B_o$ and design facilities for viscous oil with minimal gas.

Summary

Volume factors ($B_o$, $B_g$, $B_w$) are essential PVT properties that translate reservoir volumes to surface conditions, driving accurate reserve calculations and efficient facility design. Light crudes have higher $B_o$ due to dissolved gas, while heavy crudes have lower $B_o$ and higher viscosity. By mastering these factors, production engineers ensure operations are optimized, from the Permian Basin’s shale plays to Ghawar’s carbonate reservoirs.

Questionnaire

1. What does the oil formation volume factor ($B_o$) represent?
   
   a) The volume of gas at reservoir conditions.
   
   b) The ratio of oil volume at reservoir conditions to surface conditions.
   
   c) The compressibility of water in the reservoir.
   
   Answer: b) The ratio of oil volume at reservoir conditions to surface conditions.

2. Why is $B_g$ important for pipeline design?
   
   a) It predicts how much gas expands from reservoir to surface.
   
   b) It calculates the reservoir’s porosity.
   
   c) It determines the water cut in production.
   
   Answer: a) It predicts how much gas expands from reservoir to surface.

3. How does $B_o$ typically differ between light and heavy crudes?
   
   a) Light crudes have a lower $B_o$ than heavy crudes.
   
   b) Light crudes have a higher $B_o$ due to more dissolved gas.
   
   c) Both have the same $B_o$ regardless of crude type.
   
   Answer: b) Light crudes have a higher $B_o$ due to more dissolved gas.

Bibliography

Sources Used

• Danesh, A. (1998). PVT and Phase Behavior of Petroleum Reservoir Fluids. Elsevier.
  Comprehensive resource on PVT properties and volume factors.
• Guo, B., Liu, X., & Tan, X. (2016). Petroleum Production Engineering: A Computer-Assisted Approach. Gulf Professional Publishing.
  Covers applications of volume factors in production.
• SPE Paper 19638 (1989). Correlations for Predicting Oil and Gas Properties. Society of Petroleum Engineers.
  Details empirical correlations for PVT properties.

Recommended Reading

• McCain, W. D. (2017). The Properties of Petroleum Fluids (3rd ed.). PennWell Books.
  In-depth guide to PVT properties and their applications.
• Economides, M. J., Hill, A. D., Ehlig-Economides, C., & Zhu, D. (2013). Petroleum Production Systems (2nd ed.). Prentice Hall.
  Practical insights into volume factors and facility design.

Direct Links

• SPE (Society of Petroleum Engineers) - Webinars and papers on PVT properties.
• PennWell Books - Source for McCain’s book.
• AAPG Resources - Educational content on petroleum engineering.