There are onshore tank BOG recovery facilities, but they are not designed to handle ship- .... refrigeration in the LNG tanks is preserved in the ballast voyage.
BOG RECOVERY FROM LONG JETTIES DURING LNG SHIP-LOADING Stanley Huang Staff LNG Process Engineer Chevron Energy Technology Company Houston, Texas, USA John Hartono LNG Operations Advisor Chevron Shipping Company, San Ramon, California, USA Pankaj Shah Team Leader – LNG Project Support Chevron Energy Technology Company, Houston, Texas, USA
ABSTRACT The selection of an LNG production site should consider, among other issues, plant plot layout and exporting port requirements. An ideal site would have a relatively large flat land for LNG production and storage, and a shoreline with deep water to accommodate large LNG ships. Generally, these requirements are difficult to achieve simultaneously at a given site. It is not uncommon that one has to deal with long jetties which may run several kilometers from LNG tanks to ship berths. Long jetties result in higher pumping energy, and heat leakage via the long LNG lines. Consequently, the boil-off-gas (BOG) generation rate during ship loading is relatively high. Furthermore, transferring large volumes of BOG at low pressures across long jetties is fairly costly. The combined effects make it uneconomical to recover BOG from long jetties. There have been examples in which ship loading BOG was flared at ship berths. However, as environmental regulations become more stringent, flaring of BOG during ship loading is not a viable option. This paper describes various BOG recovery and management alternatives suitable for long jetties. Methods of recovering BOG are reviewed together with discussions on their pros and cons. Examples include high pressure or low pressure transferring of BOG to LNG plant for final recovery, in-situ re-liquefaction, and in-situ power generation. The feasibility of the alternatives will be considered from perspectives of process efficiency as well as marine limitations. The guidelines in this paper will serve as useful reference for future LNG projects.
PO-34.1
INTRODUCTION Boil-off-gas (BOG) generation and recovery in a receiving terminal is well established. However, BOG handling and recovery in a liquefaction plant offers some interesting challenges. During normal operation of a natural gas liquefaction facility, BOG is produced due to the following: 1. Heat leak into the LNG storage tanks and piping 2. Flashing of the LNG in the tank and 3. Heat input from plant LNG pumps. This mode of operation of the liquefaction plant is known as holding mode operation. BOG generated during the holding mode is compressed and typically used as fuel gas. During LNG ship-loading additional BOG is produced due to the following: 1. Initial chilling of the ship tanks 2. Vapor displacement from the ship tanks 3. Heat leakage through piping and vessels and 4. Energy input from LNG loading pumps The BOG from the first two factors during ship-loading is dependent on the ship characteristics. However, the BOG production from last two factors is proportional to the jetty length. When the jetty is short, the ship BOG generation is relatively minor. The gas can be flared, or returned to onshore facilities where it can be recovered. In scenarios where long jetties are required, BOG management poses some challenges. Long jetties imply long LNG loading lines which, in turn, result in higher pumping energy and heat leakage. Consequently, the ship-loading BOG generation rate will be significantly higher compared to the holding mode BOG generation. Furthermore, moving large volumes of low-pressure BOG across long jetties is relatively costly. The combined effect generally makes it economically unattractive to recover BOG from long jetties. There are several instances where ship loading BOG is flared at shipping berths. However, as environmental regulations become more stringent, flaring of BOG during ship loading is not a viable option. Each LNG project has its unique features which should be considered during the design phase of BOG recovery systems. These items include the plant capacity, loading frequency, potential for simultaneous loading, availability of incremental feed gas, flexibility of plant operation and marine operational preferences. One of the first considerations in designing a BOG recovery system is the final destination of the recovered BOG. For example, the BOG can be used as fuel gas or as feed gas to the cryogenic section. Alternatively, it can be recovered as LNG to either onshore storage or ship tanks. The pros and cons of each option should be analyzed from the process plant owner’s perspective. Another key consideration in the design of the BOG recovery systems is related to the marine aspects. It is a common observation that limited understanding and misconceptions of the marine aspects result in designs that
PO-34.2
could fail to take into consideration the impact of the liquefaction plant equipment design and operation on the ship side. The characteristics of LNG ship-loading operation are totally different from those of ship-unloading at receiving terminals. These differences should be recognized in design of the BOG recovery systems. A third major consideration in the design of the BOG recovery system is related to the characteristics of different BOG recovery systems. The recovery systems may have different methods of generating, utilizing, and storing refrigerant. For example, there are commercial packages available to provide instantaneous refrigeration for liquefying the BOG, or to take BOG as feed stream to packages for LNG production. Alternatively, it is possible to provide liquefied nitrogen (LIN) or air (LAR) packages for liquefaction of BOG during ship loading while producing and storing LIN or LAR during holding mode. This paper discusses the different considerations for the evaluation of the BOG recovery options. BACKGROUND Baseline Operation Scenario Figure 1 shows the schematic of the overall LNG plant layout relative to the marine facilities. Ship loading is a relatively complex operation and requires quite a few operators. The machine maintenance, power supply, and provision of purging nitrogen demand a sizable plot area. For the purpose of this paper, it is assumed that there is space to accommodate relatively small BOG compressors (e.g., about 2 MW in total duty) at the berth area. This assumption should be verified for specific projects. Possible installations at BOG recovery area: 1. Heavy BOG compression; 2. Refrigeration generation; 3. Refrigeration storage; 4. NRU modules L
N
G
Berth Jetty or Causeway
LNG Tank Area Possible installations at berth area: 1. Primary BOG compression; 2. Exchanger for condensing BOG; 3. In-situ power generation
LNG Process Area
Figure 1. LNG Ship-loading Facilities with Possible Installations of BOG Recovery Equipment at Specified Locations The LNG plant as depicted in Figure 1 can be viewed as a black box of heat pump. The plant takes in feed gas, uses mechanical work to reject heat to the environment, and outputs LNG to be loaded to ships. Hence, the total plant throughput as measured in LNG shipped is proportional to the total refrigeration capacity of the plant. Accordingly, if the provided BOG recovery package includes its own refrigeration capacity, the total plant throughput will increase. On the other hand, if the recovery package only provides recompression for the BOG, then the plant throughput will stay roughly the same because the re-compressed BOG will compete, against the feed gas, for the available plant refrigeration. PO-34.3
A typical natural gas liquefaction process is depicted in Figure 2. Sweet, dry, and prechilled natural gas goes into the cryogenic section of the LNG plant. The heavies are removed to meet LNG heating value specifications and to prevent possible freeze-out of components, such as benzene at cryogenic temperatures. The lean, high-pressure, liquefied natural gas stream typically goes through plant Nitrogen Rejection Unit (NRU), sub-chilling section, before entering the LNG storage tanks. During the plant holding mode, the flashed gases from NRU and BOG from LNG tanks are collected and compressed to the plant fuel gas system. FLARE (DESIGN BASELINE) Notes: 1. Stream 4 includes contributions of flashed gas , heat leaks, and vapor displacement of produced LNG . Impacts of ship-loading is not included . 2. Stream 6 includes contributions of pumping , heat leaks, and vapor displacement of loaded LNG . It is assumed to be flare at berth site .
HOLDING MODE
LOADING MODE
SHIP BOG
FUEL GAS
3 6 4 TANK BOG
PRECHILLING
N2 REJECTION
SWEET, DRY GAS
1 GAS CHILLING, HEAVY REMOVAL & LIQUEFACTION
2 SUBCHILLING
LNG
LNG
5
IN-TANK LNG ACCUMULATION
ONBOARD LNG ACCUMULATION
FRACTIONATION SECTION
PLANT CONDENSATE
Figure 2. Baseline of Design The loading mode operation is also shown in Figure 2. The ship BOG is shown totally flared at the berth area. No plant resources are redirected to its recovery. As an option for plant operators during this mode, the temperature of the LNG entering onshore tanks may be raised slightly to compensate for the vapor replacement need of the tanks. The instantaneous LNG production rate may be slightly increased due to the reduced load on plant refrigeration systems. Alternatively, the operators may choose to shutdown the onshore tank BOG compressors during this time and take the make-up fuel gas elsewhere. This alternative will minimize the operational impacts due to ship loading. A hypothetical base case for a BOG recovery study could be as shown in Figure 2. There are onshore tank BOG recovery facilities, but they are not designed to handle shiploading BOG. Since no plant resources are directed to recovery ship BOG, the impact on the plant operation from ship loading is minimal. Recovering ship BOG could consume plant resources; if the provided recovery facilities do not include own refrigeration capacity, the plant feed gas would need to be curtailed in order to recovery ship BOG. It could be assumed that the plant normal feed rate is maintained at all times. The objective would be to identify the additional equipment required for recovering the ship BOG. The immediate implication of this
PO-34.4
philosophy is that plant capacity will rise above the baseline, because the ship BOG represents additional inflow of raw materials into the plant. Other advantages of this philosophy include: Normal operation of the liquefaction plant is maintained regardless of the ship loading conditions. The amount of BOG generation is somewhat unpredictable during initial chilling of the ship tanks as it depends on initial condition of the ship. In an extreme scenario that the ship is new or returning to duty from major overhaul, the BOG generation during initial chilling can be excessive. The study philosophy assures that this scenario does not have an impact on operation of the liquefaction plant. This philosophy is particularly relevant for de-bottlenecking or expanding existing plants. The BOG recovery section can be treated as an add-on package. Even for a grassroots project, the detachment of baseline operation from the ship BOG recovery would simplify the definition of process scope. Otherwise, the calculation of ship BOG generation cannot be finalized until detailed marine designs are complete. This finalization can only take place at a later stage of the engineering phase. BOG Profiles for Ship-Loading and Unloading Operations The ship-loading BOG is typically flared in existing LNG export terminals. Therefore, the BOG generation profile has received little attention. In contrast, the ship unloading BOG in receiving terminals is totally recovered. Hence, the BOG generation profile is relatively well understood. This subsection compares the differences in BOG generation profiles between the two scenarios. Figure 3 shows two idealized BOG profiles; one for ship unloading and another for ship loading. Development of a rigorous BOG profile requires dynamic simulation of the scenarios.
PO-34.5
BOG flow rate
(3a) Ship-unloading at receiving terminals
BOG due to vapor displacement at LNG rate of 10,000 m3/hr
0
5
10
(3b) Ship-loading at exporting terminals
15
20
Time, hr
BOG flow rate
2
3
1
BOG due to vapor displacement at LNG rate of 10,000 m3/hr
4 5
0
5
10
15
20
Time, hr
Figure 3. Idealized BOG Profiles for Ship-unloading (Top) and Ship-loading Operations Ship Unloading Operation. Figure 3a represents a typical LNG unloading operation at receiving terminals. After the initial chilling of connecting pipes and accessories, the LNG unloading rate is raised and maintained at the maximum capacity of onboard pumps. Correspondingly, the BOG generation rate in the onshore LNG tanks stays fairly constant during the unloading operation. The onshore BOG recovery facilities are typically designed to handle the ship-unloading BOG. The parameters for estimating the maximum BOG generation rate include jetty length, heat leaks, and tank design pressures. Usually, a portion of the generated BOG is returned to the ship through a vapor return arm for vapor replacement in ship tanks. Ship Loading Operation. Figure 3b depicts simplified BOG generation profile for LNG loading operation at export terminals. While five distinct phases of the operation can be identified, the boundaries between them are not as well defined as shown in the figure 3b. These phases are described below. 1. Initial chilling: When a ship arrives with a minimum LNG level as heel, the ship tanks, piping, and accessories are relatively warm, e.g. at -125 °C. Accordingly, when cold LNG at -162 °C is introduced into the system, the BOG generation increases. This initial chilling of the ship tanks should be performed slowly to avoid excessive thermal shocks to tank materials. Typically, a chilling rate of less than 3°C in 20 minutes is considered adequate. This phase will last four or five hours. At this point, the chilling rate limitation controls the LNG loading rate, not the capacity of onboard BOG compressors.
PO-34.6
2. Ramp up of LNG loading rate: When temperature indicators in the ship LNG tanks show that proper levels of chilling are achieved, the LNG loading rate can be ramped up. However, since the onboard compressors determine the overall BOG handling capacity, the LNG ramp-up rate should be closely monitored to keep BOG generation rate within the limit. The filling of ship LNG tanks is preferred to be performed in a staggered manner so as to facilitate topping-off later. The BOG generation is mainly attributable to the continued chill-down of LNG tanks and vapor displacement. 3. Maximum LNG loading rate: After the LNG level exceeds approximately ½ of the tank height, the tank chill-down is complete. The BOG generation rate starts to decrease. The maximum capacity of onshore LNG pumps controls the loading rate in this phase. 4. Ramping down: When individual tanks are 80% full, the LNG loading rate is reduced gradually until total stoppage. This is performed according to the aforementioned staggering sequence. This ramping down also provides extra time for suppressed BOG to continue evolving. 5. Topping-off: This phase is to maximize the utilization of all ship tanks (up to 98.5% of tank volumes). Valves to individual tanks are opened one after the other to top-off the tanks. Certain LNG “shrinkage” may occur in this phase of operation due to the continued evolution of BOG. Owing to the highly dynamic nature of BOG profile, instantaneous BOG flow data is of little value. Instead, operators may record accumulated BOG data in the course of an entire loading procedure. These data normally range from 0.6 to 0.8% transferred LNG per ship-load, equivalent to LNG loss between 840 to 1100 m3 (based on 140,000 m3 ship capacity). The differences between the ship-loading and ship-unloading operations are further elaborated below. 1. The capacity of a typical onshore tank is in the range of 150,000 m3 or higher. In comparison, a ship of a similar capacity would comprise four to five separate onboard tanks (Moss or membrane types). When accepting transferred LNG from smaller ship tanks in receiving terminals, the larger onshore tanks provide excellent buffering capability for tank temperature and pressure stability. This stability advantage is non-existent when transferring LNG from larger onshore tanks to smaller ship tanks in exporting terminals. 2. Onshore tanks can be top-filled or bottom-filled, typically, subject to the discretion of operators based on the density of incoming LNG. In a top-filled operation, the BOG generation can release the pumping energy and leaked heat instantly. However, the BOG generation rate tends to be high. In a bottom-feed operation, BOG generation can be delayed, depending on the detailed design of bottom-feed columns. Ship-loading is bottom-feed. 3. For ship-loading scenario, the amount of BOG generation during the initial chilling phase is determined by many factors such as types of ship tanks, levels of LNG heel, roughness of the sea during ballast (empty) voyage, and how
PO-34.7
refrigeration in the LNG tanks is preserved in the ballast voyage. The last factor is strongly dependent on the LNG composition and experience of the ship crew. For ship-unloading scenario, a full ship is always chilled. 4. In Moss LNG ships, Moss tanks have a higher design pressure, up to 0.7 barg, and can operate at a higher pressure (up to 0.25 barg). This design feature can be used to absorb the energy input during the loading process. However, the LNG temperature in the tank will be slightly raised. The raised temperature can be dealt with when the LNG is transferred from the ship to the storage tanks at the receiving terminal. The disadvantage of Moss LNG ships is that Moss tanks are constructed of relatively large mass of metal, which takes more LNG for chilldown. Membrane tanks are just the opposite. They are constructed of relatively small mass of metal and are not designed to hold pressures. A large percentage of existing global LNG fleet and new-builds are of the membrane-type tanks. These tanks are particularly susceptible to pressure fluctuations. The installation of very large BOG compressors on the jetty to assist in the handling of ship BOG should be evaluated carefully to ensure integrity of the membrane tanks are maintained. LNG Tank and Ship Compressor Operating Pressures Ship tank pressures can have significant impact on BOG generation. It can be assumed that onshore LNG tanks are of full-containment construction and operating at 1.06 bara. Ship LNG tank operating pressure is also set at 1.06 bara. The possibility of raising ship tank pressure to reduce the amount of ship-loading BOG is not explored in this paper for the following reasons: 1. Ships with membrane tanks are gaining popularity in recent years. These types of tanks are not designed to hold pressure. 2. The LNG delivery temperature may be bound by sales contracts. 3. The trapped heat in the ship LNG tanks does not disappear. It will be released in forms of unloading BOG at the receiving terminals. This is undesirable from LNG regasification terminal owners’ perspective. Each ship is assumed to have onboard BOG compressors to boost BOG pressure up to 2.15 bara at the compressor discharge. The discharge temperature would range between 80 and -50 °C, depending on the temperature of the exiting BOG at the top of LNG tanks. The maximum ship BOG rate is controlled by the onboard compression capacity. In scenarios of short jetty lines, typically the onboard BOG compressors are capable of delivering BOG back to onshore facilities. Some of current practices direct the returned BOG to LNG tanks, from which the onshore compressors draw the feed. The major advantage is that LNG tank vapor space provides a huge buffer for the compressor. The disadvantage is that the returned BOG may introduce heat and impurities to the tank. This concern is particularly true when a new or overhauled ship is being cooled down.
PO-34.8
PROCESS OPTIONS This section describes the possible destination for the recovered BOG. Five different destinations for the recovered BOG are discussed and each has its own intrinsic pros and cons. Figure 4 indicates some possible process options for BOG recovery. The options are classified based on the final destinations for the recovered BOG. a) As fuel gas (FUELG) b) As feed to plant cryogenic section (FEEDG) c) As LNG at onshore site (LNG_1) d) As LNG at berth site (LNG_2) e) In situ power generation (POWER) The difference between LNG_1 and LNG_2 is that in LNG_1 BOG is transported back to the onshore facilities for re-liquefaction. In contrast, LNG_2 liquefies the BOG at the berth by transporting refrigerant to the berth. The implications of this difference include: In LNG_1, a cryogenic or non-cryogenic pipeline carries BOG from the berth to the onshore LNG tank. In LNG_2, a cryogenic pipeline to carry refrigerant to the berth is provided. Hence, one will be used to carry gas, and the other one to carry cryogenic liquid, e.g. LIN or LAR. Depending on the delivery point for LNG_1, a separate NRU package may be required to avoid N2 accumulation in onshore LNG tanks. This NRU is not needed if the product is injected to the export LNG line for direct return to ships. Although different operators may have different criteria to evaluate BOG recovery processes, some of the critical criteria are listed below: It may be desirable to consider that the LNG production is isolated to a great extent from ship-loading operations. This ensures that optimal plant steady-state conditions can be maintained for LNG production under all operating modes. Therefore, a BOG recovery system exerts the least disturbances to the plant operation would be the most desirable. If the recovered BOG can bring in extra revenue, that would be a plus. If BOG recovery system has high thermodynamic efficiency then it can be economically used to produce extra LNG during holding mode, this is a desirable characteristic.
PO-34.9
FLARE (DESIGN BASELINE)
(FEEDG)
(FUELG)
(LNG_1) SHIP BOG
N2 REJECTION MODULE
N2 REJECTION MODULE
FUEL GAS
(LNG_2) (POWER)
TANK BOG
PRECHILLING
GAS CHILLING, HEAVY REMOVAL & LIQUEFACTION
N2 REJECTION
IN-SITU POWER GEN
SUBCHILLING
LNG
LNG
IN-TANK LNG ACCUMULATION FRACTIONATION SECTION
PLANT CONDENSATE
Figure 4. BOG Recovery Process Options Ship loading is an intermittent operation. BOG recovery requires compression or refrigeration machinery, both are suitable for continuous operation. Consideration has to be given to converting the intermittent operation to continuous characteristics. The advantages of a continuous operation over intermittent operation include efficient use of equipment capacity and elimination of thermal cycles. Figure 5 shows the two approaches of smoothing-out the intermittent operations; back-fill versus averaging. The back-fill approach would provide a BOG recovery capacity matching the maximum continuous BOG generation rate. During the holding period, incremental plant feed gas is assumed to be available to feed the BOG recovery system so as to utilize its full capacity. In other words, all the plant supporting system, such as gas pre-treatment, utility, and LNG storage, should be sized for this additional increment in the plant capacity. In contrast, the averaging approach would only provide a capacity for the BOG recovery system matching a time-averaged demand. During the holding period, the cold refrigerant is stored in dedicated storage tanks. The stored refrigerant is used to recover the entire BOG during the ship-loading operation. Although the cost of providing and storing cold refrigerant appears to be more expensive than liquefying BOG directly, this approach requires equipment with smaller capacity in continuous operation. The various process options described in this section or available for the recovery of BOG can be evaluated based on specific project requirements using a life cycle cost analysis to select the most appropriate option.
PO-34.10
Additional feed gas during holding mode to level capacity
BOG
BOG
BOG
Back-fill approach
Providing time averaged capacity only
BOG
BOG
BOG
Time-averaged approach
Figure 5. Two Approaches to Smoothen Intermittent BOG Recovery Processes JETTY PIPELINE FOR BOG RECOVERY AND MARINE CRITERIA A dedicated jetty (or causeway) pipeline is required to provide a means of transporting BOG onshore or refrigerant offshore so that material processing or energy exchange can be realized. Since this pipeline is dedicated to the BOG recovery, its operation is independent of the LNG plant. The process criteria described before are not applicable. Furthermore, the pipeline has direct interaction with ship onboard facilities hence marine criteria are appropriate to provide guidelines for the design of the pipeline. Jetty Pipeline Options While the possibility of packing the BOG pipeline during ship-loading is not practical, operating the BOG pipeline at elevated pressures does provide the following advantages: Higher pressures lead to smaller pipe sizes. Higher pressures result in higher compressor discharge temperatures, which allows for non-cryogenic pipe materials. Higher temperature eliminates the need for cryogenic insulation and leads to saving in bulk materials. Higher pressures provide operating buffer for gradual start-up and shutdown of certain equipment items used for intermittent operation. The following piping options to the jetty are possible. 1. No compression on the LNG loading berth. The onboard ship compressors are adequate for recovery of BOG PO-34.11
2. Compression system on the loading berth. The discharge pressure of the compressor is dependent on the size of the BOG line from the berth to the plant 3. Transportation of the refrigerant to the berth area for condensation of BOG The above options need to be individually evaluated for specific project requirements. Some of the marine considerations for this evaluation are detailed below. Marine Considerations The marine considerations should focus on the protection of ships and its cargo. Different ship crews may have different preferences. A set of the marine criteria that could be potentially used are listed below: The onboard BOG compressors are typically designed to send ship tank BOG to flare facilities for disposal and are not suitable for high discharge pressures for transporting ship BOG for long distances. Onshore facilities should be designed to eliminate the possibility of creating vacuum on the discharge side of the onboard BOG compressors. The creation of vacuum could affect the integrity of LNG ship tank containment system. Adequate precautions should be taken to avoid such a situation. The onboard BOG compressors are provided in multiple units. These machines may be individually shutdown in response to the dynamic nature of BOG profiles. Onshore facilities should be capable of handling such scenarios. To shorten the mooring period, it is desirable to have onshore facilities pre-chilled before ship arrival. The ramping-up of BOG generation during initial chilling can be much higher than 3 °C per 20 min, which is set for Moss type tanks. A ship with membrane-type tanks does not contain much metal and the cooling rate can be faster. The marine criteria discussed above can be applied to evaluate the different pipeline options from a life cycle costing perspective. When the jetty is short, the onboard BOG compressors are capable of returning the gas to onshore facilities. To compensate for the small volume between the vapor return arm and the onshore compressors, the returned ship BOG can be routed to onshore LNG tanks. If this practice is acceptable, the vapor space in the onshore LNG tanks serves as excellent buffer for BOG compressors. There would be no further limitations on onshore BOG compression. However, if the returned BOG is not directed to the LNG tanks, then the marine criteria are applicable to the aforedescribed process options. Those process options requiring no BOG compression would be favored. PROCESS MODULES The equipment used in the BOG recovery can be classified into the following four categories:
PO-34.12
(1) BOG Compression Depending on the final destination of the recovered BOG, as many as three stages of compression may be required. Only the primary compression, up to about 8 bar discharge pressure, may be suitable for jetty installation due to machine weight and dimension. A secondary and final compression, up to 50 bar discharge pressure is more suitable for onshore installation. (2) Refrigeration Systems Closed-loop refrigeration systems are proven technology. They have been used extensively in the LNG industry [1, 2]. The N2-loop is relatively new but is considered feasible [3]. Small-scale application of nitrogen based refrigeration systems for BOG re-liquefaction is commercially available. Additionally, single-loop refrigeration systems typically used in peak-shaving applications can be used here as well. Open-loop refrigeration system designs are also available from several vendors. Examples include the Nitech of BCCK [4] and Kryopak Process [5]. There are several vendors that supply packaged units for the generation of chilling medium. Examples include Air Products, Linde and Air Liquide. LIN and LAR are functionally similar from the perspective of refrigeration storage. The refrigeration modules should be located in the onshore BOG Recovery area due to their large dimensions and heavy weight. (3) Nitrogen Rejection (NRU) The need for NRU is project-specific. When the inlet gas has low N2 content, there would be no concerns about the N2 content in the LNG and a NRU is not required. (4) Power Generation Since it is uneconomical to store ship BOG by pipeline packing, the power generation option is required to be sized for instantaneous BOG rates. Under this scenario, the instantaneous power generated is too large to be productively utilized. Hence this is not considered a viable option. Each of the process options depicted in Figure 4 can be designed by suitable combination of the process components described above. Options FUELG and FEEDG require BOG compression modules only. Options LNG_1 and LNG_2 could be configured with various process schemes because there are different ways of providing refrigeration modules, some of which may require BOG compression or nitrogen rejection. After process schemes are defined, the Life-cycle cost (LCC) analyses should be performed for all the cases under consideration. The selection of the BOG recovery option depends on three major decisions: (1) lengths of jetties, (2) concerns of marine operation, and (3) availability of feed gas if additional refrigeration capacity is available. SUMMARY There is no unique one-case-fits-all solution for BOG recovery. Each individual project situation has to be evaluated for the specific requirements of the project. Some observations on the BOG recovery systems are listed below:
PO-34.13
1. A cryogenic pipeline on the jetty (or causeway) is expensive. It should be avoided whenever possible. 2. The selection of process option for BOG recovery is strongly influenced by the marine considerations. If onshore compression is unacceptable, then the solution is to use LIN to liquefy the BOG. In other words, LIN package should be provided and the produced LIN is stored during the holding mode. The stored LIN is released during ship-loading mode to recover BOG. 3. If onshore compression is acceptable, the product is limited to high-pressure gas. This option is worth evaluating when the LNG plant can accept high-pressure returned BOG for incremental LNG production. 4. If additional feed gas liquefaction capacity is available, a proactive approach is to view the BOG recovery system as an opportunity to expand the LNG plant capacity. The provided refrigeration capacity to liquefy BOG during ship loading can be used to produce LNG during holding mode. This added plant capacity may improve economics of the project. On the other hand, if additional feed gas is not available, then the provided refrigeration package will be sitting idle most of the time. REFERENCES CITED 1.
Yost, C., DiNapoli, R., “Benchmarking Study Compares LNG Plant Costs”, Oil & Gas Journal, issue of April 14 (2003).
2. Mokhatab, S., Economides, M. J., “Process Selection Is Critical to Onshore LNG Economics”, World Oil, issue of February (2006). 3. Finn, A., “New FPSO design produces LNG from offshore sources”, Oil & Gas Journal, issue of August 26 (2002). 4.
Butts, R. C., Chou, K., Slaton, B., “Nitrogen-Rejection Process Developed for Small Fields”, Oil & Gas Journal, issue of March 13 (1995).
5.
Kryopak website, www.lngplants.com (2006).
GLOSSARY BOG
Boil-Off Gas, which include contributions from vapor displacement, pump energy input, and heat leaks through piping and vessels. CS Carbon Steel Holding The operation mode of an LNG plant when there is no ongoing ship-loading mode operations. The BOG generated from onshore LNG tanks is handled by dedicated compressors. LAR Liquefied Air LCC Life cycle cost. The analysis takes into account initial investment and operation costs LIN Liquefied Nitrogen
PO-34.14
Loading The operation mode of an LNG plant when there is ongoing ship-loading mode operations. Since LNG is pumped out at a fast rate, attention should be paid to vapor replacement. Also, there will be significant amount of ship-loading BOG which needs to be handled. LTCS Low Temperature Carbon Steel NPV Net Present Value NRU Nitrogen Rejection Unit SS Stainless Steel TIC Total Installed Cost VIP Vacuum Insulated Piping
PO-34.15
