INTEGRATION OF MEMBRANES INTO NATURAL GAS PROCESS SCHEMES

William I. Echt and Mander Singh UOP LLC, A Honeywell Company Des Plaines, IL © UOP LLC 2008, All Rights Reserved

ABSTRACT As the world searches for more energy in more remote locations, natural gas reserves that would have been marginal or unprofitable years ago are now being developed. Many of these reserves are offshore and contain large amounts of carbon dioxide. Pipelines and compression to bring the gas to shore are expensive, hence partial offshore gas conditioning makes economic sense. This paper evaluates optimized processing options when using membranes to remove CO2 from natural gas. These include simultaneous dehydration, mercury and H2S removal, dew point control, and NGL recovery strategies. Relevant process utility duties and equipment sizes are compared to demonstrate the advantages and disadvantages of various process schemes. Some of the key process decisions that must be addressed in conjunction with CO2 removal are operating pressure / optimization of compressor stages and horsepower, CO2 sequestration, NGL recovery schemes and their impact on the condensate stabilization unit, reliability / turndown / equipment redundancy, and degrees of flexibility while minimally impacting capital and operating expenses. In recent offshore project awards, UOP has integrated UOP Separex™ membrane systems into the overall process flow scheme in various ways to create optimum solutions for our customers. Several of these projects were designed to allow future CO2 capture. This paper highlights design features that are specific to the use of Separex membranes and others that are of general interest. While the examples emphasize the effect on offshore platform designs, the conclusions also apply to land-based systems.

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INTEGRATION OF MEMBRANES INTO NATURAL GAS PROCESS SCHEMES INTRODUCTION Natural gas processing schemes vary to conform to the product specifications. When hydrogen sulfide (H2S) is present in the raw gas, the processing scheme must produce a residue gas that meets the pipeline specification. This typically requires pretreatment of the feed gas prior to natural gas liquid (NGL) recovery but post-treatment of the liquid fraction(s) is also possible. When liquid ethane recovery is desired, some removal of carbon dioxide (CO2) from the feed gas and/or the liquid product is required. The process chosen may also impose requirements for upstream or downstream processing. For instance, when NGL recovery is desired the feed stream requires removal of both water and CO2 as part of the upstream pretreatment. Removal of trace H2S and mercaptans is often left to removal from downstream liquid streams. This paper examines various processing schemes that use membranes for bulk removal of CO2 from natural gas. One of the prominent applications for membrane technology is dehydration and CO2 removal from offshore natural gas reserves and other remote locations. Offshore applications require an export sub-sea pipeline to shore, which can span several hundred kilometers. Because these pipelines, and the associated compression, are very costly, producers have chosen to remove both water and CO2 at the production platform. This scheme allows the pipeline to be constructed of mild carbon steel and increases efficiency by removing a non-value-added contaminant. A raw NGL stream may also be produced offshore when a pipeline or floating production, storage, and off-loading (FPSO) ship is made available. Several offshore applications with a combination of dehydration, CO2 removal using membranes and NGL production have been installed or are currently under construction. This paper will look at various process schemes and highlight where advantages may be found. Bulk CO2 removal processes using membranes onshore can also apply the process schemes discussed in this paper. CASE STUDY CONDITIONS To examine the effect of various process schemes on the overall economics of the process, this paper will use a single set of feed gas conditions and product specifications. The equipment arrangement and operating conditions will then be varied over a design range and the effects on system capital and operating costs will be compared. Detailed cost estimates were not conducted for each scenario. Rather, the effect on equipment size and duty will be compared to a selected reference. The case study assumes the following feed gas conditions: • •

The gas is produced from several wells and arrives at the platform at 88ºF (31ºC) and 300 psig (2100 kPag). The production separator removes all liquids from the gas. Gas leaving the production separator has 38% CO2 and is saturated with water and hydrocarbons as shown in Table 1.

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H2S content is 80 ppmv and mercaptans are not present in significant quantities. Mercury removal is not considered in this base case. Table 1 – Feed Gas Conditions and Composition

Stream Name Temperature, F Pressure, psig Composition, Mole% Carbon dioxide Nitrogen Methane Ethane Propane i-Butane n-Butane 2,2-Mpropane i-Pentane n-Pentane n-Hexane Mcyclopentane Benzene Cyclohexane n-Heptane Mcyclohexane

Feed Gas 87 300 38.8002 1.2587 44.6058 6.8232 4.9076 1.0486 1.1517 0.0040 0.3855 0.2795 0.1950 0.0334 0.0410 0.0244 0.1165 0.0312

Composition, Mole% Toluene n-Octane E-Benzene m-Xylene o-Xylene n-Nonane 1,2,4-MBenzene n-Decane n-C11 n-C12 n-C13 n-C14 n-C15+ Water Hydrogen sulfide, ppm

0.0166 0.0132 0.0005 0.0059 0.0012 0.0030 0.0004 0.0012 0.0003 0.0001 0.0000 0.0000 0.0000 0.2432 80.0894

The case study assumes the following product specifications: • • • •

Export gas to contain no more than 22% CO2 and 50 ppmv H2S. Water content to be less than 7 pounds per million standard cubic feet of gas (7 #/MMSCFD). Export gas rate of 363 MMSCFD must be delivered at the discharge of the export compressors at 2000 psig (13,800 kPag). The product gas rate is based upon a contractual rate of 330 MMSCFD plus a 10%. NGL product stabilized to a Reid vapor pressure of 12 psia (83 kPa) is to be delivered at 235 psig (1600 kPag). The CO2 rich permeate stream is to be flared with provision for future reinjection.

The following design constraints were applied to all process schemes: • • •

Equipment size (plot space) and weight to be minimized. The vapors from the condensate stabilizer system to be compressed and recycled to the feed gas stream are to be minimized. Equipment sparing and multiple trains to be considered so as to achieve a system availability of 98.5%.

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The above requirements impose challenges, which necessitate working closely with customers to develop innovative and optimized schemes tuned to their individual applications. By adjusting operating parameters one at a time the effect of each can be compared to better understand the impact on system cost. Some combination of these operating parameters will result in an optimum scheme with the lowest operating and capital cost. MEMBRANE PROCESS REQUIREMENTS Membranes themselves impose process requirements over and above the demands of the gas processing product streams. While membranes have been shown to be quite robust in natural gas service, long membrane life (resulting in low operating cost) is dependent upon proper feed gas pretreatment. A discussion of the reasons for membrane pretreatment is presented in the literature.[1] For the feed gas described in Table 1, advanced pretreatment is required for dew point control to enhance membrane life and efficiency. UOP employs a temperature-swing adsorption (TSA) unit called the UOP MemGuard™ pretreatment system for dew point control.[2] The effect of various process parameters on the size of the TSA system will be examined. GENERAL FLOW SCHEME The use of membranes is a very good fit for bulk removal of CO2 from 38% in the feed gas to 22% in the product gas. When the required CO2 removal is