TECHNOLOGY Acid gas injection eliminates sulfur recovery expense

April 28, 1997
Edward Wichert Gascan Resources Ltd. Calgary Tom Royan Tartan Engineering Corp. Ltd. Calgary Because sulfur recovery from produced gas has little value at this time, an alternative is to compress the acid gas (H2S, CO2, or a mixture of both) and inject it into a suitable underground zone, similar to produced water disposal. Sour natural gas containing sulfur in the form of hydrogen sulfide (H2 S) presents a double cost to producers. First, the gas has to be sweetened with a solvent, and second,
Edward Wichert
Gascan Resources Ltd.
Calgary

Tom Royan
Tartan Engineering Corp. Ltd.
Calgary

Because sulfur recovery from produced gas has little value at this time, an alternative is to compress the acid gas (H2S, CO2, or a mixture of both) and inject it into a suitable underground zone, similar to produced water disposal.

Sour natural gas containing sulfur in the form of hydrogen sulfide (H2 S) presents a double cost to producers. First, the gas has to be sweetened with a solvent, and second, most of the H2 S has to be converted to sulfur. Both processes are expensive.

Acid gas reinjection eliminates sulfur compounds and carbon dioxide (CO2) emissions into the atmosphere. This compression and injection process has been rapidly developed and adopted in Western Canada for handling acid gas streams from sour gas sweetening facilities.

Acid gas mixtures

Raw sour natural gas mixtures present a greater potential for causing problems than sweet natural gas. These problems arise mainly in two areas: increased potential for corrosion and increased propensity for hydrate formation at elevated pressures.

Therefore, it is assumed that acid gas, H2 S and CO2 with little or no hydrocarbon content, will further exacerbate these two problems. In fact, this may not be the case.

Corrosion

Sour gas corrosion of low-alloy steel occurs mainly in the presence of a liquid aqueous phase. The corrosion manifests itself as general metal loss corrosion or pitting corrosion. When these occur, atomic hydrogen is generated. Because atomic hydrogen can penetrate steel, this could lead to hydrogen-induced cracking, blistering, or sulfide stress cracking, resulting in sudden failures.

By following the NACE MR0175 standard in materials selection and adhering to recommended construction practices, one can usually avoid such failures. Sour or acid gas dehydration effectively eliminates corrosion by H2 S or CO2 .

Water vapor, hydrates

At a given pressure, the hydrate-forming temperature of sour gas increases with increasing H2 S content. The equilibrium water vapor content of natural gas decreases with increasing pressure at constant temperature.

Similarly, in their pure state, both H2 S and CO2 hold less water in the vapor phase as the pressure is increased to about 5,000 kPa (725 psi). Above 5,000 kPa, water saturation increases with increasing pressure at a constant temperature.1

It is reasonable to assume that H2 S and CO2 mixtures behave similar to their pure states, and therefore the acid gas mixture will also have a minimum water content at about 5,000 kPa. Thus, by separating the condensed water between 3,000 and 5,000 kPa and at a temperature a few degrees above the hydrate temperature, no condensed water would be present when acid gas is compressed to higher pressures and cooled to ambient temperatures.

At such elevated pressures, the acid gas mixture would be in the liquid or supercritical (dense) phase at normal flow line temperatures. Therefore, there may not be a need for dehydration, because the acid gas mixture would be undersaturated in water.

Without condensable water present, hydrates would not occur in the liquid or dense phase of the acid gas mixture, and corrosion would also be at a minimum.

Disposal zone

Many factors influence the selection of a suitable injection zone within a reasonable and economic distance from the compressor location.2 In acid gas compression and injection, the drilling of an acid gas disposal well is a major expense.

The first task is to check to see if a well is near the sour gas plant. A suitable injection zone could be a large aquifer, a depleted reservoir, or a zone producing sour fluids.

A depleted zone is particularly attractive because the main reservior parameters, namely size and original pressure, are known. Thus, one can easily estimate how much gas can safely be injected.

Later, if the sulfur price increases to profitable levels, the acid gas could be produced back.

If no suitable depleted zone or large aquifer is readily available near the sour gas plant, then disposal into a producing horizon is feasible because the amount of gas returned to the zone is usually a small fraction of the total gas in place.

In this regard, the disposal well could be drilled near the plant, thereby eliminating a long injection flow line.

Compression, dehydration

Acid gas is liberated from the sweetening solvent in the regenerator tower. Upon cooling and separating from the condensed liquids in the reflux drum, the acid gas mixture is at a pressure of 80-100 kPa, and at a temperature between 15° C. in winter and up to 40° C. in summer.

This stream would normally be sent either to a flare stack, if the sulfur content is very low, or to a sulfur-recovery unit.

If the acid gas contains more than about 60% CO2, which is usually the case with small amounts of sulfur in the sour natural gas, then a modified Claus plant may not be the best choice for small-scale sulfur recovery, and instead a redox unit could be selected for converting H2S to sulfur. However, redox processes are expensive to install, difficult to operate, and the resulting sulfur product does not meet sulfur purity specifications.

In such situations, the best solution may be to compress the acid gas stream for disposal into an underground formation.

Discharge pressure

The maximum pressure to which acid gas has to be compressed depends on the reservoir pressure, permeability, and depth.

If the acid gas mixture is compressed to about 6,000 kPa and cooled below 20° C., the mixture will be in the liquid phase, provided the methane content is no greater than 1-2%. The liquid acid gas mixture density will be about 70-80% of the water density as it enters the injection well.

Thus, the injection pressure into the reservoir will be aided by the acid gas density in the liquid state, and the injection rate will generally be low.

A rate of 1 bbl/min of liquid CO2 injection amounts to 3.6 MMscfd of gaseous CO2 at standard pressure and temperature. Thus, the wellhead injection pressure would generally be about 6,000-9,000 kPa, and would depend largely on the reservoir injectivity as well as reservoir pressure and depth.

A four-stage compressor can achieve pressures of 6,000-9,000 kPa.

Metallurgy

Because compression increases temperature, the cylinders are compressing gas that is at its water dewpoint on the suction side, and undersaturated in the compressor cylinder and on the discharge side. Thus, carbon steel meeting NACE MR0175 standard requirements for sour gas should be installed as a minimum. The line to the aerial cooler can be carbon steel meeting the NACE standard.

In the interstage coolers, water will condense, and could pose a corrosion problem. The coolers, the lines to the interstage scrubbers, and the scrubbers themselves will be exposed to the corrosive acid gas and condensed water mixture. The coolers, lines, and interstage scrubbers should be 316 stainless steel.

After the third compression stage, the pressure will be about 3,000-4,000 kPa. This is the final stage at which water will condense in the cooler.

Boosting the pressure substantially above 6,000 kPa will increase the capacity of the acid gas mixture for holding more water in solution than at the previous separation stage. Upon cooling after the fourth compression stage, there should theoretically be no water of condensation dropping out.

The downstream facilities could be constructed from carbon steel meeting NACE specifications.

Dehydration

As mentioned previously, under certain pressure and temperature conditions, no water of condensation would occur after the final compression stage.

The chemical and petroleum engineering department at the University of Calgary has a research project ongoing on the water content of acid gas mixtures at elevated pressures in the gaseous and liquid phases. In due course, this information will allow engineers to properly design acid gas compression and injection facilities so that dehydration of the acid gas mixtures may in many cases not be necessary.

If one chooses dehydration to ensure that no water of condensation drops out at the high pressures, dehydration should be after the second or third compression stage.

The absorbed acid gas in the glycol can be largely liberated by incorporating a flash tank through which the rich glycol would flow prior to entering the regeneration column. The flash vapors can be routed to first-stage suction.

One problem with glycol dehydration of gas in general and with acid gas in particular is reboiler off-gas disposal. There is considerable environmental concern with emitting off-gas to the atmosphere.

In acid gas dehydration with glycol, this off-gas would have to be collected and incinerated or cooled and recompressed into the acid gas stream.

Injection facilities

Acid gas injection facilities beyond the final compression stage and cooling consist of an injection line, well site control facilities, and an injection well.

Disposal line

Selection of material for the acid gas injection line between the plant and the injection well is generally related to whether or not the acid gas has been dehydrated.

For dehydrated gas, sour service carbon steel materials could be used, such as CSA-Z662 Grade 359 Category II sour-service material. Addition of corrosion inhibitor should also be considered.

For nondehydrated acid gas, the line can be carbon steel or 316L stainless steel. One key consideration is line length. Stainless steel is more expensive, and if the line cost exceeds the dehydration unit cost, then it may be more economical to dehydrate the acid gas stream.

The proposed line should be fully evaluated with the material vendor to ensure full compatibility with anticipated process conditions of pressure, temperature, and acid gas composition.

The line diameter should be sized for liquid phase fluids if the acid gas mixture contains no more than about 2% hydrocarbons. This means that the injection rates would be quite low in terms of liquid quantities.

An injection rate of 1 MMscfd of CO2 reduces to 11.8 gpm in the liquid phase. The pressure drop in a short, 50-mm (2 in.) diameter line would be small because even 4 MMscfd of acid gas would amount to only about 1 bbl/min of liquid injection.

Well site facilities

At the well site, the facilities can be very simple. A meter could be installed to record flow. This would provide information to the plant supervisory control and data acquisition (scada) system concerning the injection pressure, temperature, rate, and fluid density.

The wellhead would be equipped with a check valve as well as an emergency shutdown (ESD) valve.

Injection well

The ideal acid gas injection well would be a well drilled for this purpose within 200 m of the plant perimeter. The considerations for selecting the disposal zone were previously briefly mentioned.

The acid gas injection well completion could include a subsurface safety valve, which would be remotely operated. The casing would be protected by a downhole packer and a noncorrosive fluid, such as diesel fuel or stabilized condensate containing corrosion inhibitor, in the annulus between the casing and tubing.

A hydrocarbon liquid in the annulus has the advantage of remaining noncorrosive even if acid gas were to leak from the tubing into the annulus.

The tubing string can be made out of sour service material, such as J-55, K-55, C-75, or L-80. Because the injected acid gas mixture is undersaturated in water, the tubing does not need to be internally coated, unless methanol is used for hydrate prevention.

The tubing should be equipped with premium connections that provide a flush internal surface at the connections, without recesses such as in EUE couplings.

Canadian experience

Sour gas compression with up to 45% H2S is common in Canada. However, because of corrosion concerns, it was not until 1989 that the first acid gas compression and injection scheme was installed by Chevron Canada Resources at its Acheson plant.

A key factor for choosing acid gas compression and injection was the downward revision, in 1988, of the sulfur emission limits. These new limits reduced the allowed sulfur flaring to less than 1 metric ton/day from the previous 10 metric ton/day limit.

This new regulation required plant operators to recover small amounts of sulfur, usually with acid gas feeds having poor H2S/CO2 ratios.

Since 1989, the number of plants injecting acid gas has increased to nearly 20, with sulfur content ranging from 1 to 77 metric tons/day.

Acid gas is injected into producing or depleted reservoirs and eight aquifers. It is also disposed of with water into three reservoirs.

Table 1 [68944 bytes] lists acid gas disposal projects and key design and operating parameters.

As more compression schemes have come on stream, operating problems have been identified and solved. Operator confidence has increased to a level that now acid gas compression and injection is the preferred choice over sulfur recovery.

This approach also has the advantage that there are minimal or no sulfur emissions to the atmosphere.

Compression

Most facilities have four compression stages with the compression ratio generally being less than three/stage. The early units were built entirely of 316 stainless steel, from the compression inlet flange to the final discharge flange. Currently, most units have carbon steel material up to the first-stage cylinder and carbon steel downstream of the dehydration facilities. Carbon steel has to meet NACE specifications for sour gas service.

Other components for the compressor items are materials used for sour gas compression, such as:

  • Cylinders-ion nitrided carbon steel

  • Rods-tungsten carbide coated stainless steel

  • Piston-carbon steel

  • Valves-stainless steel

  • Rod packing-glass-filled Teflon

  • Distance pieces-purged double-distance pieces.

One key area that must be watched is cooler design. For most installations, the first three stages handle the acid gas mixture in the gas phase, but in the cooler after the fourth compression stage, at ambient air temperatures, the acid gas will condense to a liquid or a dense phase. Therefore, the cooler design needs to account for the latent heat of condensation in the fourth stage, which is generally significantly more than just cooling the gas.

All cooler passes should have individual temperature control louvres to prevent gas condensation, particularly the third-stage cooler. The aerial coolers should have a provision for recirculating warm air when the ambient air temperature drops in the winter.

Another item that requires attention is the adequate sizing of the suction scrubber to the first stage. Most plant designs assume that the amine reflux drum will be adequate to handle any type of foaming or carry-over problem at the amine plant. However, if plant upsets cannot be controlled within the amine unit, and carry-over occurs, the compressor suction scrubber must have sufficient size to handle the liquid.

In addition, because of the very low operating pressure of the first-stage suction scrubber, the liquids caught in this vessel will either drain very slowly or it may be necessary to pump this fluid out.

Liquid separated in the suction scrubber of the first compression stage may be returned to the amine unit. However, liquid from the other scrubbers will usually be contaminated with compressor lube oil and will need to be sent to a separate disposal tank.

Most compressor units are skid mounted as complete packages and shipped to the field with an erected building.

Turndown

To accommodate varying flow rates, the acid gas compressor needs to have turndown capacity. For units with gas engine drivers, this can be done with speed control. For units with electric motors, this can be done using variable frequency drives.

However, speed reduction may have its limits, in which case a recycle provision of gas prior to final stage cooling to first stage suction is usually included.

Dehydration operation

Most operators continue to install some type of acid gas dehydration. The most common dehydration system remains the glycol dehydrator, although mole sieve or silica gel could be used. Plants that have a refrigeration system can also use this process to reduce the water content of acid gas to the appropriate level.

When glycol dehydrators are installed, all vessels, equipment, and piping on the rich system are usually 316 stainless steel. Carbon steel can be used on the lean side.

Most units are installed with a rich glycol flash tank. The operating pressure of the flash tank should be as low as possible, but still high enough to return flashed acid gas to the first-stage suction scrubber.

The glycol regenerator vent gas contains a significant amount of H2S, which must be sent to either a flare stack or an incinerator with a suitable stack height for dispersing combustion vapors.

A problem with lube oil carry-over from the compressor is glycol contamination. A high-quality scrubber should be considered for installation upstream of the glycol contactor.

Flow lines

Most injection lines are carbon steel because the acid gas is usually dehydrated. A corrosion inhibition program is sometimes applied as well, together with ultrasonic testing on a regular basis for the plant piping and lease injection lines. Where acid gas is injected into a water disposal operation, the water line is internally coated.

In cases with no dehydration equipment and the disposal well relatively near the plant, operators have used stainless steel lines.

Safety

Safety is a major concern with an acid gas injection system. Most compressor facilities are equipped with H2S detection and fire detection in the building with suitable alarms and exhaust fans that start at about 15 ppm of H2S.

At higher levels, 20-30 ppm, the unit would automatically shut down and be depressurized to flare. H2S detector heads are usually mounted 1 m above floor level.

Some operators have made provisions for acid gas compressors to be started either remotely from the plant control room or from a compressor panel installed in a separate building beside the injection compressor. This allows the operator to observe the compressor start-up.

References

  1. Wichert, E., and Royan, T., "Sulfur Disposal by Acid Gas Injection," Paper No. SPE 35585, Gas Technology Symposium in Calgary, Apr. 28-May 1, 1996.

  2. Longworth, H.L., et al., "Underground Disposal of Acid Gas in Alberta, Canada: Regulatory Concerns and Case Histories," Paper No. SPE 35584, Gas Technology Symposium, Calgary, Apr. 28-May 1, 1996.

The Authors

Edward Wichert is operations manager with Gascan Resources Ltd., Calgary, and also an adjunct professor in the department of chemical and petroleum engineering at the University of Calgary. His interests include research in sour gas and acid gas compression and injection.

Wichert holds a BS in petroleum engineering from the University of Alberta and a Masters in Engineering in chemical engineering from the University of Calgary.

Tom Royan is chief process engineer for Tartan Engineering, Calgary. He is involved in design, construction, and operations of gas plants, LPG systems, sulfur recovery units, compressor stations, gas storage systems, and underground salt cavern facilities. Royan has a BS in chemical engineering from the University of Alberta. He is member of the Canadian Gas Processing Association and a registered engineer in Alberta.

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