METHANOL GAS-TREATING SCHEME OFFERS ECONOMICS, VERSATILITY

June 1, 1992
Ari Minkkinen, Joseph Y. M. Larue Institut Francais du Petrole Paris Suru Patel Petro-Canada Inc. Calgary Jean-Francois Levier IFP Enterprises Texas Inc. Houston A process has been developed by Institut Francais du Petrole (IFP) to treat natural-gas using methanol as a single, basic solvent to dehydrate, control dew point, recover hydrocarbon liquids, and sweeten produced gas.
Ari Minkkinen, Joseph Y. M. Larue
Institut Francais du Petrole
Paris
Suru Patel
Petro-Canada Inc.
Calgary
Jean-Francois Levier
IFP Enterprises Texas Inc.
Houston

A process has been developed by Institut Francais du Petrole (IFP) to treat natural-gas using methanol as a single, basic solvent to dehydrate, control dew point, recover hydrocarbon liquids, and sweeten produced gas.

The impetus for IFP's research and developmental efforts which began in 1986 was to integrate the functional process steps-dehydration, NGL extraction, and acid-gas removal-into a compact solvent process with which water, NGL, and acid gases could be extracted with only a single solvent.

With the recognition that not all gases are sour but almost all are wet, it is important to be able to comply with only the hydrate depression and dehydration aspect of the gas process.

Thus, although the process, which is designated Ifpexol, was conceived for integration, it is also convenient to be split into three main parts: Ifpex-1, Ifpex-2, and Ifpex-3.

Ifpex-1 removes condensable hydrocarbons and water from the raw wet gas. It obviates the need for more complicated molecular sieves and environmentally stigmatized glycol systems.

Where methanol is already used for protection against hydrate formation in the cold process, Ifpex-1 is a solution for recovering much of the methanol and, therefore, reducing its consumption by a factor of six. The payout for this small investment is often less than a year.

When sweetening or bulk acid-gas removal is needed, the Ifpex-2 system is an alternative to selective amine technology. It operates dry with an inexpensive solvent.

Thermal energy requirements are often halved for the same acid-gas removal loads, and acid gases may be recovered dry at pressures to facilitate recompression for disposal or reinjection.

Ifpex-3, soon to be introduced, will treat the condensed hydrocarbons (if any) to remove dissolved acid gases and recover trace methanol from the liquids.

Pilot testing and detailed evaluation of Ifpexol with competitive technologies indicated that it exhibits low thermal-energy requirements, has no vent emissions, and allows recovery of process water.

Petro-Canada has agreed to collaborate with IFP by installing the first industrial application at its East Gilby gas plant in Alberta.

HOW IT WORKS

As shown in Fig. 1, a slipstream of raw wet feed gas flows up a column in counter-current contact with a descending methanol-water stream originating from a cold separator. This column can even be located remotely from the cold process, for example, on a wellhead platform.

The methanol solvent is completely stripped from the water by rising feed gas. The liquid stream leaving the column is essentially demineralized water-the same quantity that must be removed from the raw feed gas to meet the water dew point specification.

Meanwhile, the gas stream leaving the column has sufficient methanol content to prevent hydrates from forming during the subsequent pipeline transport or cold processing. Hydrocarbons, methanol, and water condensed during the cold process are separated in the cold separator.

The cold process reduces the gas temperature to the point at which the water or hydrocarbon dew point specification is reached. Any cold process can be used, from a simple expansion valve to an elaborate turboexpander process.

The net results are that the water and condensed hydrocarbons are removed and the methanol recovered efficiently for recycling without having to use either additional solvent recovery or water stripping facilities or external heat.

With the water and hydrocarbon dew points adjusted in the Ifpex-1 step, the already cold sour gas flows up a second column where it is contacted counter currently with a chilled methanol solvent stream (Fig. 2). The acid gases, notably H2S, CO2, and mercaptans, are physically absorbed in the solvent stream allowing the exiting gas to meet the sweet gas specifications.

A conventional regeneration process desorbs the acid gas from the solvent which is recycled to the Ifpex-2 column.

The regeneration is accomplished at pressures higher than 1 atm without resorting to high-level heat requirements; waste heat, hot water, or low-level steam is adequate. Some chilling, however, is required to cool the regenerated solvent to the same temperature as the inlet gas.

Chilling is also used to condense methanol in the solvent regenerator stripper overhead system.

If any water accumulates in the Ifpex-2 solvent stream, it is removed by the slip stream which purges the water with methanol as the make-up stream for the Ifpex-1 step.

PROCESS COMPARISONS

The Ifpex-1 step is simple in concept and achieves hydrocarbon and water dew points simultaneously down to even - 150 F. (- 100 C.).

The process was compared in a comprehensive evaluation conducted by an engineering company which had recently completed three different onshore dew point control dehydration projects with conventional technologies: monoethylene glycol (MEG) at 20 F. water dew point and 100 MMscfd capacity; triethylene glycol (TEG) at -35 F. and 210 MMscfd; and molecular sieves at -60 F. and 15 MMscfd.

Equivalent Ifpex-1 designs were applied to each real case for comparison of investment cost, equipment dry weight, and plot space. The cost savings figures covered dehydration only, excluding common equipment.

The comparison indicated that Ifpex-1 would realize a savings of $155,000 in investment costs over MEG injection, $500,000 over TEG contactor scheme, and $420,000 over molecular sieves.

Further, for dry-weight considerations, Ifpex-1 was found to realize a weight savings of 10 tons over MEG injection, 60 tons over TEG contactor, and 18 tons over mol sieves. For plot space, Ifpex-1 would realize a savings over MEG injection of 200 sq ft, over TEG contactor of 500 sq ft, and over mol sieves of 300 sq ft.

An example of weight and space for an offshore installation in the North Sea is illustrated in Table 1, showing a savings of 110 tons of wet support weight for a 300 MMscfd associated gas dew point control facility installed in the North Sea.

The savings in platform surface in this case was 520 sq ft. The resulting capital cost savings was $1.8 million.

Besides attractive performance and costs, the concept and simplicity of the Ifpex-1 process lends itself to substantial environmental advantages: no vent gases, emissions, thermal energy, or hot zones, and water being recovered for re-use.

Today much is heard about glycol dehydration units and their potential hydrocarbon emissions, notably those concerning hazardous aromatics such as benzene.

Glycol is a known extractant of aromatics. Some industrial aromatics extraction processes, in fact, use mixtures of glycols to extract benzene, toluene, and xylenes from liquids and gases.

Since the passage of the U.S. Clean Air Act, much attention has been focused on hydrocarbon emissions in air, notably those containing benzene. A GPA subcommittee has been formed recently to study these issues and develop a sampling method for measuring emissions from existing glycol dehydrators.

Regulations will undoubtedly be enacted in the near future to limit these emissions.

Hydrocarbon emissions are avoided by the nature of the Ifpex-1 technique. The Ifpex-1 contactor uses the energy available in a slip stream of water-saturated feed gas to accomplish the stripping of methanol from the methanol-laden water stream returned from the cold process.

Methanol, being more volatile than water, is completely stripped and returned to the cold process. Water is taken off at the bottom of the contactor as a liquid, not boiled off as a vapor in conventional glycol regenerators.

Neither hydrocarbon emissions nor benzene are emitted into the atmosphere with this concept.

Because the heat energy available in the feed gas is enough even at ambient cold temperatures as low as 10 F. to effect the stripping of methanol, no other external source of heat is required. The external heat energy, albeit small for glycol and mol sieve regenerators, creates a nuisance in terms of maintenance and security risks, especially on offshore platforms. Only a slip stream of relatively warm water-saturated feed gas is required to regenerate the methanol in the Ifpex-1 concept.

Finally, as the water condensed from the hydrocarbons in the cold process is stripped of methanol in the Ifpex-1 contactor, it is recovered for easy rejection or reuse. The quality of the water can be almost as good as demineralized water, especially when upstream free-water separation has already taken place.

The recovered water, as such, can be used to make up an amine unit or other demineralized water users.

If the recovered water is destined for rejection to sea, for instance, the methanol content can be controlled even below 100 ppm (mol) by providing sufficient packing height in the contactor and sufficient stripping gas flow.

The Ifpex-1 pilot plant in IFP's Research & Development Center in Solaize, France, has demonstrated the ability to strip methanol from the water to less than 50 ppm.

The stripping effectiveness can be illustrated in Fig. 3 as a function of the percentage of gas used for stripping and the number of theoretical stages of contact.

CANADIAN APPLICATION

Petro-Canada operates several gas-processing plants employing MEG injection with refrigeration to recover NGLS.

The cold separator operating temperatures vary from 0 F. to -40 F., depending on the level of LPG recovery required.

In Petro-Canada's (and industry's) experience, MEG systems have worked well in most applications. But the rich-glycol separation from the liquid-hydrocarbon phase becomes increasingly more difficult as the temperature is lowered.

Glycol losses also tend to increase. In fact, at one of the plants operated by Petro-Canada, losses were so severe that an upstream glycol-dehydration unit had to be installed to reduce losses and to eliminate glycol from the liquid product.

The plant operates at -40 F. and had 45-min residence time provided for separation of the liquid phases in the cold separator. Thus, it is of great interest to Petro-Canada to develop a simple process which can replace the glycol system, especially in low-temperature operations.

Also, the Ifpexol process employs methanol, a chemical which has a significantly lower cost than MEG and has proven to work well even at the low temperatures employed in the turboexpander process. Petro-Canada operates a 2.4 bcfd turboexpander plant which employs methanol for hydrate prevention.

Thus, methanol used in place of MEG is not a new concept. But the conventional methanol-regeneration,, scheme is much more complex and costly than for glycol regeneration and can only be supported by large processing plants.

Hence, the novel concept of regenerating methanol by the internal energy of the raw gas feed stream in a small packed column was appealing.

Finally, with the whole scheme operating under normal plant operating pressure, there are no emissions. All these factors combined to lead Petro-Canada to a collaboration agreement with IFP in taking the process to its commercial demonstration phase.

Several Petro-Canada operated plants were candidates for the Ifpex-1 conversion. However, East Gilby was selected because it is wholly owned by Petro-Canada, which simplified the approval process; it is conveniently located; and capital cost requirements for conversion were low.

In addition, the plant personnel were receptive to trying the new technology, although the original MEG system worked well.

Petro-Canada's management has also supported the project because of its environmental, energy, and cost benefit potentials.

In April 1991, Petro-Canada decided to convert its existing East Gilby gas-processing plant, which employs the conventional MEG injection and refrigeration process, to the Ifpex-1 process. The plant additions were carried out in the next few months and start-up took place on Sept. 11, 1991.

After a demonstration run of 2 weeks to collect various operating data on Ifpex-1, the plant reverted to MEG operation without interruption of the gas production.

After some minor modifications and the addition of self-regulation for unmanned operations, the plant will go back to the Ifpex-1 mode of operation in the next maintenance shut-down of the plant.

The East Gilby gas plant is designed to process 24 MMscfd of raw sour gas, Fig. 4 shows both a simplified process flow of the original scheme before its conversion to the Ifpex-1 design and the process flow after conversion.

The raw gas is fairly rich and before its arrival at the plant, any free liquids are separated and the gas undergoes compression in the field. The liquids separated in the field are treated by others.

In the plant, the raw-gas stream goes through an inlet separator where and, additional condensed liquids are removed. The gas then goes through an MDEA-based (monodiethanolamine) selective sweetening unit where the H2S is removed together with some of the CO2.

The treated gas, which contains up to 2% CO2, is mixed with sweet raw gas from another well nearby and, in the original process scheme, goes through a conventional MEG-type refrigeration unit.

Fig. 4 shows the additional equipment required to convert the plant to the Ifpex-1 process omitting the redundant equipment (MEG regeneration, storage, and pumping).

As can be noted, the main items to be added are the Ifpex-1 contactor (MeOH stripper), the decanted methanol-water recycle pumps, and the methanol make-up storage tank and delivery pump. No modifications were required to any other parts of the existing process.

As the gas entering the Ifpex contactor is saturated with water, it strips only the methanol from the methanol-water stream. Therefore, all the water entering the column at the top leaves from the bottom.

The stripped methanol, now transferred as a vapor to the overhead gas stream, together with the make-up methanol, condenses with the vapor in the gas stream due to refrigeration and is separated in the cold separator for recycling.

A trace amount of methanol leaves with the cold separator gas and some is lost through solubility in the NGLs which condense. This methanol loss depends on the liquid stream composition and cold separator temperature, with losses decreasing as the temperature is lowered, This is in direct contrast to MEG where the losses tend to increase rapidly as the temperature is lowered because of the increasing difficulty of separation.

The modifications for East Gilby were designed to allow operation in either MEG mode or Ifpex-1 mode without requiring a plant shut-down.

ACID-GAS REMOVAL

When the raw gases contain H2S, CO2, COS, and mercaptans which must be removed to meet pipeline sales-gas specifications, then the continuation of the Ifpex-1 step consists of the Ifpex-2 step.

The gas under pressure leaving the cold separator of the upstream process can be conveniently passed in its cold state to a matching cold pressure absorber column for complete removal of the H2S and tailored removal of the CO2 contained in the upflowing gas.

COS and mercaptans are also removed by the solvent stream.

The sweet gas leaving the top of the absorber column (Ifpex-2 contactor), at essentially inlet temperature with inlet dryness, is passed through a gas-gas heat exchanger for recuperation of the cold before being passed to further processing or battery limits as a sweet dry product. Refrigerated methanol is well known as a selective physical solvent for removal of H2S from gases. The proven Rectisol process is in fact based on cold methanol solvent for H2S and CO2 removal from chemical and natural gases. Being a physical and not chemical solvent, methanol absorbs the components present in the gas by a selective solubility, not by chemical reaction like amines.

H2S, being very highly soluble in methanol, can be completely removed even below 0.25 grain/100 scf or 3.0 ppm without much effort. CO2, on the other hand, is less soluble than H2S, and its slippage in the product gas can be tailored to suit the allowable specifications in like manner as with selective amines, such as MDEA.

Generally, a CO2 content of less than 1,000 ppm (mol) in the product gas would require solvent rates which would not be economical. The selectivity for H2S over CO2 by the physical solubilities of these acid gases in the methanol makes for easier regeneration of the solvent. The bulk of the CO2 and loosely held co-absorbed hydrocarbons can be released by simple flashing of the rich solvent. Highly soluble H2S, however, requires some thermal regeneration, but this can be accomplished at higher than atmospheric pressure (that is, up to 140 psig).

For regeneration of solvent containing only CO2, and when the CO2 content in the product can be slipped to greater than 1.0 mol %, the thermal regenerator can be operated as high as 200 psig. As with all physical solvents, there is a co-absorption of hydrocarbons to contend with. Sometimes this can be used to an advantage, but more often it is a disadvantage.

IFP's research and pilot-plant testing, however, have enabled hydrocarbon co-absorption to be controlled within limits by the adjustment of absorption parameters, chief among which is the water content of the solvent. The higher the water content (that is, the lower the methanol content), the lower the hydrocarbon solubility in the solvent.

Thus, by an adjustment of the concentration of methanol in the circulating solvent, hydrocarbon co-absorption can be tailored. Capacity for acid gas absorption, however, is reduced at lower methanol concentrations and an optimum balance must be made for each use. When high acid-gas absorption capacity is required for reduced solvent circulation with subsequent reduced energy cost, the hydrocarbon co-absorption in highly concentrated solvent can be accommodated by additional design features.

A proprietary feature within the Ifpex-2 regeneration allows for the recovery of nearly pure co-absorbed hydrocarbons which can be utilized as plant fuel gas if not suitable as product gas. This feature is generally incorporated into Ifpex-2 designs treating more than 100 MMscfd of gas.

COMPARATIVE EVALUATION

In a recent project study concerning onshore acid-gas extraction from a North Sea gas stream, a comprehensive evaluation was conducted by a European engineering company to assess the merits of the Ifpex-2 process over a classical MDEA process scheme. Principal characteristics of this project are given in Table 2.

The incoming gas was already dehydrated upstream with a glycol contactor process to a -25 F. water dew point on the offshore platform. The landfall pressure of 1,580 psig was imposed in order to transport the gas at greater than its cricondenbar pressure in a single dense phase.

A landfall turboexpander maintained the back pressure, expanding the inlet, temperature-adjusted gas to 710 psig with a controlled outlet temperature of approximately -5 F. Some sour liquids were formed, but these were either flashed to an acid-gas pipeline or sent to sour-condensate stabilization facilities.

The dew point and heating value-adjusted dry gas was to be treated through a selective amine process to remove acid gas to the limits of the following sales gas specifications: CO2 content-4.0 mol % (maximum); H2S content-2.6 ppm vol (maximum); water content-2 lb/MMscf; and delivery pressure-700 psig.

The acid gas extracted by the sweetening process was, for environmental reasons, to be recompressed to a disposal pipeline (eventually to be reinjected to a disposal aquifer). The acid gas extracted consequently must also meet the following specifications: water content-2 lb/MMscf; delivery pressure-500 psig.

As the upstream turboexpander section for both the MDEA and Ifpex-2 schemes are the same, this comparison concerns only the gas sweetening and post-treatment aspect.

Because of the conventional choice of an aqueous amine process, the dry sour feed gas leaves the sweetening unit as a water-saturated gas. Likewise, the acid gas recovered from the amine regenerator leaves at relatively low pressure saturated with water.

Hence, for the conventional scheme, glycol contactors were required for both the sweet product gas and the acid-gas streams to meet the water-content specifications.

The Ifpex-2 acid-gas removal process wets neither the product nor the acid gas streams; both leave drier than allowable specifications. Moreover, as the recovery of the acid gas from the Ifpex-2 methanol solvent is accomplished at 75 psig instead of 20 psig, recompression of the acid gas to 500 psig is facilitated by a reduction in the compression stages from three to two with a subsequent saving of compression power. There is also a saving in material cost of the compression system which could be made of carbon steel for the Ifpex-2 scheme. The comparison of the utilities consumption for the overall processing complex including acid-gas compression and additional dehydration, is given in Tables 3 and 4. The utility operating cost comparison is given in Table 5.

As can be seen, the Ifpex-2 utilities' cost is roughly $1.5 million/year lower than the MDEA scheme. This is due principally to a much lower thermal energy requirement of the process.

The investment comparison which is summarized in Table 6 gives an overall advantage of $5 million to the Ifpex-2 scheme. Although the Ifpex-2 unit investment is shown to be $4 million more expensive than the equivalent MDEA unit, the overall investment savings result from the lack of additional dehydration and the savings in acid-gas compression. Another study made by a U.S. engineering and construction firm came to the same conclusions (Fig. 5). It considered two trains of 210 MMscfd of a sour gas with 33% CO2 and 1.37% H2S.

BIBLIOGRAPHY

  1. Minkkinen, Ari, and Levier, Jean-Francois, "Ifpexol: Complete Gas Treatment with a Basic Single Solvent," Laurance Reid Gas Conditioning Conference, Norman, Okla., Mar. 2-4, 1992.

  2. LaRue, J., Minkkinen, A. A., and Patel, S., "Ifpexol For Environmentally Sound Gas Processing," 71st Annual GPA Convention, Anaheim, Calif., Mar. 16-18, 1992.

  3. U.S. Patent No. 4775395: "Integrated Process for the Treatment of a Wet Hydrocarbon Gas," October 1986.

  4. U.S. Patent No. 4979966: "Process and Apparatus for Dehydration, Sweetening and Separation of a Condensate from a Natural Gas," September 1988.

Copyright 1992 Oil & Gas Journal. All Rights Reserved.