Natural gas composition and phase behavior

Three years after the Tamarack Lake waterflood became a pool-wide project, Prairie Crest Energy Inc. has made the largest acquisition in its history: a block of Marcellus rights in Pennsylvania, about 70 miles from Waynesburg. The company now calls the block the Ten Mile Ridge project. Four horizontal wells drilled by the previous owner have produced for two years into a third-party plant, and the plan is to build a company-owned gas plant, drill a long program of wells and sell the gas into the interstate pipeline network that supplies both East Coast markets and the Gulf Coast LNG terminals. Lena Haugen, now the vice-president of development, has put Ethan Cardinal on the new gas asset team. His lead is Farid Mansour, a senior gas engineer who spent fifteen years on deep gas and condensate fields before joining Prairie Crest. “Oil engineers think of gas as the stuff that comes out of solution,” Farid tells him on the first day. “Here gas is the product. Every decision starts with what the gas is made of and how it behaves when pressure and temperature change.”

This course follows the Ten Mile Ridge team from the first gas analysis to a field development plan. Along the way it covers gas properties, gas in place and material balance, water influx, deliverability, well testing, condensate reservoirs, tight and shale gas, gas processing, pipelines and compression. This first lesson sets out what natural gas is and how its phase behavior decides almost everything that follows.

What natural gas is

Natural gas is a mixture of light hydrocarbons, mostly methane, with smaller amounts of ethane, propane, butanes and heavier compounds, plus non-hydrocarbon gases. The common non-hydrocarbons are nitrogen, carbon dioxide, hydrogen sulfide, water vapor and, in some fields, helium. Each component matters for a different reason. Methane carries most of the heating value. Ethane, propane, butanes and pentanes plus are worth more as liquids than as fuel and are recovered as natural gas liquids, or NGLs. Nitrogen and carbon dioxide dilute the heating value and must be kept below pipeline limits. Hydrogen sulfide is lethal at low concentrations, corrosive and the reason sour gas plants exist. Water causes corrosion and hydrates and must be removed before the gas is sold.

Gas engineers describe composition in mole fractions, because the gas laws work with moles. A gas analysis from the laboratory lists each component's mole fraction, usually lumping everything heavier than hexane into a single heptanes-plus fraction, C7+, with a measured molar mass and specific gravity. Mei Lin, who has moved from the EOR laboratory to support the gas team, runs the analysis of a recombined sample from the Kessler 3H well: the separator gas and separator liquid were sampled at the same time and recombined in the laboratory at the measured producing ratio, so the analysis describes the fluid that actually leaves the reservoir.

Ethan notices that the analysis is richer than he expected for a gas well. More than 7 percent of the molecules are propane and heavier. That makes the Ten Mile Ridge gas a liquids-rich gas, and the liquids are a large part of its value. It also means the reservoir fluid might behave very differently from the dry methane that textbooks use as the example of an ideal gas.

Molar mass, gas gravity and pseudo-critical properties

Three numbers summarize a gas composition for most engineering work. The apparent molar mass is the mole-fraction-weighted average of the component molar masses. The gas specific gravity is that molar mass divided by the molar mass of air, 28.97 g/mol:

A methane-rich dry gas has a gravity near 0.56 to 0.6; a rich wet gas or gas condensate can reach 0.75 to 0.9 or more. The pseudo-critical temperature and pressure are the mole-fraction-weighted averages of the component critical properties, a mixing rule introduced by Kay in 1936. They are not the true critical point of the mixture, which must be measured or computed with an equation of state; they are simply the scaling factors that let one chart of z-factors serve all natural gases, as Lesson 2 explains.

When a gas contains carbon dioxide or hydrogen sulfide, Kay's rule gives z-factors that are too low, because acid gas molecules interact more strongly than hydrocarbons of similar size. Wichert and Aziz published a correction in 1972 that lowers both pseudo-critical properties by an amount that depends on the acid gas content. For the Ten Mile Ridge gas the correction is small, but for a gas with 10 or 20 percent acid gas, common in some deep carbonate reservoirs, it changes the z-factor by several percent.

# Molar mass, gas gravity, pseudo-critical properties and heating value of the Caribou Ridge separator gas.
SI = False     # True: metric units, False: oilfield units

h2s = 0.0020 if SI else 0.0      # the Canadian Montney gas is slightly sour; the Marcellus gas is sweet
# name: (mole fraction, molar mass g/mol, Tc K, pc kPa, gross heating value Btu/scf, liquid density lb/gal)
comp = {
    'N2':   (0.0080, 28.013, 126.2, 3394, 0.0, None),
    'CO2':  (0.0140 - h2s, 44.010, 304.1, 7374, 0.0, None),
    'H2S':  (h2s, 34.082, 373.5, 8963, 637.1, None),
    'C1':   (0.8170, 16.043, 190.6, 4599, 1010.0, None),
    'C2':   (0.0850, 30.070, 305.3, 4872, 1769.7, None),
    'C3':   (0.0350, 44.097, 369.8, 4248, 2516.1, 4.223),
    'iC4':  (0.0060, 58.123, 408.1, 3648, 3251.9, 4.686),
    'nC4':  (0.0100, 58.123, 425.1, 3796, 3262.3, 4.865),
    'iC5':  (0.0040, 72.150, 460.4, 3381, 4000.9, 5.199),
    'nC5':  (0.0040, 72.150, 469.7, 3370, 4008.9, 5.251),
    'C6':   (0.0040, 86.177, 507.6, 3025, 4755.9, 5.526),
    'C7+':  (0.0130, 115.0, 575.0, 2650, 6180.0, 5.92),
}
total = sum(v[0] for v in comp.values())
assert abs(total - 1) < 1e-9, total
M = sum(y * mw for y, mw, *_ in comp.values())
gg = M / 28.966
Tpc = sum(y * tc for y, _, tc, *_ in comp.values())
ppc = sum(y * pc for y, _, _, pc, *_ in comp.values())
# Wichert-Aziz correction for CO2 and H2S (temperatures in degrees Rankine, pressures in psia)
A = comp['CO2'][0] + comp['H2S'][0]; B = comp['H2S'][0]
eps = 120 * (A ** 0.9 - A ** 1.6) + 15 * (B ** 0.5 - B ** 4)        # deg R
TpcR, ppcpsi = Tpc * 1.8, ppc * 0.145038
TpcR2 = TpcR - eps
ppc2 = ppcpsi * TpcR2 / (TpcR + B * (1 - B) * eps)
hv = sum(y * h for y, _, _, _, h, _ in comp.values())         # Btu/scf, ideal gross
# liquid content of propane and heavier: US gallons per thousand standard cubic feet
gpm = sum(y * 1000 / 379.5 * mw / rho for k, (y, mw, _, _, _, rho) in comp.items() if rho)
print(f"Apparent molar mass {M:.2f} g/mol, gas gravity {gg:.3f}")
if SI:
    print(f"Kay pseudo-criticals: Tpc {Tpc:.1f} K, ppc {ppc:,.0f} kPa")
    print(f"Wichert-Aziz corrected: Tpc {TpcR2 / 1.8:.1f} K, ppc {ppc2 / 0.145038:,.0f} kPa (epsilon {eps / 1.8:.1f} K)")
    print(f"Gross heating value {hv * 0.037259:.1f} MJ/m3")
    print(f"C3+ liquid content {gpm * 0.0037854 / 28.317 * 1e6:.0f} m3 per 10^6 m3 (from {gpm:.2f} US gal/Mscf)")
else:
    print(f"Kay pseudo-criticals: Tpc {TpcR:.1f} deg R, ppc {ppcpsi:,.0f} psia")
    print(f"Wichert-Aziz corrected: Tpc {TpcR2:.1f} deg R, ppc {ppc2:,.0f} psia (epsilon {eps:.1f} deg R)")
    print(f"Gross heating value {hv:,.0f} Btu/scf")
    print(f"C3+ liquid content {gpm:.2f} gal/Mscf")

Apparent molar mass 21.39 g/mol, gas gravity 0.739
Kay pseudo-criticals: Tpc 395.7 deg R, ppc 665 psia
Wichert-Aziz corrected: Tpc 393.2 deg R, ppc 661 psia (epsilon 2.4 deg R)
Gross heating value 1,247 Btu/scf
C3+ liquid content 2.59 gal/Mscf

The well stream has a molar mass of about 21.4 g/mol and a gravity of 0.74. Its gross heating value is about 1,250 Btu/scf, far above the roughly 1,000 to 1,050 Btu/scf of pipeline gas, because the heavier components carry more energy per molecule. That high heating value is a sign of liquids the gas plant will recover. The last line of the output is the propane-plus liquid content, which gas processors call the GPM: gallons of liquid per thousand standard cubic feet. At about 2.6 US gallons per thousand cubic feet, or roughly 350 m³ of liquid per million cubic meters of gas, the Ten Mile Ridge gas is rich enough for a deep-cut NGL plant to pay for itself.

Standard conditions

Gas volumes are always quoted at standard conditions, because a cubic meter of gas at reservoir pressure contains hundreds of standard cubic meters. In Canada the usual standard is 15 °C and 101.325 kPa; in the United States it is 60 °F and 14.696 psia for most purposes, with 14.73 psia in many gas contracts. The two are close but not identical, so a careful engineer always checks which base a volume uses. Gas is also sold by energy, in gigajoules in Canada and in million British thermal units in the United States, so the heating value links the volume a well produces to the money it earns.

Phase behavior of a pure substance and a mixture

A pure substance such as methane has a single vapor pressure curve that ends at the critical point. Below the curve it is a gas; above it, a liquid; on the curve, both phases coexist. Above the critical temperature no amount of compression produces a separate liquid. A mixture behaves differently. Instead of a single curve, it has a phase envelope: a region in pressure-temperature space inside which two phases coexist. The upper-left boundary is the bubble point curve, where the first bubble of gas appears in a liquid. The right-hand boundary is the dew point curve, where the first drop of liquid appears in a gas. The two meet at the critical point. The highest pressure on the envelope is the cricondenbar and the highest temperature is the cricondentherm.

The shape of the envelope depends on composition. A gas made almost entirely of methane has a small envelope at low temperatures. Adding heavier components stretches the envelope to the right and upward, because heavier molecules condense at higher temperatures. A rich gas condensate can have a cricondentherm well above reservoir temperature, so its dew point curve passes through the reservoir's temperature at a high pressure.

The five reservoir fluid types

McCain's classification, used throughout the industry, sorts reservoir fluids into five types by where the reservoir and the separator sit relative to the phase envelope. Black oils and volatile oils have critical temperatures above reservoir temperature, so they are liquids in the reservoir; they were the subject of the oil courses. The three gas types have critical temperatures below reservoir temperature.

A dry gas lies entirely to the right of its envelope at both reservoir and separator conditions. No liquid forms anywhere in the production system, and the gas produces only some water. Dry gas is mostly methane, with a gravity around 0.55 to 0.6. A wet gas lies to the right of its envelope at reservoir conditions, so no liquid forms in the reservoir, but the separator sits inside the envelope and some liquid condenses at the surface. Wet gases produce a light liquid, often colorless, at condensate-gas ratios of a few to perhaps 20 barrels per million standard cubic feet. A gas condensate, or retrograde gas, has a critical temperature below reservoir temperature but a cricondentherm above it. As reservoir pressure falls below the dew point, liquid condenses in the reservoir itself. That liquid is mostly lost, because it rarely reaches a saturation high enough to flow. Gas condensates have initial condensate-gas ratios from about 20 to more than 200 barrels per million standard cubic feet.

The table's boundaries are rules of thumb, not physical limits. A fluid near a boundary must be tested in the laboratory to decide whether it has a dew point or a bubble point at reservoir conditions. Farid's first question about the Kessler 3H analysis is exactly that. With an initial condensate yield near 45 barrels per million standard cubic feet, the fluid is probably a gas condensate. If so, the reservoir will begin to drop liquid as soon as its pressure falls below the dew point, and the development plan must account for that lost liquid. Lesson 7 returns to this with the laboratory's constant-volume depletion test.

Why phase behavior drives the whole project

The fluid type decides the engineering choices downstream. For a dry gas, the reservoir engineer can work with a single-phase gas from reservoir to sales line, and the plant needs only to remove water and perhaps acid gas. For a wet gas, the reservoir is still single-phase, but the surface facilities must separate, stabilize and sell a liquid, and gas-in-place calculations must use the well-stream gravity, not the separator gas gravity. For a gas condensate, the reservoir itself becomes two-phase below the dew point. Liquid builds up around the wellbore, lowering gas productivity, and the most valuable components are left behind unless pressure is kept above the dew point by cycling dry gas back into the reservoir.

Composition also decides the processing. Hydrogen sulfide means an amine unit, a sulfur recovery unit, special metallurgy, emergency planning zones and stricter regulation under federal and state rules for sour gas, although the Marcellus gas is sweet. High propane-plus content means an NGL recovery plant and a market for the liquids. Water content decides dehydration and hydrate prevention. Carbon dioxide may need removal to meet the pipeline's limit, typically 2 mole percent, and nitrogen above a few percent may need rejection to meet heating value limits. Farid sums it up for Ethan: “The analysis is the cheapest piece of data we will ever get, and it decides half the capital cost.”

Sampling therefore deserves care. A gas sample must represent the reservoir fluid, which means sampling early, before the reservoir pressure falls below the dew point; flowing the well at a low, stable rate so that liquid does not drop out near the wellbore; and recording the separator pressure, temperature and the gas and liquid rates so that the laboratory can recombine the samples at the right ratio. A gas condensate sampled after the near-well pressure has fallen below the dew point is leaner than the true reservoir fluid, because some of the heavy ends have stayed behind in the rock. Ethan learns that the Kessler 3H samples were taken in the first month of production at a choked-back rate, and that two other wells were sampled for comparison; the three analyses agree within the expected scatter.