Middle East Economic Survey

VOL. LI

No 5

4-February-2008

GCC/REGIONAL

Introducing Flexibility into LNG Plant Operation

By Peter Carnell, Adrian Lawrence and Vince Atma Row

This paper was presented at the 6th Doha Conference on Natural Gas, held 29 October-1 November 2007 in Doha, Qatar, by Vince Atma Row, Product Manager, Gas Processing and Refineries at Johnson Matthey Catalysts. It was authored by Mr Row and his Johnson Matthey colleagues Peter Carnell and Adrian Lawrence.

Abstract

Historically gas has been produced and consumed locally. This has resulted in significant differences in the product specifications set by the customers. The emergence of gas as a global source of energy will inevitably result in demands for greater flexibility. The gas processing and liquefaction stages will have to be able to handle changes in raw gas composition as plant life is extended by the introduction of new fields. Environmental and metallurgical constraints will impose limits on gas purity throughout the processing plant. Spot sales of gas to different markets introduce problems in meeting the higher heating values (HHV) and the Wobbe Number.

Modern fixed bed absorbents allow the removal of mercury from raw gas and thus avoid environmental and metallurgical problems throughout the plant. Integration of fixed bed technology with conventional wash processes allows flexibility and energy savings on the acid gas removal plant. Catalytic Rich Gas (CRG) technology allows control of (HHV) and Wobbe number on both the producing plant and the receiving terminal. This paper shows how the application of existing technology can lead to savings in operating costs and give more flexibility in meeting differing market demands.

Introduction

The first supplies of gas were derived from coal and production and distribution was restricted to urban areas using low pressure storage and distribution systems. The emergence of natural gas provided an alternative source of fuel but again the initial use was localized. The development of high pressure gas pipelines allowed the establishment of extensive distribution networks and this in turn lead to the introduction of tight gas specifications. However, although all of the gas specifications cover the same general characteristics such as heating value, burner performance, corrosion prevention and avoidance of liquid drop out, there is no universal standard and there are significant regional variations. This was not a problem as long as the different regions were isolated. The development of long distance pipelines and more importantly LNG has allowed inter-region trade and brought with it problems in compatibility. This is highlighted by the variation in higher heating value (HHV) set by the major gas consuming markets.¹

The plants built to provide pipeline gas and LNG tended to be supplied from a large gas field. This meant that only a limited range in gas composition was likely and the plant design was relatively simple. The declining gas supplies in the North Sea have called for a fresh approach. Thus on the SAGE project 1,150 MMscfd of sour gas and 60,000 b/d of NGLs is produced from three fields of widely differing composition.² Four of the many gas compositions are shown in Table 1. An additional complication was the addition of a gas stream containing some mercury, which required the installation of a separate mercury removal unit (MRU).

Flexible Gas Sweetening

Conventional wash processes can be used to remove H₂S down to a few ppm and down to a few tens of ppm of CO₂. However, the size of the wash systems process plant precludes flexible operation and they are most efficient when operating under steady state conditions. Considerable flexibility can be achieved by the use of a “roughing/polishing” approach. The SAGE plant uses the BASF activated MDEA (aMDEA) process for the bulk removal of CO₂ and H₂S with multiple injection points on the absorber column to cope with varying gas compositions. The plant design allows for the handling of feed gases up to 11 mole % CO₂ and 20ppm H₂S. It is important not to remove all of the CO₂ from the sales gas as it has to meet the National Transmission System (NTS) calorific value and Wobbe Index specifications.

The CO₂ content is controlled by either bypassing some of the gas around the aMDEA absorber or adjusting the aMDEA process to slip the required CO₂ from the absorber overheads. The first method of controlling sales gas CO₂ is used at high plant throughputs and may result in too much H₂S in the sales gas. In this case part of the gas is passed through fixed beds containing PURASPEC absorbents for the total removal of H₂S. At low feed gas rates, the aMDEA unit can be run alone to meet the CO₂ and H₂S specifications. This combination of processes technologies allows gas to be produced to meet NTS or LNG specifications from almost any feed gas. The installation of a fixed bed PURASPEC reactor involved only a modest increase in CAPEX but brought with it considerable benefits in flexibility.

Adjustment In Higher Heating Value (HHV)

The early LNG plants were constructed to provide gas to meet a specific regional gas market. In its simplest form the LNG tanker was replacing a gas pipeline connecting the gas processing plant with the gas market. The LNG was produced to match the combustion characteristics of a specific market. The burgeoning LNG market now means that “spot” sales for LNG are now possible but this is complicated by the regional differences in the domestic gas markets. The two parameters of most concern are the Higher Heating Value (HHV) and Wobbe Index. Raising the HHV can usually be achieved by the addition of LPG. Lowering the HHV is more complex in that either NGLs must be removed or an inert gas like nitrogen must be added. In general it is easier to raise the HHV than to lower it. In many ways it offers more marketing flexibility for the LNG producer to produce low HHV LNG.

Raw gas compositions can vary widely and although the acid gas removal (AGR) unit can be designed to manage variations in CO₂ and H₂S, disposal of NGLs is harder to control. Most LNG plants are in remote locations with little immediate use for NGLs. LPG is marketable but ethane is more of a problem. Vapor pressure limits restrict the ethane content of LPG. The UK and Californian specifications limit the ethane to 6% of LNG and if the raw gas contains more than 8-9% ethane then the ethane must either be used within the plant or exported. As a general rule an LNG plant uses around 10% of the raw gas as fuel. If the raw gas contains 9% ethane then the resulting fuel gas will contain 36% ethane and will be too rich to meet the NOx emission limits of the larger gas turbines.

An interesting possibility is to use the “Catalytic Rich Gas” (CRG) process to convert the higher hydrocarbons into methane. This was developed by British Gas in 1968 and is sold under license by Davy Process Technology using Johnson Matthey catalysts. This process was developed to allow the manufacture of pipeline gas from naphtha but is even better suited for the conversion of low molecular weight hydrocarbons to methane. The process starts with the steam reforming of the hydrocarbon to give hydrogen and carbon monoxide which coupled with the shift reaction gives hydrogen and carbon dioxide. Hydrogen is then reacted with carbon monoxide to give methane and water.

The overall reactions for ethane, propane, butane and pentane are:

4C2H6 + 9H2O = 7CH4 + 7H2O + CO₂

2C3H8 + 7H2O = 5CH4 + 5H2O + CO₂

4C4H10 + 19H2O = 13CH4 + 13H2O + 3CO₂

C5H12 + 6H2O = 4CH4 + 4H2O +CO₂

Ethane is the most of efficient hydrocarbon for methane conversion with a reforming temperature of 300° to 350°C. Not only does the process allow for the de-richment of LNG but also increases the methane yield.³ The operation of a plant supplied with a CRG conversion unit has considerable flexibility. Thus the quality of the LNG produced can be adjusted by tuning the fraction of the de-ethanizer overhead stream sent for conversion and, given segregated storage tanks, can supply different markets. The CRG process can be incorporated in either the producing or receiving terminals. On the liquefaction plants the CRG process can be used on part of the raw gas or on one of the overhead fractions and the product as can be returned to the feed to the acid gas removal plant. De-richment can be achieved by NGL removal but studies in the UK have shown that rich LNGs (Nigeria and Indonesia) would require 85% of the gas to be processed for ethane removal to meet the sales specification and there would be a flow reduction of 10%. Nitrogen ballasting can be used but this requires a cryogenic air separation unit and Wobbe Index limits the extent of ballasting. The CRG option offers greater flexibility to maximize gas production but does involve a higher investment.

Dealing With Mercury Issues

Almost all hydrocarbons contain mercury. In the case of natural gas and natural gas liquids it is likely to be present as elemental mercury. In the case of crude oil it may also be present as organo-metallic and ionic mercury. The concentration of mercury in natural gas varies widely from 450 to 5000 in some fields in North Germany to less than 0.01 μg/Nm³ in some parts of the US and Africa. Reported levels of mercury found in some well known gas fields are given in Table 2. Mercury has a high boiling point (356.7 °C) but has a high vapor pressure at ambient temperature and is surprisingly mobile.

Although the levels of mercury recorded are low, the tonnages of liquid hydrocarbons handled are enormous so downstream processing equipment is exposed to a substantial amount of mercury. Thus a typical 10,000 tes/day LNG plant would use 600mn cfd of natural gas and if this contained 100 μg/Nm³ mercury the plant would receive 582kg mercury per year.

The main concerns are:

• Corrosion of process equipment.

• Exposure of workers to high levels of mercury during maintenance operations.

• Difficulty in disposal of mercury contaminated equipment.

• Emissions to the environment.

• Potential liabilities resulting from mercury contaminated product streams.

These can cause serious financial losses for the plant operator. Most LNG plants have mercury removal units (MRU) but these are normally installed immediately after the molecular sieve dryers to protect sensitive cryogenic equipment. However, this ignores the problem of mercury emissions from the Acid Gas removal units and dryer regeneration vents, the presence of mercury in NGLs and the contamination of process equipment. Many operators are setting a limit on the level of mercury in LPG and naphtha for use on petrochemical plants. Plant surveys have shown that around half of the mercury present in the raw gas is lost through vents or in NGLs.

Johnson Matthey has developed a range of fixed bed absorbents that can be used for the removal of mercury from raw gas at the very start of the LNG plant, thus producing a mercury free plant. These employ completely inorganic components and so can be recycled through the metal recovery industry. These new materials can be used in radial flow reactors giving substantial savings in pressure drop.

Conclusion

The global market for natural gas is growing rapidly. However, regional variations in sales specifications restrict the scope of suppliers to freely market gas. There are signs that more uniform gas specifications will be adopted in the future but this will be a slow and lengthy process and in the short term producing plants will need greater flexibility. Environmental issues are also coming to the fore with concerns over emissions and disposal of waste products. The addition of relatively simple equipment to the design of LNG and gas processing plants can greatly increase the flexibility to process complex feeds and meet differing market specifications. The modifications proposed involve the use of fixed bed technology that has the advantages of low capital costs and minimum operating requirements.

References

1.         Coyle D de la Vega, F F and Durr C, “Natural Gas Specification Challenges in the LNG Industry” LN15.

2.         Carnell P, J H , Joslin K, W and Woodham, P “Fixed-Bed Processes Provide Flexibility for COS and H₂S Removal” 74^th Annual GPA conference, San Antonio, 13-15 March 1995.

3.         Chretien D, “Process for the Adjustment of the HHV in the LNG Plants”, 23^rd World Gas Conference, June 2006.

Table 1

Range of SAGE Feed Gas Compositions Used as Design Basis

Table 2

Reported Levels Of Mercury In Specific Gas Fields