美国石油工程师协会-LNG工艺介绍 LNG for PE Paper - SPE 133722.docx

SPE 13372211 SPE 133722LNG for Petroleum EngineersMichael S Choi, SPE, ConocoPhillipsCopyright 2010, Society of Petroleum EngineersThis paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Florence, Italy, 1922 September 2010.This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.AbstractWhile remote parts of the world are awash with hundreds of trillions of cubic feet (Tcf) of natural gas, the industrialized West and emerging economies of the East cant get enough of the clean-burning, environmentally friendly fuel. The problem is transporting this compressible fluid long distances, across major bodies of water. For markets greater than 1,500 miles, liquefied natural gas (LNG) has proved to be the most economic option. By refrigerating natural gas (primarily methane) to -260ºF (-162ºC), thereby shrinking its volume by 600:1, LNG can be transported in large insulated cryogenic tankers at reasonable cost.Natural gas liquefaction is a series of refrigeration systems similar to the air conditioning system in our homes consisting of a compressor, condenser and evaporator to chill and condense the gas. The difference is in the scale and magnitude of the refrigeration. A typical single-train LNG plant may cost $1.5 billion and consume 6-8% of the inlet gas as fuel. Since many of the impurities (water vapor, carbon dioxide, hydrogen sulfide, etc.) and heavier hydrocarbon compounds in natural gas will freeze at LNG temperatures, they must first be removed, and disposed or marketed as separate products. This paper will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading. However, the focus is on the liquefaction process and equipment. Differences among the commercially available liquefaction processes (cascade, single mixed refrigerant, propane-pre-cooled mixed refrigerant, double mixed refrigerant, nitrogen, etc.) will be discussed. The aim is to provide SPE members with a clear understanding of the technologies, equipment and process choices required for a successful LNG project.IntroductionThe liquefied natural gas (LNG) industry is currently experiencing explosive growth. There isnt an oil and gas exporting country that doesnt have a LNG plant in the planning stage or under construction. The Arab State of Qatar alone will be bringing on 50 million metric tons per year (Mtpa) of production in the next 3 years. This is equivalent to about 6.6 Bscfd of pipeline gas. In addition, new projects in the Atlantic Basin, Asia Pacific and Middle East could well double that figure in the same time frame. The excitement is driven by the convergence(集合) of technology and market. There are reportedly 2,500 Tcf (420 Billion BOE) of known natural gas reserve stranded(搁浅) in remote areas. The barrier to taping this abundant source of clean energy has been the cost of liquefaction and shipping. With recent advances in liquefaction technologies and rising natural gas price, the time has finally arrived for LNG to be economically attractive to both producer and consumer.Air Products & Chemicals Inc.s (APCI) Propane-precooled Mixed Refrigerant process has dominated base load LNG technology with about 75% of the existing plant capacity. However, revitalization(新生,复苏) of the Phillips Optimized Cascade process in the past decade, along with development of the Linde/Statoil Mixed Fluid Cascade, Shell Double Mixed Refrigerant, APCI APX and other processes, has given producers options. The competition has fostered innovations in plant design, train size and equipment utilization. This paper will discuss the gas pretreatment required, thermodynamics of natural gas liquefaction, features of the different liquefaction processes and the major equipment used.DiscussionNatural gas, unlike oil, is compressible and occupies huge volumes at atmospheric pressure. The most economic means of transporting the fuel to market is through high pressure pipelines. As a result, the gas industry was developed primarily around regional or intra-continental pipeline networks. Up until the 1940s, there was no intercontinental or trans-ocean trade of natural gas. In the 1960s, Japan, an island nation, began importing LNG in limited amounts. By refrigerating to about -260°F (-162°C) through various means, natural gas (which is primarily methane) is transformed into a liquid, thereby shrinking its volume by 600:1. The liquefied natural gas which has a specific gravity of only 0.45 is transported by large ocean-going tankers. Typical capacity of these highly insulated cryogenic tankers is about 145,000 cubic meters. They carry the equivalent of 3.1 Bscf (87 million cubic meter) of gas, or about 512,000 BOE (81401.34M3). Figure 1 is a photo of such a LNG tanker being loaded at the Oman LNG plant year 2000.1 US Barrel (oil) = 158.987 litersFigure 1 - Oman LNGFrom year 2000 to 2010, LNG trade worldwide nearly double to 175 Mtpa as new plants in Trinidad, Nigeria and Qatar came on-stream. With increasing demand for the clean-burning fuel, LNG has no problem finding a market and in most cases, commanded a premium price. This led to a boom in LNG plant construction. At the current time, there isnt an oil and gas exporting country that doesnt have a LNG plant in the planning stage or under construction. With reportedly 2,500 Tcf (420 Billion BOE) of known gas reserve stranded in remote areas that require ocean transport to market, LNG will surely continue to contribute toward the growth of the natural gas industry.To many petroleum engineers whose main focus is finding and getting hydrocarbons out of the ground, LNG is a bit of a mystery. The plants are huge, with tall columns resembling refineries serviced by our downstream colleagues. In fact, many of these columns serve the same purpose as those in the refinery. Some of them are absorbers, while some are distillation columns. However, they have nothing to do with the function of liquefying natural gas. They are there primarily to condition the produced fluid for liquefaction. An LNG plant would simply be a big refrigeration system if the reservoir is able to produce pure methane (no water vapor, hydrocarbons or other impurities). The refrigeration system would consist of the same major components as the air conditioning (AC) system in our home. It would have a compressor/driver, refrigerant condenser and evaporator (the process heat exchanger). The liquefaction equipment in an LNG plant would only differ from a home AC system in size and operating temperature.However, Mother Nature is never that simple. All produced gas is saturated with water vapor and would freeze and plug heat exchangers at cryogenic temperatures. In addition, reservoir gas typically contains varying amounts of H2S, CO2, mercury and heavy hydrocarbons. In order to meet customers specifications and prevent damage to liquefaction equipment, plant inlet gas would go through a series of pre-treatment steps. Figure 2 is a block flow diagram of a typical 2-train LNG plant showing these pre-treatment steps.Figure 2 LNG plant block flow diagramInlet Gas Reception 来气接收would at a minimum consist of pipeline manifold and an inlet separator. To accommodate offshore production or long production flowlines, pig receivers and a slug catcher may also be required. Water separated in the slug catcher and/or inlet separator would be treated and disposed. Hydrocarbon liquids would be sent to Condensate Stabilization.Condensate Stabilization 凝析液稳定would consist of a multi-stage fractionation column and a vapor compressor. Typical specification for the stabilized condensate is 10 psia Reid Vapor Pressure (RVP). RVP is the vapor pressure of the condensate at 100°F determined by the Reid method. Overhead vapor from the stabilizer is recompressed and sent back to commingle with (混合) separator gas for further processing. For sour produced fluids, the concentration of mercaptans(硫醇) in the stabilized condensate may be high enough to necessitate a de-odorization(去味) system. The same may apply to total sulfur content. However, the price differential between high and low sulfur condensates usually does not justify the cost of desulfurization of the condensate. Desulfurization can be more economically achieved at the refinery.Inlet Gas Treating is a prerequisite for natural gas liquefaction. H2S concentration must be reduced to less than 4 ppm to meet typical gas sales spec. CO2 must be less than 50 ppm to avoid freezing and deposition in the cryogenic heat exchangers. An amine system is typically employed to remove both H2S and CO2 from the inlet gas. If more than 50 tons per year of H2S is removed, it will have to be converted to elemental sulfur in a sulfur recovery unit (SRU). Since most host countries have regulations that specify recovery of 99.5%+ of all sulfur compounds, a Claus off-gas clean-up system will also be required along with the SRU. Most countries, at the current time, allow CO2 venting (unlimited amount) and atmospheric discharge of SO2 up to 100 tons per year. Therefore if total amount of sulfur (H2S) in the inlet gas is adequately low, acid gas (H2S & CO2) from amine regeneration may be incinerated and discharged into the atmosphere.Most cryogenic heat exchangers are made of aluminum. Mercury is very corrosive to aluminum even in small quantities and must be removed prior to exposure. Because the consequences are so serious, LNG plant operators will typically install a mercury removal system. Mercury adsorption guard beds are non-regenerative and are sized for the amount of mercury expected between change-outs. Another must-have pre-treatment is molecularecular sieve dehydration. Water vapor concentration must be reduced to less than 100 ppb to avoid freezing at cryogenic LNG temperatures. To reduce load on molecular sieve beds, sweet inlet gas is usually first cooled by the first stage of refrigeration. Bulk of the water vapor will condense and be removed by separation, thus reducing the size of the more costly molecularecular sieve dehydration system.LPG Recovery can be as simple as a scrubber or knock out drum after one or two stages of refrigeration, depending on gas composition and vapor-liquid equilibrium. The purpose is to condense and remove the butanes and heavier hydrocarbons in the gas to prevent freezing in the low temperature parts of the cryogenic process. For gas with high ethane content, a turbo-expander LPG recovery system may be necessary to achieve the high propane recovery, sometime as high as 99%+, that is required to meet US and European heating value limits. Most US and European buyers limit gross heating value at 1,070 btu/scf. Typically, there are also limits on Wobbe index and nitrogen content that prevent reducing heating value through dilution with nitrogen. Ethane is usually left in the LNG with the methane since it is difficult to transport as a separate product due to its high vapor pressure and poor economics to do otherwise. Therefore very high propane recovery is required to allow significant amount of ethane to remain in the LNG and still meet heating value limit.LPG Fractionation is often required to handle the recovered LPG. After LPG is extracted from the gas, methane and ethane in solution with the liquid product will have to be removed. A de-ethanizer column is needed to fractionate (separate) out these light ends. De-ethanizer overhead vapor, containing the methane and ethane, is recompressed and sent to liquefaction along with the lean gas. Depending on marketing strategy, the raw LPG stream (de-ethanizer bottoms) may have to be fractionated into separate products. If separate propane, butanes and condensate (containing the pentanes and heavier compounds) products are desired, 2 more columns in the form of de-propanizer and de-butanizer are required. Depending on the relative amount of iso-pentane, normal-pentane and heavier hydrocarbons, a de-isopentanizer may also be needed to reduce the RVP of the condensate product to 10 psia. Commercial grade propane limits ethane content to 2% by volume and a vapor pressure of 200 psig at 100°F, and contains a minimum of 95% propane. Butanes product must be at least 95% and have a vapor pressure not to exceed 70 psig. Both propane and butanes are limited to less than 0.5 ppm H2S and 15 ppm of total sulfur compounds. Since what little amount of H2S and sulfur that may have escaped through the amine system (Inlet Gas Treating) tends to concentrate in the propane and butanes, these products may require further treating by molecularecular sieve adsorption to meet sulfur specifications. Molecularecular sieve regeneration gas, containing the removed sulfur compounds, is usually sent to the amine system in the Inlet Gas Treating section for handling.LNG Storage is by far the single largest item in a plant. Figure 3 shows a typical LNG tank farm. Storage capacity is based on the volume of a tanker plus perhaps 4 days of production. Majority of the LNG tankers built in the last decade has capacity in the 140,000 cubic meter (M3) range. New class of “super” tankers QMax and QFlex, designed for long haul trade of 10,000+ miles (i.e. Qatar to US or Europe around the Cape of Good Hope) can be as large as 250,000 M3. At the current time, the largest LNG tank available is in the range of 180,000 M3. Its dimensions are approximately 75 m diameter x 40 m high. Most LNG plants will have 2 or more storage tanks in order to meet the tanker load requirement and swing volumes needed between loadings. Figure 3 Typical LNG tank farm Figure 4 Schematic of full containment LNG tankLNG tank design has gone through an evolution toward greater safety and space efficiency. Early tanks were “single containment” and then “double containment” types. Most operators have opted for the “full containment” design. The full containment type tank has an inner tank made of 9% nickel steel. It is the primary cryogenic liquid barrier. Then there is an outer shell of post-tensioned concrete.