You see them everywhere: acres of giant white cylinders—some rotund and some a bit slimmer—rising from the ground like a farmer’s root crop ready for harvest. They are the liquid petroleum terminals that adorn energy centers and energy transfer points around the globe. Even some of the larger airports around the world have their own farms of tanks where jet fuel is piped to the airport directly from a producer’s refinery.
These tank farms are home to large networks of pipe and the valves that help control the flow of what goes through those pipes into and out of the tanks.
There are two types of tanks in these farms. The first is the traditional solid design with rigid sides and top. The second is the floating top tank, which has a cover that rides on the surface of the liquid and eliminates any void in the tank as it empties or fills. Floating top tanks are now usually built with geodesic dome covers to contain fugitive emissions that could leak around the floating top seal.
The original location for most of these farms was on the periphery of petroleum refineries where finished product was stored awaiting pipeline, rail or marine transport to its ultimate destination. The quantity of in-refinery tank farms has diminished greatly over the past few decades because producers do not want to hold onto all that costly liquid inventory. However, the overall quantity of outside-the-plant terminals has greatly increased. This equates to a good market for valves for this somewhat unique service.
The modern-day liquid petroleum terminal exists to perform vital functions in the hydrocarbon raw-material and finished-product supply chain. The tanks often are used to store extra product not needed yet at the refinery. Sometimes finished product is stored until it is needed by the pipeline operator and eventual end user. Also, some terminals use the tanks to store different blends of product that are then combined to create specific fuel formulas for different locales and markets. Another purpose of a terminal is to act as an ownership or “custody-transfer” point for product that is changing hands.
While this article only focuses on valves in ambient-liquid terminals, liquified natural gas (LNG) terminals and some other non-liquid storage facilities exist as well. However, their valve needs are different, especially the LNG facilities, which have cryogenic valve requirements.
THE VALVE ENVIRONMENT
Valves are specified by the function they are required to perform (on/off, regulating flow or preventing backflow), as well the service conditions for which they must function. Steam valves, for example, may see temperatures above 1,000°F (538°C), while critical refinery valves may see high temperatures and highly corrosive environments. Aside from valves in water service, tank farm valves function in one of the tamest environments that exist in the valve world.
Except for installations in the far northern climates, the operating temperature for liquid petroleum terminals is moderate (-20°F or -29°C to 120°F or 49°C) and the fluids are generally not that harsh unless hydrogen-sulfide-laced sour crude is involved. A third criterion for valve selection (beyond temperature and corrosivity) is operating pressure. For most tank farm/liquid terminal applications, the pressures are well below 200 psi. In terms of design requirements, the most predominant pressure class for valves in this service is Class 150 with its operating pressure around 285 psi, depending on the material of construction.
The material selected for valves in liquid tank farm applications is almost always carbon steel with a variety of valve trims based upon the exact fluid and operating conditions of the valve. In Canada, where the ambient operating temperatures can be much colder than -20°F (-29°C), special, low-temperature steels such as casting grade LCB are chosen.
Piping sizes in terminals have increased over the last 20 years or so. In the 1950s, 60s and 70s, Nominal Pipe Sizes (NPS) 12 through NPS 20 were considered the normal pipe sizes, while today, it is not uncommon to see piping of NPS 30 in these facilities. This is because the larger diameter piping offers faster throughput through a facility.
For over 100 years, the most popular valve in tank farm service has been the venerable gate valve. These common denominators of tank farm valving have functioned very well and been cost efficient. The torque-closure design of the wedge gate has performed well for so long because it is cheap and easy to maintain since it has a hearty design. For valves in crude oil service, the environment is especially good for the gate valve because it is operating in a gentle bath of lubricating oil.
THE EXPANDING PLUG VALVE
The gate valve has one disadvantage in that most designs are not guaranteed “zero leakage,” especially if the zero leakage is required for both directions of flow. Some American Petroleum Institute (API) 6D resilient-seat expanding gate valve designs do provide zero-leakage. Zero leakage for both directions is needed in a terminal, however, to keep from cross-contaminating product as the tanks and their inputs and outputs are switched for various purposes. This simultaneous sealability in both directions is called double block & bleed (DB&B).
The need for a valve that could accomplish this was addressed over 75 years ago with the development of a valve design that specifically met and still meets the fluid control needs of the tank and terminal industry: the expanding plug valve. The design was originally developed by the General Valve Company in 1941, which called it the “twin-seal” because it sealed with zero leakage in both directions.
The expanding plug design is unique in the valve world because of how the sealing system functions inside the valve. When closed, the tapered O-ring fitted steel sleeves are snugly pushed into both seats simultaneously by the internal plug. Then, as the valve is opened, a sealing- surface-saving process takes place: As the stem is rotated open, the plug’s seals (often called slips) initially move away from the body seats in the valve. Next, the entire plug assembly rotates to the open position as the handwheel is turned. This sequence eliminates any potentially damaging rubbing action on the seating surface slip O-rings, which are the key to zero leakage sealability in the valve.
For applications where the piping size is small to moderate (up to about NPS 16), the expanding plug valve is the valve of choice today for DB&B terminal service applications. The primary reason that these valves are not specified more often in larger sizes for terminal installations is purely cost-related.
When using DB&B valves, a possibility of overpressuring the body cavity exists if the internal temperature rises since the valve is seating simultaneously in both directions. A thermal relief system is required to alleviate the overpressure, usually venting to the upstream side of the valve.
Virtually all hydrocarbon service valves inside a terminal are required to be fire-safe. While the wedge gate valve is inherently fire-safe because of its metal-to-metal seating, the DB&B expanding plug valve, with its O-ring slip inserts, must be tested and confirmed to be fire-safe. (See “What Does Fire-safe Mean?”).
The choice between using the guaranteed DB&B sealing of the expanding plug or the sealing of wedge gate valves is a decision left up to the purchasing team at each facility. The wedge gate valve may not seat quite as tightly, but its simple design makes it almost maintenance free, especially in a sweet crude environment. The more complex, expanding plug valve requires a bit more upkeep and may cost more to actuate. Since the profit margins of these facilities are traditionally thin, initial valve cost is very important in the decision-making process.
Because most tank farms and terminals are storing hydrocarbon-based liquids, it is natural that, as far as applicable, API standards be followed in the design. The overall design guidance requirements for these facilities are covered in API Standard 2610: Design, Construction, Operation, Maintenance, and Inspection of Terminal and Tank Facilities. While this document is extensive, the subject of valves is only briefly mentioned and is in fact deferred to the American National Standards Institute (ANSI)/American Society of Mechanical Engineers (ASME) B31.3 piping design standard, Process Piping.
Within B31.3, the valve design requirements are further relegated to fall under the auspices of common API valve standards such as 600, 608, and 6D. In API, standards fall under different umbrellas based on whether the valves are used in upstream, midstream or downstream service. Since the tank or terminal facilities can be considered both midstream and downstream—depending upon the location of the tank farm and its piping—both downstream (API 594, 599, 600, 602, 608, 609, 623) and API 6D valve designs are acceptable.
It’s possible also that more requirements such as additional radiography or other testing requirements imposed in ANSI B31.3 could be required of valves in tank and terminal service.
Although gate and expanding plug valves are the primary valves in tank farms and terminals, other valve types are used. Since pumps are involved in creating the pressure necessary to distribute the liquid throughout the facility, automatic back-flow protection for these pressure-generating devices is required. This means check valves will be installed downstream of their output to protect them from backflow damage. The most common styles of check valve for this application are either the wafer or spring-assisted, center-guided check valves.
In these facilities, a need also exists for positive and quick line closure in case of a mishap such as a fire or overfilling. Emergency shutdown valves (ESDs) fill that need. Frequently, ball valves are used in this service since their quarter-turn actuation cycle is very fast compared to the actuation motion of a multi-turn valve. Except for ESD service, ball valves have been slow to gain acceptance in tank farms and liquid terminals. One reason is the possibility that entrained solids in the fluid could damage soft seats.
The high-performance butterfly valve is used in tank and terminal service more and more, but terminal operators and facility designers still seem to fall back on what has worked well in the past: the gate and expanding plug valves. However, the future could see an influx of metal-seated ball and triple offset butterfly valves taking market share from the currently popular multi-turn products.
Once upon a time, terminal and tank farm piping manifolds and shut-off valves were operated by a burly, big-biceped tank farm employee with a valve wrench in his hand. This worker would open and shut the valves as required to direct the flow to and from the proper tank or tanks. Today, however, most of these systems are automated; all the key valves are now actuated and controlled either onsite or offsite from a safe and secure control room.
The actuator controls are interfaced to a computer or programmable logic controller in the control room, along with outputs from tank level gauges, pressure gauges, flow meters, temperature sensors and other data inputs. This data, along with incoming liquid data from the supply-side pipeline, are combined to assess the status of the facility and provide information so the operator can adjust any final control elements that feed the tanks in real time as needed.
These control systems also benefit custody transfer, where different entities are providing product that is gathered at the same terminal facility and accurate liquid inventory accounting is critical.
Three main safety concerns are involved in tank/terminal facilities: overfilling of tanks, lightning and fire. With all that flammable and inflammable potential energy present, an important need is fire suppression systems in the terminal/tank farm. The design of these systems falls under the purvey of National Fire Protection Association (NFPA) standards and recommendations. The dominant NFPA standard applied is NFPA 30, Flammable and Combustible Liquids Code. Included in recommendations are designs for the dissemination of firefighting liquids and foam.
These systems, which are almost always separate from the main fluid piping system, also include valves. A system may have automatic and/or manual nozzles or deluge installations to direct fire suppression liquid or foam to the fire. An additional safety requirement is that all tanks be contained in earthen or concrete dikes to retain the liquid in case of disaster.
Some facilities also have a unique interface between the main fluid piping system and the firefighting system. An inlet to the main fluid piping network can be used to pump foam or another fire-suppression fluid directly into the burning vessel through the supply piping. This requires either automatic or manual closure of valves and redirection of firefighting fluids to only the affected tanks by the terminal control personnel.
The possibility of tank damage by overpressure or underpressure (vacuum) is usually handled by a pressure relief or vacuum relief/vent system attached directly to each tank. Additional pressure relief valves (PRVs) are installed in the main pump-powered product piping system and are generally set at about 110% of the pump output pressure. These PRVs follow the same material and pressure class requirements of the rest of the piping system.
Tank farms and terminals are key elements within the petroleum supply chain, and efficient valves and piping systems are the vital arteries of each system. Although the pressures and temperatures seen by these valves are not extreme, the service they perform is critical to the successful and safe operation of the terminal or tank farm. VM
GREG JOHNSON is president of United Valve (www.unitedvalve.com). He is a contributing editor to VALVE Magazine and a current Valve Repair Council board member. He also serves as chairman of the VMA Communications Committee, is a founding member of the VMA Education & Training Committee and is past president of the Manufacturers Standardization Society. Reach him at firstname.lastname@example.org.
A valve is considered fire-safe when it can still retain some closure capability after it has been exposed to the high temperatures of a fire. These high temperatures would melt any elastomer or fluoroelastomer used to effect zero leakage in a valve. Metal-to- metal seated valves such as most gate and globe valves are inherently fire-safe. Metal-seated ball valves also fall under this category.
The fire-safe connotation is applied to a valve after its original design has gone through a special test protocol that mimics what can happen in a real fire—extreme heat, followed by quick cooling. The two most common fire test specifications used today are API 6FA: Standard for Fire Test for Valves and API 607: Fire Test for Quarter-turn Valves and Valves Equipped with Nonmetallic Seats. API 6FA is generally applied to midstream and upstream applications, while API 607 is used for downstream applications.
Passing of either of these two test procedures requires that the valve must be covered by flame at a particular temperature for a specific period of time and then cooled rapidly by a spray of water. The valve’s seat leakage rate is then tested, with the requirement that the backup sealing mechanism must function somewhat effectively, even after the primary elastomer or fluoroelastomer seating mechanism has been destroyed by the high-temperature effects of the fire.
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