Study Guide for Petroleum Gas Technology: Water-Hydrocarbon Phase Behavior

Course and Institutional Context

• Institution: Koya University, Faculty of Engineering.
• Department: Chemical Engineering Department.
• Level/Semester: Level 2, 4th Semester.
• Academic Year: 2024–2025.
• Subject: Petroleum Gas Technology.
• Topic: Topic 3: Water hydrocarbon phase behavior systems (Part A).
• Instructor: Mr. Ribwar K. Abdulrahman, Msc. Natural Gas Processing Engineering, UK.

Fundamental Concepts of Water-Hydrocarbon Systems

• Natural Occurrence: Almost all natural gas contains substantial amounts of water vapor. This is primarily due to the presence of connate water within the reservoir rock.
• Saturation State: At the specific pressure and temperature of the reservoir, natural gas is saturated with water vapor.
• Necessity of Removal: Separating water from the gas stream is required to meet sales specifications and prevent operational issues.
• Separation Mechanisms: Liquid water is typically removed through gas-liquid and liquid-liquid separation processes.
• Equilibrium Behavior:     - Hydrocarbons and water are considered "natural followers" as hydrocarbons form in aqueous environments and exist in equilibrium with water under reservoir conditions.     - In the liquid phase, water and hydrocarbons are essentially immiscible.     - Their mutual solubility is extremely low; for example, at $25\,^{\circ}\text{C}$ and atmospheric pressure, the mole fraction of a paraffin such as n-pentane in water is approximately $10^{-5}$.     - While this slight solubility has no measurable effect on vapor-liquid equilibrium (VLE) behavior, it is critically important for predicting the formation of hydrates.
• Phase Distribution: If liquid water, liquid hydrocarbons, and gas are all present in a system, there will be two distinct liquid phases.
• Vapor Phase Composition: The quantity of water vapor in the gas phase is determined by the overall gas composition and the vapor pressure of the liquid water phase.

Determination and Calculation of Water Content

• Primary Objectives: There are two primary calculations required for water hydrocarbon systems:     1. Calculation of the water content of the gas stream.     2. Prediction of the specific conditions (pressure and temperature) under which hydrates will form.
• Water Holding Capacity Factors: The capacity of a gas stream to hold water vapor is a function of:     - Gas composition.     - Pressure of the gas.     - Temperature of the gas.
• Behavior during Compression/Cooling: The capacity to hold water is reduced as the gas stream is compressed or cooled.
• Dew Point and Saturation:     - A gas is "saturated" or at its "dew point" when it has reached the physical limit of its water-holding capacity for a specific pressure and temperature.     - Any water added beyond this point cannot vaporize and will instead drop out as "free liquid."     - If pressure increases or temperature decreases from the saturation point, more water vapor will condense and precipitate.
• Methods for Determining Water Content:     1. Partial pressure and partial fugacity relationships.     2. Empirical plots illustrating water content versus pressure ($P$) and temperature ($T$).     3. Corrections applied to empirical plots for contaminants such as hydrogen sulfide ($H_2S$), carbon dioxide ($CO_2$), and nitrogen ($N_2$).     4. Pressure Volume Temperature (PVT) equations of state.

Pressure and Fugacity Relationships

• Ideal Conditions (Raoult's Law): For water in a gas stream, Raoult's law can be applied. Due to the immiscibility of liquid phases, the liquid mole fraction ($x_w$) is taken as unity ($1.0$).
• Equation 6.1 (Simplified Vapor Phase Mole Fraction): Given a known total pressure and water vapor pressure, the mole fraction of water in the vapor phase can be determined.
• Range of Validity: This method is valid only at low pressures where the ideal gas law applies. It is recommended for system pressures up to $60\,\text{psia}$ ($4\,\text{barg}$).

Empirical Evaluation of Water Content

• Historical Context: Until the early 1950s, natural gas was primarily processed for heavier compounds and contaminants in NGL units. For "lean sweet" natural gas, the log of water content ($W$) was plotted against pressure and temperature.
• Linear Approximations: It was found that plotting $\ln(W)$ versus $\frac{1}{T}$ yields an approximate straight line at a constant pressure.
• Standard Plot Types (Figure 6.1): Most contemporary plots use $\ln(W)$ versus $T$.
• Interpretation of Figure 6.1:     - The water content shown represents the maximum the gas can hold (full saturation).     - This correlates to $100\%$ relative humidity.     - The temperature on the plot corresponds to the water dew point temperature for the given pressure and concentration.
• Concentration Calculations: The concentration in mass per unit standard volume is related to the mole fraction ($y$).

Case Study: Mansuriya Gas Field (Example 1)

• Context: Raw natural gas production investment.
• Gas Composition Data:     - $H_2S$: $0.003\text{ mole}\%$     - $CO_2$: $0.4\text{ mole}\%$     - $C_1$: $83.0\text{ mole}\%$     - $C_2$: $7.7\text{ mole}\%$     - $C_3$: $5.0\text{ mole}\%$     - $iC_4$: $1.8\text{ mole}\%$     - $nC_4$: $1.3\text{ mole}\%$     - $C_5+$: $0.797\text{ mole}\%$
• Operating Conditions/Field Data:     - Flow rate: $2400\,\text{std. m}^3/\text{hr}$     - Pressure: $8400\,\text{kPa}$     - Temperature: $38\,^{\circ}\text{C}$     - Gas SG (relative to Air): $0.6$     - Gas Density: $0.65\,\text{Km}$
• Calculation Requirements: Determine water content using empirical plots and the Equation method (Sour gas method).
• Conversions and Physical Constants:     - $1\,\text{kPa} = 0.001\,\text{MPa}$     - $1\,\text{bar} = 100\,\text{kPa}$     - Gas Standard Volume: $22.414\,\text{m}^3/\text{Kmol}$     - R.N.G Flow Rate: $107.0759347\,\text{kmol/hr}$
• Results derived from Figure 6.1:     - Value found: $800\,\text{kg}/10^6\,\text{std. m}^3$     - Total water content per hour: $\frac{800\text{ kg}}{10^6\text{ std. m}^3} \times 2400\text{ std. m}^3/\text{h} = 1.92\,\text{kg/hr}$

Gas Hydrates: Characteristics and Formation

• Definition: Gas hydrates are crystalline, ice-like solids composed of water and specific low molecular weight "guest" molecules.
• Common Guest Molecules: Methane ($CH_4$), Ethane ($C_2H_6$), Propane ($C_3H_8$), Hydrogen Sulphide ($H_2S$), and Carbon Dioxide ($CO_2$).
• Common Combinations:     - Water, methane, and propane.     - Water, methane, and ethane.
• Physical Appearance: Resembles wet, slushy snow initially. When trapped in restrictions or subjected to differential pressure, they become very solid, analogous to compacting a snowball.
• Impact on Operations:     - Accumulate at restrictions like flowlines, chokes, valves, and instrumentation.     - Accumulate in liquid collection sections of vessels.     - Cause plugging and reduction of line capacity.     - Inflict physical damage to chokes and instrumentation.     - Create separation problems.
• Required Conditions for Formation:     1. Correct Pressure and Temperature.     2. Presence of "free water" (the gas must be at or below its water dew point). Hydrates cannot form without free water.
• Structural Classification: Hydrates are "clathrates." Water molecules form a hydrogen-bonded cage structure stabilized by the guest molecules.
• Structure Types: There are three known structures: Structure I, II, and H.
• Essential Formation Elements:     1. Supply of guest molecules ($N_2, CO_2, H_2S, CH_4, C_2H_6$, etc.).     2. Sufficient Water.     3. Low Temperature.     4. High Pressure.

Hydrate Control and Remediation

• Pressure Control: Operating the system at pressures low enough to stay outside the hydrate envelope. Often impractical for transportation due to high pressure requirements.
• Temperature Control: Keeping temperatures high via passive insulation or active heating (e.g., Direct Electrical Heating - DEH).
• Water Removal: Preventing formation by removing the water supply through separation and dehydration; common for sales gas exports.
• Chemical Inhibition: Injecting chemical inhibitors into the gas stream.

Hydrate Prediction Methodologies

• Pressure-Temperature (P-T) Curves: Used as a "first approximation" or when precise gas composition is unknown. These approximate the formation temperature based on gas gravity and pressure.
• Example (P-T Curve): For a $0.6$ specific gravity gas at $2000\,\text{psia}$, the hydrate formation temperature is read as $68\,^{\circ}\text{F}$.
• McLeod–Campbell Method: A calculation-based approach for predicting formation temperatures.
• McLeod–Campbell Example Calculation:     - Given Conditions: Gas at $41.4\,\text{MPa}$ ($6000\,\text{psia}$).     - Composition Analysis:         - $C_1$: $0.906\text{ mol fr.} \rightarrow C' = 17153$         - $C_2$: $0.066\text{ mol fr.} \rightarrow C' = 1373$         - $C_3$: $0.018\text{ mol fr.} \rightarrow C' = 511$         - $iC_4$: $0.005\text{ mol fr.} \rightarrow C' = 153$         - $nC_4$: $0.005\text{ mol fr.} \rightarrow C' = 87$         - Total Combined Constant ($C$): $19277$     - Temperature Calculation (SI):         - $T = 2.16 \times (19277)^{0.5} = 300\,\text{K}$         - $T = 27\,^{\circ}\text{C}$     - Temperature Calculation (Field Units):         - $T = 3.89 \times (19277)^{0.5} = 540\,^{\circ}\text{R}$         - $T = 80\,^{\circ}\text{F}$"