Gas sweetening and NGL recovery

The A-12-3 analysis showed 0.2 percent hydrogen sulphide, 2,000 parts per million, and 1.2 percent carbon dioxide. That makes the Caribou Ridge gas sour, and the Caribou Ridge gas plant must remove the hydrogen sulphide almost completely before the gas can be sold. It must also decide what to do with the sulphur. At the same time, the gas carries about 7 percent propane and heavier and 8.5 percent ethane, liquids worth far more than the gas they ride in. Gwen lays out the second half of the plant for the team: the amine unit, the sulphur recovery unit and the deep-cut NGL train. “Sour gas is a safety problem first and a chemistry problem second,” she says. “Liquids are where the plant earns its keep.”

Acid gases and why they come out

Hydrogen sulphide is toxic, corrosive and odorous. At low concentrations it smells of rotten eggs, but at higher concentrations it paralyzes the sense of smell, and exposure to a few hundred parts per million can be fatal within minutes. Sour gas facilities therefore have gas detection, breathing apparatus, emergency shutdown systems, emergency planning zones around wells and pipelines, and materials resistant to sulphide stress cracking, specified to NACE MR0175/ISO 15156. Carbon dioxide is not toxic at pipeline concentrations but forms carbonic acid with water, which corrodes carbon steel, and it dilutes the heating value. Pipelines limit hydrogen sulphide to a few parts per million and carbon dioxide to about 2 percent. LNG plants need carbon dioxide below about 50 ppm, because it would freeze at liquefaction temperatures.

Amine treating

Most acid gas is removed by chemical absorption in aqueous alkanolamine solutions. The amine reacts reversibly with hydrogen sulphide and carbon dioxide: the reaction runs forward at the high pressure and moderate temperature of the absorber and backward at the low pressure and high temperature of the regenerator. Sour gas flows up through the absorber against lean amine; sweet gas leaves the top. The rich amine is flashed to release dissolved hydrocarbons, heated in a lean-rich exchanger and stripped with steam from a reboiler in the regenerator, which releases the acid gas at the top. The lean amine is cooled and pumped back.

The choice of amine sets much of the design. Monoethanolamine (MEA) is the most reactive and removes both acid gases, but it is corrosive and limited to low concentrations and loadings. Diethanolamine (DEA) is less reactive and less corrosive. Methyldiethanolamine (MDEA), a tertiary amine, reacts quickly with hydrogen sulphide but only slowly with carbon dioxide, so a short-contact absorber can remove hydrogen sulphide selectively and let much of the carbon dioxide slip into the sales gas. That selectivity reduces circulation and energy and concentrates hydrogen sulphide in the acid gas, which helps the sulphur plant. Activated MDEA, with a piperazine promoter, is used when deep carbon dioxide removal is needed, as for LNG feed. Physical solvents and membranes suit very high acid gas partial pressures.

A first estimate of the circulation rate follows from stoichiometry. The moles of acid gas to remove per day, divided by the net loading of the amine, in moles of acid gas picked up per mole of amine, give the moles of amine to circulate; the solution strength and density convert that to a volume. Net loadings of 0.3 to 0.45 mol/mol are typical for MDEA. Reboiler duty, the main operating cost, scales roughly with the circulation rate.

# Amine sweetening, sulphur recovery and NGL recovery for a 150 MMscf/d (about 4.2 x 10^6 m3/d) plant.
SI = True      # True: metric units, False: oilfield units

Q = 150e6                                     # plant inlet gas, scf/d
h2s = 0.0020 if SI else 0.0                   # sour Montney gas (Canada) / sweet Marcellus gas (US)
co2 = 0.0140 - h2s
lbmol = Q / 379.5                             # lb-mol of gas per day
# MDEA unit removing all H2S and enough CO2 to meet 2 mol% (pipeline) or 50 ppm (LNG feed)
for label, co2_out in (("pipeline spec, 2 mol% CO2", 0.02), ("LNG feed spec, 50 ppm CO2", 50e-6)):
    ag = lbmol * (h2s + max(co2 - co2_out, 0.0))   # lb-mol acid gas picked up per day
    if ag == 0:
        print(f"{label}: no CO2 removal needed" + ("; H2S must still come out" if h2s else ""))
        if not h2s: continue
        ag = lbmol * h2s
    amine = ag / 0.35                         # lb-mol MDEA at a net loading of 0.35 mol acid gas per mol amine
    sol = amine * 119.16 / 0.50               # lb/d of 50 wt% solution
    gpm = sol / 8.67 / 1440                   # US gal/min at 8.67 lb/gal
    print(f"{label}: acid gas {ag * 0.4536:,.0f} kmol/d, MDEA solution {gpm * 0.2271:,.0f} m3/h" if SI else
          f"{label}: acid gas {ag:,.0f} lb-mol/d, MDEA solution {gpm:,.0f} gal/min")
if h2s:
    S = lbmol * h2s * 32.06 * 0.985 * 0.4536 / 1000    # tonnes/d of sulphur at 98.5 percent recovery
    print(f"Claus sulphur recovery: {S:.1f} tonnes/d of sulphur; {lbmol * h2s * 0.015 * 0.4536:.2f} kmol/d of H2S equivalent to the incinerator")

# NGL recovery in a turboexpander plant: (component, mole fraction, molar mass, liquid density lb/gal, recovery)
ngl = [('C2', 0.0850, 30.070, 2.970, 0.85), ('C3', 0.0350, 44.097, 4.223, 0.98), ('iC4', 0.0060, 58.123, 4.686, 0.995),
       ('nC4', 0.0100, 58.123, 4.865, 0.998), ('C5+', 0.0250, 96.0, 5.60, 1.0)]
tot_gal = 0.0; tot_mol = 0.0
for name, y, mw, rho, rec in ngl:
    gal = lbmol * y * rec * mw / rho          # US gallons per day of liquid product
    tot_gal += gal; tot_mol += lbmol * y * rec
    print(f"  {name:4s} {gal * 0.0037854:8,.0f} m3/d" if SI else f"  {name:4s} {gal / 42:8,.0f} bbl/d")
print(f"Total NGL {tot_gal * 0.0037854:,.0f} m3/d" if SI else f"Total NGL {tot_gal / 42:,.0f} bbl/d")
print(f"Shrinkage of the gas stream by liquids removal: {tot_mol / lbmol:.1%}")

pipeline spec, 2 mol% CO2: acid gas 359 kmol/d, MDEA solution 10 m3/h
LNG feed spec, 50 ppm CO2: acid gas 2,501 kmol/d, MDEA solution 68 m3/h
Claus sulphur recovery: 11.3 tonnes/d of sulphur; 5.38 kmol/d of H2S equivalent to the incinerator
  C2      1,094 m3/d
  C3        536 m3/d
  iC4       111 m3/d
  nC4       178 m3/d
  C5+       641 m3/d
Total NGL 2,561 m3/d
Shrinkage of the gas stream by liquids removal: 14.8%

For the plant's 4.25 × 10⁶ m³/d (150 MMscf/d), meeting the pipeline specification only requires removing the hydrogen sulphide, because the carbon dioxide is already below 2 percent. A selective MDEA unit picks up about 360 kmol/d of acid gas with roughly 10 m³/h of 50 weight percent MDEA. Treating to LNG feed quality would multiply the circulation sevenfold. The Claus plant downstream would make about 11 tonnes of sulphur per day.

Sulphur recovery and acid gas disposal

The acid gas from the regenerator of a sour plant is mostly hydrogen sulphide and carbon dioxide with some water and hydrocarbons. It cannot be vented. The Claus process converts hydrogen sulphide to elemental sulphur in two steps. In the thermal stage, a furnace burns one-third of the hydrogen sulphide to sulphur dioxide; in two or three catalytic stages, the remaining hydrogen sulphide reacts with the sulphur dioxide over alumina or titania catalyst to form sulphur, which is condensed between stages:

A modified Claus unit with three catalytic stages recovers about 96 to 98 percent of the sulphur. Tail gas treating units, which convert the remaining sulphur compounds back to hydrogen sulphide and recycle them, raise overall recovery to 99.8 percent or more. Regulators set minimum recovery levels that rise with plant size, and the tail gas is incinerated before release, so sulphur dioxide emissions are monitored. The liquid sulphur is degassed, formed into prills or blocks and sold, mostly for fertilizer manufacture.

For smaller sour plants, especially where sulphur markets are poor, acid gas injection is an alternative: the acid gas is compressed, dehydrated and injected into a deep saline aquifer or depleted reservoir. Western Canada has many acid gas injection schemes, operating since the late 1980s, and the experience gained has informed carbon capture and storage projects. For the Caribou Ridge gas plant, the team compares a Claus unit with acid gas injection into a depleted reef below the Montney; the injection option avoids a sulphur product but needs a disposal approval from the BCER and a well that can handle sour service.

NGL recovery

Natural gas liquids are recovered by cooling the gas until the heavier components condense. The deeper the cooling, the more ethane and propane are recovered. Three main processes are used. Refrigeration plants chill the gas with propane refrigerant to about −30 °C (−20 °F), enough to meet the hydrocarbon dew point and recover much of the butanes and heavier but only part of the propane. Lean oil absorption, once common, has been largely replaced. Cryogenic turboexpander plants, the modern standard for rich gas, cool the dry, treated gas against cold residue gas in a brazed aluminium exchanger, then expand it through a turboexpander. The expander does work on a compressor wheel as the gas expands, which cools the gas much more than a simple valve would, to about −90 to −100 °C (−130 to −150 °F). The cold gas and liquids feed a demethanizer column, which sends methane overhead as residue gas and recovers 80 to 95 percent of the ethane and nearly all the propane and heavier in its bottoms.

The NGL stream, often called Y-grade, is either sold as a mixture or fractionated into ethane, propane, butanes and natural gasoline in a series of columns: a deethanizer, a depropanizer and a debutanizer. Ethane recovery is a commercial choice made month by month in many plants. When ethane is worth more as a petrochemical feedstock than as fuel in the gas stream, the plant recovers it; when it is not, the plant runs in ethane rejection and leaves most of the ethane in the residue gas, which raises the gas's heating value. In Alberta, ethane feeds the province's ethylene crackers, and plants in the Montney supply part of that market through the Alberta gathering and extraction system.

Removing liquids shrinks the gas. The code shows that recovering 85 percent of the ethane and all the heavier components from the Caribou Ridge gas removes about 15 percent of the molecules, which the residue gas sales volume must reflect. Fuel for compressors and heaters takes another few percent. The plant also lowers the heating value of the residue gas, from about 46.5 to 39 MJ/m³ (1,250 to 1,050 Btu/scf), bringing it within the pipeline's heating value range.

Product specifications and markets

Each NGL product has its own specification. Propane sold as fuel (HD-5 grade) limits ethane, butanes, sulphur and water. Ethane for crackers limits methane and carbon dioxide. Condensate and natural gasoline are specified by vapour pressure, so they are stabilized to a Reid vapour pressure that allows safe storage. The plant design balances recoveries against the market for each product and the cost of transporting it, by pipeline, rail or truck. Prairie Crest's marketing group will sign the NGL and condensate contracts before the plant is sanctioned, because the liquids revenue is as large as the gas revenue in the early years.