Nitrogen Rejection Unit Research Articles

Design and Optimization of a Novel Hybrid Membrane-Electrochemical Hydrogen Pump Process for Recovering Helium from NRU off Gas.

Due to the low boiling point of helium, the nitrogen-rich off gas of the nitrogen rejection unit (NRU) in the liquefied natural gas (LNG) plant usually contains a small amount of CH4, approximately 1-4% He, and associated gases, such as H2. However, it is difficult to separate hydrogen and helium. Here, we propose two different integrated processes coupled with membrane separation, pressure swing adsorption (PSA), and the electrochemical hydrogen pump (EHP) based on different sequences of hydrogen gas removal. Both processes use membrane separation and PSA in order to recover and purify helium, and the EHP is used to remove hydrogen. The processes were strictly simulated using UniSim Design, and an economic assessment was conducted. The results of the economic assessment show that flowsheet #2 was more cost-effective due to the significant reduction in the capacity of the compressor and PSA because of the pre-removal of hydrogen. Additionally, using the response surface methodology (RSM), a Box-Behnken design experiment was conducted, and an accurate and reliable quadratic response surface regression model was fitted through variance analysis. The optimized operating parameters for the integrated process were determined as follows: the membrane area of M101 was 966.6 m2, the permeate pressure of M101 was 100 kPa, and the membrane area of M102 was 41.2 m2. The maximum recovery fraction was 90.66%, and the minimum cost of helium production was 2.21 $/kg. Thus, proposed flowsheet #2 has prospects and value for industrial application.

Sustainable boil-off gas utilization in liquefied natural gas production: Economic and environmental benefits

Boil-off gas (BOG) causes negative environmental impacts related to gas streams flaring in the liquefied natural gas (LNG) industry. This study addresses the resources and energy management and discusses the economic and environmental benefits of recycling the BOG stream in the LNG production process. Three BOG utilization scenarios and strategies are considered. The first scenario is a separate cooling cycle dedicated to re-condensing the BOG before introducing it to the nitrogen rejection unit (NRU). The second strategy is recycling the BOG before the liquefaction section. The third scenario is recycling the compressed BOG directly in the NRU without re-condensation. Three NRU configurations—flash drum, single distillation column, and double distillation column—are analyzed. The assessment is conducted by the steady-state ASPEN HYSYS simulation of an AP-X LNG production flowsheet. In an illustrative case study, various design alternatives are analyzed for recycling 52,000 metric tons of BOG annually while considering and combining economic, energy, and environmental objectives.

Integration of hybrid membrane-distillation processes to recover helium from pre-treated natural gas in liquefied natural gas plants

We used Aspen HYSYS V.10 simulations and techno-economic analysis to evaluate the potential of four hybrid membrane-cryogenic distillation flowsheets for the direct recovery helium from nitrogen and methane in pre-treated natural gas (i.e., CO2, H2S, and water removed from the gas). The study aims to increase energy efficiency and reduce the cost of helium recovery from natural gas by better integration of the helium recovery unit (HeRU) with the nitrogen rejection unit (NRU) and methane production. Our results demonstrate that a flowsheet (Design # d) with a distillation column that produces a 90 mol% He overhead stream that is further purified in a single-stage membrane unit can produce grade-A helium with better than 99 mol% He purity at a specific helium breakeven price (SHBP) of $67.72/MSCF of He product. This hybrid flowsheet leads to the lowest SHBP because (i) it reduces the separation load in the HeRU column, (ii) provides a high He concentration feed to the membrane unit, and (iii) does not require recompression of the HeRU overhead stream to feed the membrane unit because the pressure of the feed gas is not let down to close to atmospheric pressure as in a conventional NRU-HeRU flowsheet. This type of hybrid distillation-membrane process may also be of interest in other gas separations that currently only use cryogenic distillation such as oxygen and argon production from air, CO2 capture, and olefin/paraffin separation.

Cryogenic Nitrogen Rejection Schemes: Analysis of Their Tolerance to CO2

In the “energy transition era” we are experiencing today, natural gas grows strongly and much faster than either oil or coal, being an environmentally friendly fuel supported by a broad-based demand and the continuing expansion of liquefied natural gas (LNG). Natural gas mainly consists of methane, but also some contaminants are present in it. Among them, nitrogen is an inert gas whose content, if too high, must be reduced to levels acceptable for producing a pipeline-quality gas or LNG. When dilution of the high-nitrogen gas stream with a low-nitrogen gas is not practical, a nitrogen removal unit (known as nitrogen rejection unit or NRU) must be installed. This is becoming more and more important as we shift to lower-quality gas feedstocks. Cryogenic distillation is the only viable option for the removal of N₂ on a large scale and in the case of stringent specifications both in the product stream and in the rejected stream. Typically, the feed gas to the NRU has to contain methane and N₂ and only very low quantities of compounds (such as CO₂) that might freeze at the NRU operating temperatures and cause equipment blockage. Focusing on the production of pipeline-quality natural gas, the aim of this work is to analyze the cryogenic removal of N₂ from natural gas streams that also contain CO₂ because a CO₂-tolerant NRU may lower capital and operating costs reducing the upstream removal of CO₂. Different process configurations (i.e., the single-column, the double-column, and the three-column systems) are investigated to determine the maximum allowable CO₂ content in the feed gas that avoids solidification within the process and permits reaching the desired value of the Wobbe index. Therefore, a range of applicability for each configuration is determined depending on the N₂ and CO₂ contents in the feed gas.

Measurements of helium adsorption on natural clinoptilolite at temperatures from (123.15 to 423.15) K and pressures up to 35 MPa

Helium (He) is an increasingly valuable gas that is relatively difficult to recover: most of the global helium supply is produced through the application of deep cryogenic separation processes to the overheads from a nitrogen rejection unit in an LNG plant. Pressure swing adsorption (PSA) offers an alternative low-cost process for recovering He from natural gas, particularly if a helium selective adsorbent with sufficient capacity could be identified. However, the accurate measurement of the helium equilibrium capacity on narrow pore adsorbents is particularly challenging. Here, the uptake of helium on a natural clinoptilolite-rich Escott zeolite was measured with a volumetric adsorption apparatus at temperatures from 123.15 to 423.15 K and pressures up to 5 MPa, and with a gravimetric adsorption apparatus at temperatures in the range 243.15–423.15 K and pressures up to 35 MPa. We used these two experimental data sets to determine the specific inaccessible solid volume (vs) and true void volume of the Escott zeolite by eliminating the common assumption of zero helium uptake. Instead, the data analysis workflow established by Sircar (2001) and by Gumma and Talu (2003) was applied to the adsorption isotherms measured using the gravimetric apparatus. This led to a specific inaccessible solid volume for the Escott zeolite of 0.462 cm3·g−1, with a maximum helium adsorption capacity of 0.9 mmol·g−1 measured at 253.15 K and 35 MPa. The isosteric heat of adsorption for helium on the Escott zeolite was estimated to be 3.05 kJ·mol−1. The uptake of N2 on the Escott zeolite was also measured; these data were used together with the helium measurements to estimate conditions at which an equilibrium selectivity of 3 for He over N2 might be achieved in an equimolar He + N2 mixture.

Optimization of helium extraction processes integrated with nitrogen removal units: A comparative study

Helium is regarded as a vital gas to various industries such as medicine, aircraft manufacturing, electronics and fiber optics fabrication. Currently, natural gas reserves are considered the only viable resource for this rare element. When processing (helium-rich) natural gas, helium is generally recovered in the most downstream stage in conjunction with the nitrogen rejection unit (NRU). The feed to this unit is a nitrogen rich stream, and the product is either crude helium (50–70 mol% purity) or purified helium (99.99 mol% purity). Currently, the cryogenic distillation method is a common technology for a crude helium extraction unit (HeXU). The alternative method for this purpose is a membrane gas separation system, which is successfully used in other applications. This study aims to propose an energy-integrated scheme for each of the two helium separation technologies with a single-column NRU and to evaluate and compare them for different applications. Matlab programming has been used to model the membrane system and incorporate it into Aspen Hysys, which is used to simulate the rest of the process flowsheet. Next, the energy consumption of the systems was optimized using the particle swarm optimization method. An economic analysis was adopted to compare the two technologies for different applications in order to suggest a comprehensive map for HeXU technology selection.

P84 Co-Polyimide Based-Tubular Carbon Membrane: Effect of Heating Rates on Helium Separations

Helium is one of the most valuable gases with unique features and properties as well as widely used in various applications. Generally, most of the helium sources was extracted from natural gas and it is very crucial to develop efficient technology for helium recovery from natural gas sources, in order to overcome the deficit of the helium supply. Up to now, there are various available traditional separation methods for helium recovery, however these methods possessed several disadvantages such as expensive in cost and energy intensive. Recently, gas separation by using membranes have been utilized and showed potential in recovering and purifying helium from natural gas. This method directly separating the helium from the methane through natural gas liquefaction process where in this process the helium is recovered from the nitrogen rejection unit (NRU) exit gas. Due to the potential benefits that can be obtained from this membrane-based separation method, this current study is aiming to provide more comprehensive scientific reports on the effects of preparation parameters on the performance of tubular carbon membranes (TCMs) for helium separation. In this study, the carbonization heating rate was varied from 1 to 7°C/min by controlling the final temperature at 800°C under Argon environment for all polymeric tubular membranes. The permeation performance of the resultant TCMs have been determined by using a single permeation apparatus. It is necessary to fine-tuning the carbonization conditions in order to obtain the desired permeation properties. From the results, it can be concluded that the most optimum heating rate was found to be at 3°C/min with 463.86±3.12 selectivity of He/N2separation.

Helium Recovery through Inorganic Membranes Incorporated with a Nitrogen Rejection Unit

Helium recovery and purification from a natural gas process is increasingly being investigated globally to address rising market demand, as traditional helium sources become depleted. Here, process...

Purification of helium from a cryogenic natural gas nitrogen rejection unit by pressure swing adsorption

Abstract Helium is produced conventionally from cryogenic processes in conjunction with LNG/NRU units. However, cryogenic processes are expensive and energy demanding. Pressure swing adsorption (PSA) was investigated as a potential replacement for the cryogenic processes to enrich dilute He (1 vol%) downstream of the NRU. The feasibility of a PSA process utilizing zeolite 13X was studied by dynamic simulation of 3-bed 3-step, 3-bed 5-step and 4-bed 7-step PSA cycle schedules. The static equilibrium parameters and dynamic mass transfer coefficients were estimated experimentally and the model was validated using dynamic breakthrough curves and PSA cyclic tests. The validated model was used to study the effect of adding equalization steps on the PSA process performance of the 3-bed 3-step cycle. Adding one equalization step (3-bed 5-step) effectively improved both the purity and recovery, while adding two equalization steps (4-bed 7-step) increased the capital costs with only minor improvements in purity and recovery. The best PSA process performance was obtained from the 3-bed 5-step PSA cycle, wherein feeding 1 vol% He resulted in a He purity of 94.3% at 62.1% He recovery and a feed throughput of 746.4 L(STP)/(h kg).

The Economics of Helium Separation and Purification by Gas Separation Membranes

Membrane gas separation has the potential to recover and purify helium, either directly from natural gas or as part of the off gas produced from the nitrogen rejection unit in conventional natural gas processing. Process designs for achieving high helium recovery and purity have previously been published by the authors, based on permeability and selectivity performances already present in current polymeric membranes. Here, the application of polymeric gas separation membranes for helium recovery is extended further, and the economic viability of process designs has been investigated and evaluated against the commercial helium price. For direct recovery and purification of helium from natural gas, membrane gas separation is economically competitive when the natural gas field has a helium concentration of ≥0.3 mol %. The final compression of the purified helium dominates the economics, accounting for 45% of the capital cost (CAPEX) of the process as well as 80% of the operating costs, because the membrane a...

Cascade refrigeration systems in integrated cryogenic natural gas process (natural gas liquids (NGL), liquefied natural gas (LNG) and nitrogen rejection unit (NRU))

Heavy components in the natural gas itself can feed downstream units and also due to the low temperature process may be formed solid. Therefore heavy components separation is a necessity and can produce useful products. Virtually all natural gases are containing nitrogen that would lower the heating value of natural gas. This study investigates design and optimization of integrated process recovery of natural gas liquids, natural gas liquefaction, and nitrogen remove unit. In this integrated process, design of low temperature processes is started from the core process and continued by heat exchangers network design and cooling system based on MFC. Design and integration processes of units at the same time reduces the number of required equipment and energy consumption. The results show that the new integrated process has specific power around 0.343–0.33 (kW-h/kg-LNG) and its thermal efficiency equal to 62.82%, compared to other integrated systems have the lowest and highest values. Exergy analysis shows that towers has the highest Exergy destruction among other equipment. Sensitivity analysis shows that the structure of the integrated process capable of removing nitrogen from natural gas at a concentration of between 5% and 15%. By analyzing the operating parameters shows reduction in the Total specific power from 19.5% to 24% and the Specific power from 2.57% to 11%, yet surging in the Ethane recovery from 2.5% to 17%. Sensitivity analysis is the method to identification of the Decision variables, finally Genetic Algorithm used to identify optimum of objective function (minimization of Specific Power) and reduction of it to 6%.

Helium separation through polymeric membranes: selectivity targets

Gas separation membranes have the potential to recovery and purify helium from natural gas. This can be through direct separation of helium from methane or as part of a natural gas liquefaction process where helium is recovered from the nitrogen rejection unit (NRU) exit gas. Here, membrane gas separation process simulations are undertaken in Aspen HYSYS to determine the required membrane selectivity and process conditions needed to perform these separations. It was determined that two and three membranes in series processes can separate helium directly from natural gas utilizing currently available polymeric membrane selectivities, if the helium composition in the feed is greater than 1mol% and at high pressure. However, for lower quality natural gas fields' improvement in He/CH4 selectivity is required for membrane separation to be viable. The recovery of helium from the NRU exit gas and concentration to 70mol% is also possible through two or three membranes in series process with a He/N2 selectivity above 5. However, this selectivity requires a significantly high pressure driving force across the membrane stages, because the process is operated at very low stage-cuts. A He/N2 selectivity greater than 25 enables recovery of helium and concentration to 70mol% with significantly lower pressure driving force. The upgrading of helium from 70mol% to 90mol%, before final purification, is the most viable separation that can be undertaken with existing gas separation membranes and the energy duty of a two membranes in series process is comparable with existing technology. Hence, current polymeric membranes for helium separation can perform many of the process stages in helium recovery and purification. However, improvements in polymeric membranes' He selectivity enables the various separation stages to become increasingly viable when compared with existing separation technologies.

Development and optimization of an integrated process configuration for natural gas liquefaction (LNG) and natural gas liquids (NGL) recovery with a nitrogen rejection unit (NRU)

In this study a novel integrated process including recovery of natural gas liquids, natural gas liquefaction and nitrogen rejection unit is investigated and analyzed. Natural gas is often associated with nitrogen and hydrocarbon heavy compounds. Recovering such heavy liquids can be necessary. Nitrogen of the natural gas when its content is more than 4 percent (mole fraction) must be removed. Because operating temperature of the LNG, NGL and NRU processes are lower than −100 °C there a good potential to integrate these processes. Process integration declines the energy consumption and number of the required equipment. The results show that the new integrated process has specific power of 0.359 (kWh/kg-LNG) and recover NGL more than 90%. Sensitivity analysis shows that this process is capable of eliminating nitrogen from the natural gas at a concentration of 4%–15%.

Integrated Air Separation Facilities For Hydrocarbon And Sulphur Recovery

Abstract The concept of using an air separation plant to generate nitrogen jar enhanced hydrocarbon recovery and oxygen for sulphur production is reviewed. Nitrogen generation (for injection) and nitrogen rejection processes are discussed and cost curves are presented. Conventional oxygen enrichment and the COPE ™ (Claus Oxygen-based Process Expansion) sulphur recovery processes are compared. Locations where an air separation facility can be designed to produce both nitrogen jar injection and oxygen jar sulphur recovery are identified. Having identified potential sites for integration, oxygen and nitrogen economics are presented. Introduction North America contains vast reserves of conventional crude oil, heavy oil, oil sands, and natural gas containing sulphur (as hydrogen sulphide). In order to produce these reserves economically, industry is constantly investigating the application of new methods to enhance production. Some of these methods use industrial gases such as nitrogen (in secondary and tertiary hydrocarbon recovery projects) and oxygen (in situ combustion for heavy oil recovery and to displace air in sulphur recovery units). These gases are co-produced in cryogenic air separation facilities. However, to date, the application of air separation technology has been very site/project specific and designed to recover only one industrial gas. Many air separation facilities have been installed to deliver nitrogen for enhanced hydrocarbon recovery (EHR). At these locations the low-purity oxygen by-product is vented to the atmosphere even though it could be used as an efficient source of oxygen for combustion processes, such as sulphur recovery from a Claus unit. Hydrocarbon Recovery- Nitrogen Injection/Rejection The use of cryogenically produced nitrogen from an air separation unit (ASU) was initiated in the late seventies as a cost-effective alternative to natural gas injection(I.2). Its use for EHR has grown dramatically and has been applied primarily in the "lower 48" United States. In their June 1985 paper, Clancy et al.(2) provide a list of 33 reservoirs which have used nitrogen injection technology. Figure 1 locates the sites (illustrated by triangles) from this list which have used cryogenic air separation facilities to produce nitrogen. Sites where a nitrogen rejection unit (NRU) is installed as well are located by a darkened triangle in Figure 1. One of the eight sites where both nitrogen injection and rejection and are practiced is Dome's Willesden Green Field in Alberta(4). Exxon operates an integrated injection/ rejection project at Jay-Little Escambia Creek Field near the Florida/Alabama border(5). The remaining six sites are located at University Block 31 (Texas), Anschutz Ranch East Field (Wyoming), Andector-Ellenberger Field (Oklahoma), Fordoche Field (Louisiana), and two at the Painter Field (one triangle shown in Wyoming). Sulphur Recovery The primary method of producing elemental sulphur from natural gas is with the use of the Claus process. A typical modified Claus sulphur recovery unit (SRU) with two catalytic conversion stages and a modem reheat scheme uses air as the course of oxygen to recover 93% to 96% of the sulphur from a relativelyrich acid gas feed.

Planning a Tertiary Oil-Recovery Project for Jay/LEC Fields Unit

Summary A major tertiary oil-recovery project is planned for the Jay/Little Escambia Creek (LEC) fields to recover an additional 47 MMbbl of oil. Ultimate recovery from the deep carbonate reservoir is expected to reach 393 MMbbl, or 54% of the 728 MMbbl oil originally in place (OOIP). Introduction The Jay/LEC fields, discovered in 1970, produce oil from a carbonate reservoir in the Florida panhandle and south Alabama. The fields were unitized in 1974, and waterflood operations have been underway for 7 years. This sour-oil field has been recognized for some time as an ideal miscible displacement candidate because (1) the crude is miscible with nitrogen, methane, and CO, at reservoir conditions and (2) about 382 MMbbf of oil are expected to remain following waterflood operations. Continuous tertiary recovery studies began in late 1977, and the working interest owners approved the project in June 1980, after 8 man-years of technical evaluation. Reservoir questions receiving special attention included injectivity of water following gas injection in a water-alternating-gas (WAG) operation and remobilization of residual oil trapped in the reservoir following water injection. A field injectivity test showed reduction in water injectivity would occur, and laboratory tests showed essentially all waterflood residual oil in place will be recovered from reservoir rock contacted by miscible gas. Additional study showed that decreased water injectivity following gas injection would be offset by excess injection capacity and some injection string changeouts. Recovery and performance estimates and WAG ratios were based on results obtained with two- and-three-dimensional reservoir simulation of representative sections of the reservoir. A modified version of Exxon's General Purpose Simulator (GPSIM) was used. Detailed reservoir description gave confidence in simulation studies and was an important factor in the decision to forego a pilot test. Nitrogen was selected as the principal injection gas rather than methane because of economics and rather than CO2 because of availability and economics. It will be injected alternately with water at rates of 67 MMcf/D until about 20% hydrocarbon pore volumes (HCPV) have been injected. A period of about 15 years of gas and water injection will be followed by injection with water until depletion. Ultimate oil recovery should be increased some 47 MMbbl, or 6.5% of the 728 MMbbl of OOIP. Ultimate recovery now is expected to reach 393 MMbbl of oil. Nitrogen will be purchased from a supplier with subsequent compression to 7,600 psig and distribution by the unit to existing injection wells. Facilities include injection compression, a field-wide distribution system, and a nitrogen rejection unit. Electric motors will be used as prime movers. Total investment is estimated at about $80 million. Nitrogen injection is targeted to begin in Dec. 1981. Reservoir and Fluid Properties Oil accumulation at Jay/LEC is in the Smackover carbonate and Norphlet sand formations. Oil occurs mostly in the dolomitized portions of the Smackover carbonate. JPT P. 1535

Octyl salicylate

Helium is regarded as a vital gas to various industries such as medicine, aircraft manufacturing, electronics and fiber optics fabrication. Currently, natural gas reserves are considered the only viable resource for this rare element. When processing (helium-rich) natural gas, helium is generally recovered in the most downstream stage in conjunction with the nitrogen rejection unit (NRU). The feed to this unit is a nitrogen rich stream, and the product is either crude helium (50–70 mol% purity) or purified helium (99.99 mol% purity). Currently, the cryogenic distillation method is a common technology for a crude helium extraction unit (HeXU). The alternative method for this purpose is a membrane gas separation system, which is successfully used in other applications. This study aims to propose an energy-integrated scheme for each of the two helium separation technologies with a single-column NRU and to evaluate and compare them for different applications. Matlab programming has been used to model the membrane system and incorporate it into Aspen Hysys, which is used to simulate the rest of the process flowsheet. Next, the energy consumption of the systems was optimized using the particle swarm optimization method. An economic analysis was adopted to compare the two technologies for different applications in order to suggest a comprehensive map for HeXU technology selection.