NONCRYOGENIC N2-REJECTION PROCESS GETS HUGOTON FIELD TEST

Yuv R. Mehra, Glenn C. Wood
Advanced Extraction Technologies Inc.
Houston

Michael M. Ross
Anadarko Petroleum Corp.
Houston

A noncryogenic, absorptionbased, nitrogen-rejection process has been installed and run on a 5 MMscfd field unit at Anadarko Gathering Co.'s Hugoton, Kan., compressor station.

In the newly patented Mehra Process nitrogen-rejection unit (NRU) concept, adapted from principles used in lean-oil absorption processes, methane is absorbed away from the nitrogen.

Contrary to the use of heat in conventional lean-oil plants, the new process uses a heatless approach to separating the recovered methane gases by reducing the pressure of the rich oil in steps.

The separated gases, containing less than 2 mol % N2 and meeting all other pipeline specifications, are compressed for sales.

In most situations in which the process can be used, the nitrogen is rejected to the atmosphere, and there is often no need for inlet-gas compression. The NRU can later be complemented with NGL recovery or helium recovery units or both with no changes within the NRU section.

Because of the noncryogenic operating conditions of the process, treatment for CO2 and mercury (Hg) removal is unnecessary. Inexpensive carbon steel metallurgy used exclusively for manufacturing all equipment additionally shortens construction schedules.

Operation of the skid-mounted Hugoton plant is stable under an unattended mode.

This plant was built exclusively from carbon steel and requires about 48% less compression than cryogenics. The entire unit required only a 22 week schedule during harsh winter conditions.

Capital and operating savings are substantial as well.

The Mehra Process NRU can also be integrated with selective recovery and helium recovery units with unusual processing and installation flexibility.

REGULATORY EFFECTS

If the U.S. Congress enacts a BTU tax a likely version will provide an incentive of 34.2cts./MMBTU to switch from oil-based fuels to cleaner burning natural gas.

A survey of some of the recoverable feedstocks being burned by U.S. refineries indicated that daily demand for natural gas could increase by more than 1.6 bcf.1

Additionally, in April 1992, the Federal Energy Regulatory Commission (FERC) issued Order 636 to complete the deregulation process of the U.S. natural-gas industry. One of the provisions of this order requires all pipelines to provide equal access to all producers and consumers of natural gas at posted tariffs for transportation of natural gas.

The order's implementation could limit pipeline companies to receiving revenues only from transportation services.

The pipeline capacity occupied by nitrogen provides no revenues. To ensure delivery of transported gases that meet stringent specifications, pipeline companies will no longer be able to afford to accept high-nitrogen gases.

The implementation of Order 636 by November 1993 will likely increase competition within the natural-gas industry to the benefit of all players in production, transportation, distribution, and marketing. 2

Additional incentives to remove nitrogen from natural gas have come with the advent of the natural gas vehicle (NGV). NGV fueling stations have stringent specifications on the nitrogen content of the natural gas because a high nitrogen content limits the operating range of the vehicles.

Currently available processes for upgrading produced gas to pipeline quality-removing water, CO2, H2S, N2, and NGLs-are often costly and energy intensive, especially when the diluents constitute a large portion of the gas.

Removing N2 is more difficult than removing CO2. But for the most part only cryogenic processes have been considered.

In one study, the Gas Research Institute (GRI) concluded that the N2 concentration of natural gas varies 563 mol % for gases associated with oil production. 3 And in several nonassociated gas reservoirs, N2 content varies 5-84 mol %.

Gases containing more than 4 mol % N2 are considered subquality and require some form of processing before shipment to most pipelines. A breakdown of N2-Contaminated U.S. gas reserves as a function of N2 content is shown in Table 1. 3

To meet growing natural gas demand, Purvin & Gertz Inc., Dallas, has projected that 93 N2-rejection plants would be required by 2000. 4 Recent BTU tax proposals and implementation of FERC Order 636 may accelerate the need to reject N2.

N2 ALTERNATIVES

Nitrogen rejection of natural gas is relatively new. The cryogenic processes for natural-gas applications have been adapted from air-separation technologies by substituting methane for oxygen.

The accompanying box summarizes briefly the differences between applications for air separation and for N2 rejection of natural gas.

This comparison shows that air-separation processes require minimal to no flexibility, whereas natural-gas applications require extreme flexibility. The limited flexibility of Exxon's Shute Creek, Wyo., cryogenic N2-rejection facility remains one of the main causes for operational difficulties there. 5

Exxon has stated that a 1 F. temperature variation on the inlet feed to the high-pressure tower causes the methane, N2, and helium products to deviate from specifications.

Additionally, another major producer operating a 300 + MMscfd cryogenic N2-rejection plant experienced a shutdown because of corrosion of an aluminum cold box from a few parts per billion mercury in the feed gas.

The Mehra Process technology 6-17 uses a physical solvent to remove and recover desirable hydrocarbons from a gas stream.

In the presence of the selective physical solvent, the relative volatility of hydrocarbons is enhanced. The selective solvent also has high loading capacity for desirable hydrocarbons, which reduces solvent circulation and equipment sizes.

The noncryogenic operating temperatures allow use of carbon-steel metallurgy which not only reduces capital investment but also shortens the construction schedule.

INTEGRATED SECTIONS

Fig. 1 shows an integrated NGL, N2 rejection unit (NRU), and helium recovery unit (HeRU) facility that uses the Mehra Process. For simplicity, the NGL/NRU/HeRU plant is shown as three separate sections.

NGL RECOVERY

The proposed configuration for NGL recovery uses an extractive-stripping arrangement similar to conventional lean-oil plants.18 19 The differences incorporate the use of a reboiled absorber column complemented by a solvent carefully chosen to meet the NGL recovery objectives.

The dried subquality gas is countercurrently contacted with a downwardly flowing lean solvent over a masstransfer surface provided by packing or distillation trays.

The solvent leaving the absorption section of the column also contains some methane. This methane is stripped from the hydrocarbon-saturated solvent by vapors generated at the bottom through a reboiler.

The objective of the stripping section of the absorption column is to ensure that the lighter undesirable components present in the rich solvent stream meet the specifications of the NGL product.

For ethane recovery, the lighter component would be methane; for propane recovery, limitations on the content of ethane are appropriate.

The rich solvent leaving the bottom of the reboiled absorber column is let down in pressure consistent with the operation of a fractionation column which separates recovered desirable hydrocarbons from the solvent. The desirable hydrocarbons are recovered from the top of the fractionating column as a liquid product.

This column is refluxed to minimize the solvent loss. The hot lean solvent leaving the bottom of the fractionating column is used to heat the rich solvent and in most cases to reboil the absorber column. The cooled solvent is returned to the top of the absorber column.

The flexibility of recovering or not recovering ethane as part of the NGL product is achieved by selecting the flow rate of the solvent in relation to composition and flow rate of the inletgas stream. This flexibility is achieved by changing-the operating conditions on-line.

Furthermore, there is no need to change the solvent for switching the operation from C2+ recovery to the C3+ recovery and vice versa.

A comparison of the Mehra Process with a cryogenic turboexpander process for the ethane-propane flexibility operation indicated a capital savings on the order of 11% and about 60% less compression for the Mehra Process unit.19

The margins for capital savings increase considerably at larger plant capacities because of substantial reduction in compression requirements.

N2 REJECTION

The Mehra Process NRU concept uses an extractive-flashing configuration to absorb methane away from the N2. Contrary to the use of heat for regeneration in conventional lean-oil plants, the process uses a heatless approach to separating the recovered methane gases by reducing the pressure of the rich oil in steps.

The separated gases are compressed to sales-gas pipeline pressures. These gases meet the new BTU and 2 mol % maximum N2 content requirements of most pipelines.

The N2 leaves the Mehra NRU at a high pressure. In most cases, the N2 is rejected to the atmosphere. The flashed solvent from the last stage is pumped back to the top of the absorber.

The Mehra concept improves the operating economics by combining the effectiveness of commercially available hydrocarbon solvents with proven equipment. This process does not require cryogenic temperatures, generally provided by using turboexpanders, and requires less overall compression than the cryogenic processes.

In most cases, inlet-gas compression is unnecessary. Because of the milder operating temperatures within the Mehra NRU, CO2 and mercury removal can be avoided. Carbon steel metallurgy is utilized exclusively.

An independent comparison of Mehra NRU with cryogenic processing for upgrading natural gas containing about 13 mol % N2 determined that the Mehra NRU costs about 12% less and requires 30% less overall energy than a cryogenic process.20 21

Maintenance requirements are considerably reduced because of 48% less compression for the Mehra unit. For NRUs requiring composition flexibility capital savings of up to 30% have been reported for the Mehra Processbased plants.

For cases where both NGL recovery and NRU are required, the solvent from the fractionating column within the NGL-recovery section enters the absorber column within the NRU section. The flashed solvent from the NRU section is returned as presaturated solvent to the reboiled absorber within the NGL recovery section.

Thus, the NRU and NGL sections of the plant utilize the same solvent and are integrated with each other.

HELIUM RECOVERY

If helium is present in the inlet feed gas after removal of NGLs and rejection of N2 from the sales gas, it stays with the overhead N2 stream.

Because the N2 stream leaving the absorber column within the Mehra NRU is at high pressure, this new concept lends itself to the recovery of high-purity helium.

Unfortunately, the helium content of inlet-gas streams is very low (0.051.25 mol %). By recovering NGLs and upgrading methane gases through the NRU section, the helium content of the N2-reject stream improves proportionately.

It is nevertheless still too low to warrant economic recovery.

Most of the cryogenic processes produce raw helium streams containing 50-70 mol % helium. The raw helium product is eventually purified to Grade A purity (99.9995 + mol % helium) at a few locations through significantly deeper cryogenic processing.

In the Mehra Process-integrated facility, the high-pressure N2/helium stream is bulk purified to 70-85 mol % helium through a membrane system. In the membrane unit, helium permeates the membrane and is recovered at low pressures.

The upgraded helium stream is compressed to about 200-300 psig for further purification through a pressure-swing adsorption (PSA) unit. The N2, leaving the membrane unit at near inlet pressures is rejected to atmosphere.

Processing an upgraded helium stream through a PSA unit enhances to 70-80% recovery levels of helium from the feed to PSA. The PSA produces a Grade A helium product at about the inlet-pressure level which is further compressed to 2,600-3,200 psig for sales.

The reject effluent from the PSA consists of residual helium and N2 but is available only near atmospheric pressure. This stream may be compressed and recycled back to one of the interstages of the multistage membrane unit for additional recovery.

Overall recovery of the combined membrane and PSA system can be 80-90% of helium present in the feed to the integrated Mehra Process units.

RECOVERY CASES

Examples of projected performance for C2 and C3 recovery cases appear in the accompanying box for the Mehra Process-based integrated facility shown in Fig. 1.

For both cases, the inlet gas is 90.0 MMscfd at design N2 content of 12.47 mol % and a gross heating value of 1,024 BTU/scf.

ETHANE RECOVERY

Under the process design carried out for C2 recovery, the NGL section recovers 95.3% of the incoming C2, 99.9% of C3, and all the heavier components of the inlet gas as NGL product. The C2 + product rate is 7,370 b/sd.

The overall recovery of the methane from the inlet feed through the NRU section is 99.3%. The pipeline sales gas (67.8 Mmscfd before fuel consumption) contains 1.06 mol % N2 and has a gross heating value of 984 BTU/scf.

From the N2/helium stream of 11.1 MMscfd containing 3.13 mol % helium, 295.5 Mscfd of Grade A helium (99.9995 + mol % He) is recovered by the HERU section. The reject N2 stream of 10.8 MMscfd containing about 2.5 mol % methane is vented to the atmosphere.

PROPANE RECOVERY

When the price of C2 as feedstock is less than its equivalent fuel value as part of the sales gas, it is important not to recover C2 while maintaining essentially the same C3 + recovery levels.

Under such market conditions, the solvent circulation rate to the absorber column within the NGL section is about 47% of the rate required for the C2-recovery case.

At these reduced circulation rates, C3 recovery is 98.1% with all of the heavier hydrocarbons being recovered as 3,822 b/sd of C3 + product. The Mehra Process NGL section essentially maintains high C3 recovery even at significantly reduced C2-recovery level of 1.2% (down from 95.3% in the C2 recovery alternative).

For this operation mode, the feed to the Mehra NRU section is 84.6 MMscfd containing about 13.3 mol % N2 (higher than 79.0 MMscfd containing about 14.2 mol % N2 under the C2 recovery case). For identical total solvent circulation to the absorber column and other operating conditions within the Mehra NRU section, additional gas is processed to maintain overall methane recovery from this inlet feed at 99.6% level.

The N2 content of the sales gas is 0.98 mol %, slightly less due to dilution from the contained ethane in the upgraded gas product. The performance of the HERU section remains unchanged.

It is important to note that with the Mehra Process, it is unnecessary to recover C2+ NGLs before rejecting N2. This is particularly important for locations where NGL pipelines are inaccessible.

Should economic conditions change, an NGL section can be added to an existing Mehra NRU section. Under either subsequent addition, essentially no changes would be required within the Mehra NRU section.

Similarly, an HERU section can be added to the Mehra NRU section at a later date.

PRODUCER'S PERSPECTIVE

Even though there are some pipelines in the area willing to transport this substandard gas, Anadarko has been limited in its marketing opportunities because of the N2.

State-controlled limitations on allowable production rates and the desire to maximize sales during higher price months historically have caused Anadarko's production on this system to vary between 10 and 90 Mmscfd.

With the deregulation of the natural-gas pipeline industry by FERC Order 636, there are now new opportunities available to Anadarko to expand its potential gas market and thereby achieve full market value through upgrading its gas quality.

While Anadarko Ekes the product recovery levels of cryogenic processes, it is nevertheless concerned with the enormous capital expenditure required for an integrated facility.

Having recognized the limits of the flexibility and the difficulty of operating available cryogenic processes, Anadarko has been seeking alternative technologies. It wants to achieve high methane recoveries, provide flexibility to accommodate flow and composition swings, and above all be easy to start up, operate, and maintain with minimal resources.

To achieve maximum value for its gas production, the plant should also be capable of flexibly recovering NGLs as dictated by the market prices and recovering high-purity helium.

Given the history and operating experience with absorption processes for the recovery of NGLs and that helium is used to calibrate the membranes and has been purified by PSA units, both Anadarko and Advance Extraction Technology agreed to demonstrate only N2 rejection of the Mehra Process technology.

DEMO UNIT INSTALLED

Fig. 2 shows the demonstration Mehra NRU built adjacent to Anadarko Gathering Co.'s (AGC) Area 3 compressor station near Hugoton. This unit is designed to process 5 MMscfd of natural gas containing 13 mol % N2.

Design performance is 98% minimum methane recovery and 2 mol % or less N2 in the residue gas. The 2 mol % N2 content is based on the most stringent pipeline specification (usually expressed as 4 mol % total inerts with a maximum of 2 mol % CO2)-Detailed engineering, fabrication, and field installation was by HPT Inc., Tulsa.

All equipment is skid-mounted (excluding the absorber column) which allows for extensive shop fabrication under controlled conditions. For example, approximately 60% of all welds were done in the fabrication shop.

In this particular case, the skid-mounted construction allowed the project to meet a 22-week schedule despite adverse weather in southwestern Kansas. Delays would have resulted had all construction been done in the field.

The Mehra NRU takes a slipstream from the discharge of AGC's compressors immediately upstream of the glycol cont actors. This pressure will vary between 420 and 520 psig depending on sales-gas flow and disposition. Methane and heavier hydro , carbons are removed from the stream and compressed back to pipeline pressure.

The N2-rich stream is returned to the inlet of the compressor station. Anadarko does not want to lose the helium contained in the stream for which it receives producer royalties.

Because the N2 is recycled back to the compressor station, the N, content in the feed will vary depending on total flow through the station. This flow can vary between 10 and 90 MMscfd, corresponding to a range of N2 concentrations between 19 and 13 million respectively. This will provide Mehra NRU data analysis at different feed compositions.

PRESSURE DROPS

Fig. 3 is a simplified flow diagram of the NRU.

The inlet gas is cooled to - 15 F. before it enters the absorber column. Cooling is provided by a propane refrigeration system. To reduce external cooling load, the inlet gas is cross exchanged with the absorber overhead and cold vapor streams from the gas-recovery flashes.

Condensed hydrocarbons are separated and sent directly to the sales-gas pipeline.

Liquid solvent is placed into the top of the column at -15 F. and flows downward through the absorber making contact with the feed gas. The solvent selectively absorbs the methane and heavier hydrocarbons; the combined solvent and hydrocarbon stream leaves the bottom of the column and enters the first of four flash vessels.

To separate the sales gas from the solvent, the pressure of this stream is reduced to 20 psia from the tower pressure of 400 psia. This reduction flashes off the gas, which is compressed back to pipeline pressure by a four-stage reciprocating compressor.

The pressure is dropped in stages to reduce compression horsepower requirements, with vapor from each flash entering the appropriate compression stage. This saves approximately 30% horsepower relative to recompression from the final flash pressure.

To meet the N2 specification in the sales gas, the first flash is recycled back to the bottom of the absorber column. Compression is provided by one stage of the residue-gas compressor.

Lean solvent is pumped back to the absorber column after leaving the final flash vessel. It flows through a cooler to maintain its temperature at -15 F.

The compressed sales gas is cooled to -15 F. to condense solvent that remains in the gas stream. This solvent is returned to the main circulation loop.

Vapor from the separator exchanges heat with compressor discharge to reduce external cooling load before it enters the sales-gas pipeline.

FLEXIBILITY

The fact that this process is based on absorption principles provides for significant processing flexibility.

The solubility of methane in the solvent is a function of its partial pressure in the gas phase. Therefore, changes in the column pressure will alter the equilibrium curve; as pressure increases, less solvent circulation will be required for a given methane recovery.

At constant column pressure, the solvent-to-feed ratio remains constant for varying feed rates.

Changes in feed-gas composition alter the operating curve in the column, requiring greater solvent-to-feed ratios at lower concentration of methane (higher N2 content).

Conversely, of course, less solvent will be required if the N2 content decreases. On a relative basis, however, the magnitude of required solvent-circulation changes are much less than the N2-content changes.

These relationships can be used to advantage for eco-nomically economically adapting to changes in feed rate and composition. With proper tower design, pump selection, and control-system design, the solvent circulation rate can be readily adjusted to compensate for both composition and feed-rate changes.

This particular unit is designed for an inlet gas flow of 2.5-5.5 MMscfd (2.2-1 turndown) utilizing standard tower internals for vapor and liquid distribution. This design is based on maintaining unit performance at a constant absorber operating pressure and staving within established design limits.

Unit testing will verify the actual range. Much higher turndown ratios can be achieved with proper vapor/liquid distributor design.

As described earlier, the concentration of N, in the unit's feed gas will vary as a function of total compressorstation flow. Fig. 4 is from the unit's operating manual showing the effect of changing the compressor-station flow (and thus N2 content) and N, in the residue gas at constant operating conditions (inlet gas flow, pressures, temperatures, and solvent circulation).

Here are the points of importance:

• A 43% increase in the feed-gas N2 content decreases total N2 rejection by only 2.1%.

• The same increase in N2 flow changes methane recovery by only 1.1% (there being actually an increase in recovery because. no process changes were made to maintain 2 mol % N2)

• Although an increase in solvent circulation would be required to maintain a constant level of methane recovery at constant N2 rejection, Fig. 4 demonstrates the relatively small change needed.

For this particular unit, the inlet N2 content can increase to 21.0 mol % design performance of 9.8% minimum methane recovery and less than 2 mol % N2 in the sales gas is maintained. This is based on a column pressure of 400 psia and constant operating temperatures.

INSTALLATION

The skid-mounted construction described earlier will allow the unit to be installed at another location after completion of unit testing.

Furthermore, because the process cooling requirements are provided by external propane refrigeration, both the refrigeration and residue-gas compressor can be provided separate from the core NRU facilities. This allows for optimizing compressor selection for specific situations.

If the unit is moved to a low-pressure gas supply, an inlet-gas compressor can be installed to boost the pressure. In fact, all compressors can be leased if economics and expected project life dictate.

Combining both the processing and installation flexibility presents a wide range of options for utilizing the NRU facilities.

For example, if the gas supply at another location contains only 1 mol % CO2, the residue gas could contain 3 mol % N2 and still meet pipeline specifications (CO2 removal being unnecessary because of the moderate operating temperatures). This would allow processing of gas containing 24 mol % N2 at 5 MMscfd.

The unit is mechanically designed for a maximum operating pressure of 640 psig 10% below maximum allowable working pressure). If gas were available at this pressure, the unit's capacity would be 9 MMscfd at the same inlet composition and solvent design rate for 5 MMscfd capacity at 400 psia.

REFERENCES

1. Mehra, Y.R., "Can We Really Afford to Keep Burning Light Olefins and Hydrogen In Our Refineries?" CMAI Seminar 1993, Houston, Mar. 24-25, 1993.

2. Koen, A.D., "U.S. gas industry sees signs of end of lengthy downturn," OGJ, Jan. 11, P.12.

3. Energy & Environmental Analysis Inc., "Chemical Composition of Discovered and Undiscovered Natural Gas in the Lower 48 United States," GRI Report 90/0248, November 1990.

4. Purvin & Gertz Inc., "Gas Processing Industry Lower 48 States," GRI Report 91/0232, July 1991,

5. Pruitt, C.A., and O'Brien, J.V., "Wyoming's Shute Creek plant uses NRU unit," OGJ, Oct. 9, 1989, p. 78.

6. Mehra, Y.R., "Process for Recovery of Natural Gas Liquids From a Sweetened Natural Gas Stream," U.S. Patent No. 4,421,535, Dec. 20, 1983.

7. Mehra, Y.R., "Process for Flexibly Rejecting Selected Components Obtained from Natural Gas Streams," U.S. Patent No. 4,526,594, July 2, 1985.

8. Mehra, Y.R., "Hydrocarbon Separation with a Physical Solvent," U.S. Patent No. 4,578,094, Mar. 25, 1986.

9. Mehra, Y.R., "Process for Using Preferential Physical Solvents for Selective Processing of Hydrocarbon Gas Streams," U.S. Patent No. 4,617,038, Oct. 14, 1986.

10. Mehra, Y.R., "Utilizing the Mehra Process for Processing and BTU Upgrading of N2-Rich Natural Gas Streams," U.S. Patent No. 4,623,371, Nov. 18, 1986.

11. Mehra, Y.R., "Extractive Stripping of Inert-Rich Hydrocarbon Gases with i Preferential Physical Solvent," U.S. Patent No. 4,680,042, July 14, 1987.

12. Mehra, Y.R., "Process for Using Alkyl Substituted C8-C10 Aromatic Hydrocarbons as Preferential Physical Solvents for Selective Processing of hydrocarbon Gas Streams," U.S. Patent No. 4,692,179, Sept. 8, 1987.

13. Bunting, T.N. "Process for Extractive-Stripping of Lean Hydrocarbon Gas Streams at High Pressure with a Preferential Physical Solvent," U.S. Patent No. 4,695,672, Sept. 22, 1987.

14. Mehra, Y.R., "Conversion of Lean Oil Absorption Process to Extraction Process for Conditioning Natural Gas," U.S. Patent No. 4,696,688, Sept. 29, 1987.

15. Mehra, Y.R., "Processing N2-Rich, Hydrogen-Rich, and Olefin-Rich Gases with physical solvents," U.S. Patent No. 4,832,718, May 23, 1989.

16. Mehra, Y.R., "Processing N2-Rich Gases with Physical Solvents," U.S. Patent No. 4,883,514, Nov. 28, 1989.

17. Mehra, Y.R. and Coffey, F.B., "Processing Hydrocarbon Gases with Selected Physical Solvents," U.S. Patent No. 4,883,515, Nov. 28, 1989

18. Mehra, Y.R., "Using Extraction to Treat Hydrocarbon Gases," Chemical Engineering, Oct. 27, 1986, p. 53,

19. Mehra, Y.R., "New Process Flexibility Improves Gas Processing Margins," Energy Progress, September 1987, p. 150.

20. Mehra, Y.R., and Leppin, D., "Using NonCryogenic Absorption to Reject N2 from Subquality Natural Gases," Gas Separation International Conference, the University of Texas at Austin, Apr. 22-24, 1991.

21. SRI International, "Comparison of the Mehra Process for N, Rejection to a Cryogenic Process for N2 Rejection from Subquality Natural Gas," GRI Report 90/0290, March 1991.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.