Flare Gas Recovery A consideration of the benefits and issues associated with sizing, installation and selection of the most appropriate technology

Transcription

1 Flare Gas Recovery A consideration of the benefits and issues associated with sizing, installation and selection of the most appropriate technology Peter Angwin, Principal Consultant Process Engineer Stuart Leitch, Process Engineer Amec Foster Wheeler, Shinfield Park, Reading, Berkshire RG2 9FW, UK This paper considers the economic and environmental benefits of installing a flare gas recovery system using ejector technology. The paper covers the environmental, economic and safety benefits associated with installing flare gas recovery systems, and the relative advantages of the different technologies available are identified. Also considered are the challenges associated with flare gas recovery installations, including successful development of a sizing basis and identification of a suitable destination for the recovered flare gas. This paper describes Amec Foster Wheeler s recent project experience where the successful design of a flare gas recovery system using ejector technologies was completed. The key design decisions carried out by Amec Foster Wheeler during the project are discussed, focussing on the economic analysis carried out comparing ejector technology to liquid ring compressors. Why Flare gas Recovery Over 150 billion cubic metres of gas is flared or vented annually, worth approximately $30 billion. It is estimated that flaring results in some 400 million tonnes of greenhouse gas emissions per year (World Bank, 2014), exceeding the emissions of countries such as France or Australia. Flare gas recovery systems enable facilities to maintain zero continuous flaring during normal operation, leading to environmental, economic and safety related benefits. Historically, flare gas recovery systems were retro fitted to existing facilities where continuous flows to the flare can be measured. With greater awareness of the benefits of flare gas recovery and increasingly stringent environmental legislation, more and more new facilities are being specified with flare gas recovery units to be available at plant start-up. This leads to a need to develop a basis for sizing flare gas recovery systems and the selection of the best available technology. All continuous streams routed to the flare header can usually be recovered. Environmental benefits can include reduced NO x, SO x, CO and CO 2 emissions, smokeless operation of the flare system during normal operation, energy conservation through use of flare gas as fuel, and higher plant efficiency through reduced waste. Economic benefits include recovery of gas to be used as fuel gas or within the process, and reduced maintenance costs associated with continuous flaring. From a safety viewpoint, minimise flare tip damage associated with burning small continuous flows, and reduce toxic flare gas emissions while having no detrimental effect on the inherent safety of a plant flare system. Typical Arrangement Flare systems are safety systems and must always be available when required to operate in emergency situations. Flare gas recovery systems therefore must not prevent the flare providing this safety function in emergency situations. Flare gas recovery systems may be considered as the first stage of a staged flare system. Staged flares involve connecting two flare stacks to a single flare header. The first stage flare, normally of small capacity, handles the continuous flows and the route to the larger 2 nd stage flare is opened during major flaring events. The requirements for staged flares are detailed in API 521 and these should be followed in designing a flare system with flare gas recovery. The design of a flare system should always allow for the failure of the flare gas recovery system and flaring of the full range of possible flows into the flare header. Once flare gas recovery is decided upon, the design of a flare gas recovery system can progress independently of the design of the flare system. There are a range of configurations available to integrate a flare gas recovery system with the flare system. Typically, a seal drum or staging valve is located in the main flare header in order to divert the flare gas to the suction of the flare gas recovery unit. Due to the low pressures in the flare header during normal operation, the recovered flare gas must be compressed. Usually the seal drum or diversion valve are considered part of the flare system, and the flare gas recovery unit constitutes the compression stage. Figure 1 shows a typical arrangement for a flare gas recovery installation. Safety considerations There are a number of safety considerations associated with the installation of a flare gas recovery systems. 1

2 (1) Isolations in the main flare header The preferred choice of diversion device is a seal drum located in the flare header as this removes the requirement for placing any valves within the main flare header (API 521, 2014). Where staging valves must be used, a buckling pin bypass arrangement is provided to ensure a clear path to flare if the isolation valves fail to open when required. (2) Common Flare Gas Recovery units joining flare headers together A flare gas recovery system may recover flare gas from more than one flare header. This creates additional risks as the common flare gas recovery suction cross-connects the flare headers. Isolation is required on the line from each flare header to ensure the flares can remain segregated in event of flare gas recovery failure. Also during a flaring event, the flare header in use can be isolated from the flare gas recovery system. This avoids potential flow from one flare header to another, and possibly exceeding the design backpressure of flare systems with consequent reduction relief valve capacities. (3) Isolation of Flare Gas Recovery during upset operations Depending on the operating conditions within the flare headers, it may not be practical to design the flare gas recovery system and all downstream equipment for the worst case. Consideration needs to be given to: a) The worst case operating conditions in the flare including high pressures during major flaring events or low temperatures. b) The technology used in the flare gas recovery system e.g. liquid ring compressors where circulating fluid may experience temperatures below freezing. Trip isolation valves initiated on high pressure, low pressure, high temperature, and/or low temperature may be required to avoid the need to design the flare gas recovery system for extreme conditions. (4) Pulling a vacuum on the flare system The flare gas recovery system capacity is generally small compared to the flare capacity, and to the volume of the flare header. Because of this the flare gas recovery system is not capable of changing the pressure in the flare header very quickly. Generally the flare header pressure control will be independent of the flare gas recovery pressure control. However, it is possible for the flare gas recovery system to pull a vacuum in the flare header with consequent risk of drawing air and therefore oxygen into the flare header. The flare gas recovery capacity control normally prevents this by controlling the suction pressure, but additional safeguards should be provided. Typically these are additional flare purge points or isolation of the flare gas recovery, both on low flare pressure. Technologies Compression of the flare gas can be achieved through a variety of technologies. The most suitable compression technology and arrangement vary for every plant and must be determined on a case by case basis. The destination of the recovered flare gas is a key consideration, as the required pressure at the end user will determine the technology type and number of systems. (1) Compressors Traditionally one or two stage compressors are used, either a single compressor or multiple compressors in parallel depending on the capacity required. The majority of installations use liquid ring compressors due to their robust design and ability to handle acid gas of variable flow, composition and temperature. Screw and reciprocating compressors are not uncommon. Figure 2 shows a typical liquid ring compressor system. The benefits of using compressors include no dilution of the recovered product, familiar technology and higher achievable discharge pressure. Their disadvantages include increased maintenance due to the use of rotating equipment and a greater number of equipment items. Control and equipment safeguarding requirements increase with larger compressors or multiple compressors. For liquid ring compressors, the sealing fluid has to be selected, and a supply provided and controlled. Also a disposal route for a purge of seal fluid has to be provided to limit the build-up of contaminants in the fluid. Fluid selection depends on the gas being recovered and the destination. Typically water is used, but the recovered gas destination must be able to accept water vapour. Another common fluid is MEG (mono ethylene glycol) that has the advantages of low vapour pressure (high boiling point), low freezing temperature and low reactivity. It is also biodegradable. Heat of compression generally has to be removed, usually with cooling water but air cooling may be practical. 2

3 Consideration has to be given to the temperature and pressure in the flare header during a relief event. High pressure in the flare header and at the flare gas recovery compressor suction increases the compressor power requirement. Generally there should be a high pressure trip to shutdown the compressor, and the compressor suction design pressure is generally adequate to avoid overpressure issues. Compressor discharge relief valves are required for the blocked outlet case. High temperature in the flare has potential to vaporise the seal fluid of liquid ring compressors. Consequently high temperature in the flare header generally shuts down the flare gas recovery system. (2) Gas Ejectors An alternative technology which has been increasingly used in recent years is ejector technology. Gas ejectors work by passing a high pressure motive fluid, through an ejector nozzle, which draws and compresses the recovered flare gas. Figure 3 shows a typical flare gas recovery arrangement using a gas ejector. Gas ejectors are inherently safer than compressors due to their much simpler design, having no moving parts, minimal ancillary equipment and requiring little maintenance once installed. It is often possible to design the ejector for the full design pressure of the motive gas supply, removing the need for any relief valves within the flare gas recovery system. Also due to their low costs, a dedicated flare gas recovery system can be provided for each flare, to eliminate potential issues with cross connecting flares. Gas ejectors require a motive gas at a higher pressure than the recovered flare gas destination. The quantity of gas required can be significant, depending on the flare gas compression ratio required, and how much higher the motive gas pressure is compared to the destination pressure. Suppliers of ejectors can readily supply this information, and also provide tools to allow this to be calculated by process designers. The availability of a source of motive gas that is at a high enough pressure often limits the use of gas ejectors, as does finding a destination that can receive the flow of recovered gas plus motive gas. The discharge pressure of gas ejectors is limited, with a single stage gas ejector typically achieving compression ratios of 3:1 to 5:1, though up to 8:1 is practical (Transvac, 2014). Ejectors are designed for a specific operating point; suction pressure, motive gas pressure and discharge pressure. Deviation from the operating point in most cases reduces the capacity of the ejector. Turndown capability is therefore limited and capacity control is achieved by recycle from discharge to suction. (3) Liquid Ejectors Liquid ejectors operate in the same was as gas ejectors except the motive fluid used is a liquid. This is a relatively new technology that has advantages subsea where compression without moving parts is desirable. Liquid ejectors can achieve much higher discharge pressures than gas ejectors, with compression ratios of up to 150:1 quoted. Liquid ejectors require a supply of high pressure liquid, which then has to be separated from the recovered gas. For flare gas recovery a high pressure pump is generally used to supply the high pressure liquid, with the liquid being pumped from the separator vessel to the ejector. A typical system recovering gas to 4 barg requires a fluid at 50 barg. The heat of compression and the heat introduced by the pump inefficiency are removed by a heat exchanger. The advantages of liquid ejectors over gas ejectors come from the higher pressure ratios possible, and a source of motive gas does not need to be identified. However a liquid is introduced into the process with similar considerations to liquid ring compressors. The advantage of liquid ejectors over compressors is equipment reliability in that high pressure centrifugal pumps are generally simpler and a more reliable than compressors. Destinations A key aspect of flare gas recovery is having a destination and use for the recovered flare gas. Where flare gas has calorific value, the most common use is as fuel gas. The flare gas may contain components that would be detrimental to a fuel gas system (e.g. water vapour or acid gas), and in these cases the need for treating the recovered gas before it enters the fuel gas system needs to be considered. Alternatively the recovered flare gas can be handled in a dedicated fuel gas system supplying burners dedicated to burning flare gas. The advantage of this is that only recovery to a low pressure is required. The use of recovered gas as fuel generally has a monetary value equal to the fuel gas it saves. However it assumes there is a requirement for fuel, and the normal fuel requirement is bigger than that available from flare gas recovery. This is a more significant concern with flare gas recovery using gas ejectors as the motive gas adds to the volume of gas recovered. For low calorific value flare gas, recovery to fuel gas is not practical unless the quantity is small and some dilution of the fuel gas can be tolerated. Recovery to the process is the best solution, but if not practical disposal by incineration may be the only option. Generally there is no economic benefit of recovery to incineration, and therefore only be considered where flare gas recovery is provided to meet environmental requirements. 3

4 The selection of flare header purge gas should be made considering the destination of the recovered flare gas. Commonly used gases are fuel gas, which has high calorific value and is suitable when the recovered gas is used as fuel, or nitrogen. The use of nitrogen generally requires the recovered gas to be incinerated or used within the process. Routing the recovered flare gas back into the process may be viable but is dependent on a process that can accept a stream of variable and in some cases unknown composition. Also a destination in a process operating at relatively low pressure is preferable to a high pressure destination due to the cost of compression. In recovering to the process the possible build-up of any undesired species should be considered as flare gas recovery can effectively become a recycle. As well as cost, it is necessary to consider emissions when determining the optimum destination for the recovered flare gas. The installation of flare gas recovery may remove continuous flaring, however if the recovered gas is used as fuel or incinerated then the emissions are the same, though NO x will be reduced by the controlled combustion. Sizing basis Flare gas recovery systems are normally sized to recover only the continuous flows to flare headers, though sizing to recover known and regular intermittent flows may also be considered. Relief flows arising from emergency situations and intermittent flows are not normally recovered but are flared. To size a flare gas recovery system the continuous flows and any intermittent flows worth recovering need to be identified. The continuous flows to flare comprise: flare header purges leakage through control valves connected to flare leakage through relief valves connected to flare continuous vents from mechanical equipment (e.g. compressor seals) continuous process vents Estimation of continuous flows to flare are considered below: a) Flare Header Purges Flare header purges are provided to prevent oxygen ingress into the flare header and, to a lesser extent to sweep out potentially problematic gases (e.g. corrosive gases). Typically a velocity in the flare header of 0.03 m/s is maintained by the flare header purge. Note this is the purge rate of the headers. As the flare header is isolated from the flare stack, a separate purge of the flare tip is required to prevent air ingress through the flare tip. To be confident that the flare purge rate is as designed, each purge point should include a means of measuring and controlling flare gas flow. The system for the initial purging of the flare header on start-up should be a separate system as much higher flow rates are required. b) Control Valve Leakage Control valves connected to flare are generally for start-up, or shutdown, or for upset conditions to prevent an emergency situation (e.g. overpressure) arising. There are a number of sources for control valve leakage figures, though these are defined for valve testing and not immediately usable for calculation of flare gas recovery capacity. The most usable in this respect is considered to be ANSI/FCI However, the standard gives leakage for new valves, and deterioration in leakage performance will occur with use. To allow for deterioration in use, the multiplication of the ANSI/FCI 70-2 leakage rate by a Use Factor is proposed. Selecting a Use Factor value of 2.0 is considered an appropriate starting value, but this should be modified to reflect a number of factors including control valve maintenance intervals. Actuated isolation valves can be treated as control valves for leakage calculations, though different standards for leakage rates generally apply. c) Relief Valve Leakage Relief valve leakage rates are identified in API 527 (API 527, 2002) for different API orifice sizes. In practice, the relief rates quoted in API 527 are an order of magnitude smaller than the control valve leakage rates and hence are not usually significant in the overall flare gas recovery load. However, the rates quoted are for new or maintained valves where the plug is sitting properly in the seat. After a relief event where the valve opens this may not be the case. The leakage on a relief valve that is not seating properly will be significantly higher, possibly 0.5% of capacity as ANSI/FCI 70-2 (ANSI, 2006) Class 2 valve. However, as relief valves are generally spared and can be taken out of service for maintenance, any allowance in the leakage calculation can be small. 4

5 d) Mechanical Equipment Vents Mechanical equipment vents generally arise from seal systems on compressors or other rotating equipment which is connected to a flare system. Where equipment already exists, the leakage rate to flare should be available from equipment datasheets. These rates may be exceeded by a significant amount if the seal is not performing as designed, and seals are expensive to replace so operation with a leaking seal may be tolerated for a long time. Where a flare gas recovery system is being specified early in the design, equipment datasheets are unlikely to be available and an estimate of seal flow to flare has to be made. Selection of a value is essentially arbitrary but the value of 7 Nm³/h per seal has been used, and this is an order of magnitude greater than quoted seal vent rates. Choosing a large value also allows for potential excessive leakage from seals. e) Process Vents Process vents, continuous and intermittent, should be considered on a case by case basis. Typically continuous vents will be mass balance flows and flow rate will be known, whereas intermittent vent flows are unlikely to be mass balance flows (unless a cyclic process) and will need to be estimated. For continuous process vents, while the normal case mass balance flow may be known, any abnormal operating conditions may significantly change vent volume. For example a venting rate of 1% during normal operating may increase to 2% during abnormal operating. While this is a small change in the overall plant mass balance, it results in double the vent rate. It is therefore important to understand the plant operating cases, including abnormal and upset cases to establish the maximum process vent flow. Intermittent process vents to flare can either be recovered, and the flare gas recovery system sized for these flows, or the decision can be made to flare the intermittent flows. All intermittent flows should be identified and quantified, which flows may be coincident considered, and then the optimum flare gas recovery capacity determined. One of the key concepts in environmental engineering is, in priority order: reuse, recycle, recover, and dispose. Sending a process vent streams for flaring is least desirable as it is dispose. Flare gas recovery will recover the stream, but the stream is degraded by contamination from other flows into the flare header. Hence process vent flows, particularly if large or a significant proportion of the flare gas recovery capacity, should where possible be reused and not enter the flare header. This would also be considered good practice as an emergency system, the flare header, is not being used as part of the normal process. The nature of flows to the flare system mean that the accuracy of the values estimated can be low. Hence it is appropriate to apply margins to the calculated flows depending on their perceived accuracy. For example, the flare header purges can be controlled and hence only a small margin needs to be applied for inaccuracies in measurement or occasional mal-operation (e.g. 20% margin). Whereas the control valve leakage flow calculated, if a large Use Factor is used can be considered a maximum and no margin applied. The consequences of under sizing and oversizing a flare gas recovery system are: Under sizing An undersized flare gas recovery system will result in occasional or continuous flow to the flare tip. Depending on the degree of under sizing the flow may be small with potential for incomplete combustion at the flare tip, or flame sitting within the flare instead of being above the flare tip. This can significantly reduce the life of the flare tip. An additional issue is with the control. Where there is a staging valve, a small flow arising from under sizing flare gas recovery system is likely to be smaller than the valve can control. Hence the valve will over react giving an unstable flare header pressure. This will not be a problem with a seal drum. Oversizing An oversized flare gas recovery system is not a concern operationally. However, for a fixed capacity system where capacity control is achieved by recycling, the flare gas recovery system will be inefficient in energy use. The capital cost will also be higher. If variable capacity is achieved by a variable speed drive, the energy inefficiency will be less but the capital cost will still be high. The recommendation is to oversize flare gas recovery systems as the consequence of oversizing is unnecessary capital cost and energy consumption, whereas the consequence of under sizing will be ongoing operational issues. Project Experience Flare Gas Recovery for Gas Oil Separation Plant The Client required flare gas recovery to be retrofitted as part of an extension on an existing site. The reasoning was to improve environmental performance, as part of a companywide initiative to minimise flaring. The Client considered gas 5

6 ejectors appropriate technology and studies supported this, and identified the optimum configuration. The key aspect of this flare gas recovery system is that the recovered flare gas could be exported as product, giving the recovered gas a high monetary value. The principal operating cost was the recompression of the motive gas used for flare gas recovery. The options for using gas ejectors involved selecting the source of motive gas and the destination of recovered gas plus motive gas, and are shown in Figure 5. Options 1 and 2 involving recovery to the LP Compressor suction were rejected due to capacity constraints on the LP Compressor, though the economics would have been the most advantageous. The Options 3 with recovery to a higher pressure destination used significantly more motive gas but operationally was the only acceptable option. To confirm the technology selection, the economics of gas ejectors and liquid ring vacuum pumps were compared with recovery to the suction of the HP Compressor. The economics gave a shorter payback for the ejector, due to the lower capital cost, though the compressor gave a better NPV (net present value) over the project life due to the reduced electrical power consumption. For this installation, the flare gas recovery was located at the opposite end of the flare header to the flare gas knock-out drum. This allowed the installation to be in the construction area for the plant extension. It also avoided long motive gas and recovered gas lines that would have been required if located adjacent to the flare knock-out drum. An additional aspect is that the flare gas recovery is installed above the piperack to allow the pipework to be self-draining into the headers to avoid any condensate collecting. In this case there are two flare headers in normal operation that are provided with dedicated flare gas recovery system, thereby avoiding any interaction between flares. Flare Gas Recovery for Gas Treatment Plant The client required the installation of a flare gas recovery unit as part of a grassroots gas processing facility to prevent continuous flaring during normal operation. All recovery options and technologies were considered. Recovery of the flare gas back into the process was not considered viable as the lowest process operating pressure was in excess of 40 barg. Recovery to fuel gas was therefore selected. The continuous flows to the flare headers included process vents from stripping columns where the stripping fluid was fuel gas. The vent streams were sour, typically containing 20 mol% acid gas and therefore direct use as fuel gas was not practical. Sweetening of the recovered flare gas was selected, using amine from the AGRU (Acid Gas Removal Units) in a contactor provided specifically for recovered flare gas. The rich amine from the contactor was returned to the AGRU for regeneration. Once sweetened, the flare gas entered the fuel gas system to the AGRU Incinerators. A block flow diagram is shown in Figure 6. These process vent streams made up the largest proportion of flare gas to be recovered, and difficulties were encountered in getting process licensors to accurately quantify these streams, holding up flare recovery system sizing. The selected technology for flare gas recovery was two stage liquid ring compressors as gas ejectors could not provide the compression ratio without excessive motive gas requirement such that the requirement for fuel gas was exceeded. Recovery to dedicated burners within the AGRU incinerator operating at low pressure to minimise the quantity of motive gas required was considered. However this was rejected as the acid gas level was too high and would have required flue gas treatment to meet environmental SOx limits. Multiple compressors in parallel were required due to the recovered gas flow rate and this required the development of a flare gas recovery capacity control system using gas recycle from compressor discharge to suction. Safeguarding systems to shut down the flare gas recovery compressors during flaring events were also implemented, with shutdown being initiated by high flare pressure or temperature. Conclusion The drivers for flare gas recovery are environmental and economic. Implementation has to be considered case by case because of the diverse nature of process plants and the different flare gas recovery technologies available. In implementing flare gas recovery, the flare system has to be designed to accommodate flare gas recovery, and must allow flaring of the full range of possible flows into the flare header in the event of flare gas recovery failure. This is essential so as not to compromise the safety function of the flare system. Of the technologies available for flare gas recovery (compressors, gas ejectors, and liquid ejectors) each has advantages, disadvantages and constraints. However the main driver for selection of technology is often the destination available for the recovered flare gas. From the economic standpoint, gas ejectors frequently have advantage due to their low capital cost and simplicity, but have the most constraints in choosing a destination for the recovered gas. The cost and operational aspects associated with compressors generally mean other solutions are preferred. Liquid ejectors are relatively new but offer advantages, but need to be more widely accepted. References AMERICAN NATIONAL STANDARDS INSTITUTE CONTROL VALVE SEAT LEAKAGE ANSI/FCI AMERICAN PETROLEUM INSTITUTE API STANDARD 521 PRESSURE RELIEVING AND DEPRESSURING SYSTEMS. 6

7 AMERICAN PETROLEUM INSTITUTE API STANDARD 527 SEAT TIGHTNESS OF PRESSURE RELIEF VALVES. TRANSVAC TRANSVAC EJECTOR SOLUTIONS. [Online] WORLD BANK WORLD BANK GLOBAL FLARING REDUCTION PARTNERSHIP. [Online] Figure 1 Typical flare gas recovery installations Figure 2 FLARE GAS RECOVERY package using liquid ring compressors 7

8 Figure 3 FLARE GAS RECOVERY package using gas ejectors Figure 4 FLARE GAS RECOVERY package using liquid ejectors Figure 5 GOSP Flare Gas Recovery Options 8

9 Figure 6 - Flare Gas Recovery for Gas Treatment Plant 9