Lost and unaccounted for natural gas, particularly at pipeline custody transfer points, is becoming a focal point for both buyers and sellers. Even somewhat small measurement error can result in very large economic gains or losses at current natural gas prices. One relatively large source of lost and unaccounted for natural gas is due to pulsation at the orifice meter-induced by compressors, flow control valves, regulators and some piping configurations. This article discusses some historical research and findings surrounding the topic of pulsation. In addition, we will provide some methods of measuring, monitoring and potentially correcting various types of pulsation supported by relevant examples.Background
In recent years the Pipeline and Compressor Research Council (PCRC), now known as (GMRC) Gas Machinery Research Council and a subsidiary of the Southern Gas Association, commissioned and funded various pulsation research projects at Southwest Research Institute (SWRI) in San Antonio, Texas. The PCRC sponsored research programs concluded that pulsation induced measurement errors to fall into two broad categories:
SRE directly relates to flow measurement error and therefore a very important topic to those who buy and sell natural gas. This paper will focus on methods to measure and quantify Square Root Error and subsequent Gauge Line Error, while also recommending several techniques to reduce pulsation effects on natural gas measurement.Square root error
Most natural gas flow measurement in the United States is performed by measuring pressure drop at two points (pressure differential) induced by an orifice plate. The gas flow rate (Q) is calculated using the basic formula Q = K√ΔPXP. The fixed orifice coefficient (K) is derived from a formula found in the latest edition of AGA Report Number 3. Differential pressure ΔP and line pressure P are measured either using mechanical chart recorders or electronic transmitters, remotely or directly mounted to the pressure taps, using a configuration of instrumentation valves, manifolds, and tubing.
Under steady-state flow conditions, gas flow rates can be accurately measured with current state-of-the-art equipment, including highly accurate pressure transmitters and flow computers. Despite the high degree of accuracy of current electronic measurement devices, inaccurate measurement still occurs when the ΔP modulates, or changes, at a frequency greater than the frequency that the measurement system extracts the square root of the ΔP.
This type of measurement error is called Square Root Error (SRE) and is the calculation of unsteady flow using the square root of the average P versus the average of the square root values of the instantaneous ΔP.
Pulsation from gas compressors, control valves, pressure regulators, and some piping configurations are one source of frequent ΔP modulation. Figure 1 is an excellent example that illustrates the amplitude and frequency of pulsation generated by a reciprocating compressor and a control valve. Three separate pulsation peaks are occurring in this system.
Figure 1: A graph exhibits three separate pulsation peaks. The operator can isolate the pulsation source by using new software filtering capability and modifying conditions in the new field. Minimizing and eliminating the pulsation source can ultimately improve the meter’s measurement accuracy.
The field technician operating the SRE Indicator is typically able to isolate the pulsation source(s) by using new filtering software and modifying the field conditions to generate new responses. This enables the operator to make necessary field changes that should improve measurement accuracy.Other primary element errors
SRE is the largest component of pulsation induced primary element error. However, inertial error and the coefficient shift will both increase in magnitude under extreme pulsation conditions. A brief explanation of each follows:
Pulsating gas flow will tend to remain in motion due to its inertia. As a result, flow velocity changes lag behind ΔP changes. Inertial errors are insignificant unless pulsation amplitude and frequency are both
Though difficult to quantify, test data indicates that pulsation levels above 1.5% SRE contribute to shifts in the orifice coefficient.
The %SRE is measured at operating conditions and is used to approximate the primary element error induced by pulsation and to determine whether corrective action is necessary.
Percent Square Root Error (%SRE) is measured with a device manufactured and marketed by Parker called the Square Root Error (SRE) Indicator. This analytical instrument utilizes a high-frequency response ΔP transducer and software to calculate %SRE according to the formula developed by SWRI, illustrated earlier in this paper.
The SRE Indicator is used by field technicians to measure the severity of pulsation and calculate %SRE. The results can be used to determine if corrective action is necessary. However, because other primary element errors (inertial error and coefficient shifts) are not directly measured, %SRE should not be used to correct flow measurement readings.
Measurement error caused by pulsation at custody transfer points can create large economic discrepancies between natural gas buyers and sellers. Therefore, many natural gas purchase contracts contain language that set limits on %SRE (sometimes as low as 0.20% SRE) and typically place the burden of reducing or eliminating pulsation on the seller.
The simplest method of reducing pulsation induced SRE is to raise the ΔP by changing the orifice plate. Unfortunately, this may also limit the operating range of the measurement system.
In some cases, the piping system could be modified or the pulsation source could be moved to reduce SRE. This can be time-consuming and costly.
Another popular corrective action for high SRE is to install a device, such as a restricting orifice, between the pulsation source and the measuring station. However, these restricting devices can result in higher compression cost and a limited flow range. %SRE can also be reduced by installing an acoustic filter to remove most of the pulsation. Although more costly than a restricting device, a properly designed acoustic filter will operate over a much wider flow range with a lower pressure drop.Gauge line error
Gauge Line Error (GLE) exists when the differential pressure (ΔP) at the tips does not equal the differential pressure (ΔP) at the end of the gauge lines. GLE is typically caused by either pulsation or other flow phenomena.
The gauge line starts at the orifice taps and ends at the transmitter, flow computer, or chart recorder connections. It includes any pipe fittings, valves, valve manifolds, tube fittings, instrument tubing, and condensate chambers or bottles that may be installed between the orifice taps and the measurement device.
Research conducted by SWRI determined that gauge line error has two components:
Parker developed its initial GLE Indicator in 1990, following it in 1996 and 2005. The current SRE/ GLE Indicator includes the ability to perform both %SRE and GLE tests, thus measuring and quantifying both gauge line error and square root error.
Figure 2: SRE6 and GLE6 test equipment that enables an operator to perform an SRE and GLE test simultaneously.
The GLE Indicator compares the differential pressure at the orifice taps with the differential pressure at the end of the gauge lines. Any difference between the two signals would be associated with gauge line error.Testing results
Extensive field-testing with the GLE Indicator confirmed the research conducted at Southwest Research Institute (SWRI) by PCRC. The lab test examples should provide a better understanding of GLE issues and measurement problems resulting from incorrect transmitter mounting practices.
As noted previously, numerous gas contracts now include pulsation magnitude clauses and many transmission companies require the installation of acoustic filters to minimize pulsation levels and %SRE. However, GLE tests conclude that gauge line error may continue to be present even after the installation of an acoustic filter and despite %SRE readings as low as 0.1%.
System complexity and numerous dependent variables, including pulsation levels, gauge line lengths, gauge line diameters, operating pressure, gas density, and gas velocity make it extremely difficult to observe a measurement location and predict what gauge line error, if any, will be present. GLE testing is currently the only recognized method to determine the presence of gauge line error.
Proper installation of the transmitter and/or electronic flow meter (EFM) in a manner that minimizes or eliminates gauge line error by removing as many of these dependent variables as possible is the best option.
Best practices include:
Using a short length of 1/2" O.D. instrument tubing and full opening quarter turn ball valve between the orifice fitting and measurement device creates numerous mating of female NPT connections and small “volume chambers,” which could create gauge line shift (pulsation rectification effects).
“Best practices” suggest using a system that directly mounts and closely couples the measurement device to the orifice taps. This method continues to gain wide acceptance within the industry illustrated by over 10,000 installations currently in service.
Figure 3. Parker’s Direct Mount System. The manifold system reduces the effect of Gauge Line Error on the total measurement system. Note the reduced number of leak points and sensing line length, and the uniform diameter between the orifice ports and the measuring elements.Summary
Pulsation created by compressors, flow control valves, regulators, and some piping configurations may create unacceptable levels of Square Root Error (%SRE) and/or the resulting Gauge Line Error (GLE).
Pulsation at the orifice meter is a major source of lost and unaccounted for natural gas, which can create large economic gain or loss for both buyers and sellers along with a natural gas pipeline system.
%SRE and GLE can be measured and quantified using an SRE/GLE Indicator to verify measurement accuracy at a specific time and place. Pulsation and resulting high % SRE creates a high probability that GLE is present. Volume chambers or numerous measurement devices connected to the same set of orifice taps may compound or create GLE.
Transmitters or EFM should be close coupled to the orifice taps with equal length, large bore (0.375" I.D. or greater), constant diameter gauge lines to minimize or eliminate GLE; however, this process will not reduce or eliminate %SRE. The pulsation source must be eliminated, piping systems modified, ΔP increased, a restricting device installed, or a properly sized acoustic filter installed to reduce pulsation and resulting %SRE.
Article contributed by BJ Jackson, Product Manager - PGI Specialized Systems, Parker Hannifin, Instrumentation Products Division.
To stay at the forefront of the competitive transportation markets, fleet managers are turning to alternative fuels that meet the environmental and economic needs of today and in the future.
Natural gas (NG) is widely recognized as a fuel that offers high potential to offset society’s concerns about pollution, climate change and depletion of natural resources — it produces fewer greenhouse gas emissions than gasoline or diesel, and is safer, with a low chance of flammability.
NG engine availability is increasing and offers longer vehicle life with less long-term expense for the consumer. As a result, more fleet operators are choosing cleaner-burning natural gas as a fuel choice for trucks and transit buses.
Most energy outlooks predict significant growth in the use of natural gas for transportation vehicles. According to the U.S. Energy Information Administration, strong increases are projected for the natural gas share of total energy:
Compressed natural gas (CNG), liquefied natural gas (LNG) and liquefied petroleum gas (LPG) are three forms of natural gas used in various types of vehicles and mobile equipment. Each has its own unique characteristics making its suitability specific to different applications.CNG
CNG applications include mobile (on vehicle) and infrastructure (fueling station). CNG is used in light-, medium-, and heavy-duty applications. From the refueling receptacle to the engine compartment, high-quality CNG components make a noticeable difference in performance.LNG
LNG is suitable for heavy-duty vehicles, locomotives and marine vessels that require longer ranges because the liquid is denser than gas (CNG) and, therefore, more energy can be stored by volume in a given tank. However, because LNG is stored at extremely cold temperatures and requires ultra-fine filtration, it is important to choose components that accommodate these requirements.LPG
LPG is used worldwide for propane-powered mobile solutions and a wide variety of industrial and commercial LPG/propane delivery and supply applications.
Choosing components for NG applications
When selecting components for NG applications, manufacturers should consider the following:
Certifications and testing
Standards and certifications governing the design of components used for natural gas vehicles and refueling stations have been established to provide assurance that components and systems have been objectively evaluated for their function and safe operation in the intended application.
- The importance of testing and validation
- Descriptions and contact information for certifying organizations
- Types of certifications for on vehicle and fueling station products
- Information on CNG inspector training and certification programs
Benefits of using certified, listed products
Safety and performance are the primary drivers for products carrying certification to defined standards. These overlaying priorities influence the entire supply chain from design to final installation and operation. By maintaining a consistent standard, manufacturers, as well as customers, gain the peace of mind that the components and systems have been tested and monitored in their intended area of application, and have met the pre-defined criteria for safe use and performance.
“There is always a risk in using untested, unvalidated components in an NGV application. You face safety concerns as to whether the component can handle the pressure extremes and temperature variations. The biggest risk of using uncertified components is leakage. If you use a component that has not gone through the rigors of certification, you will not have the assessment that the component will not leak and become a safety hazard,”
— Ken Loewenthal, product manager, alternative vehicle fueling, CSA Group
Risks of using non-certified products
Financial performance: Although non-certified components may present material cost savings, using them could result in financial risks. Any material savings would be lost with even one safety issue caused by a leak or other failure. The cost of replacement products, downtime, and potential liability would be substantial.
Reputation: The failure of a non-certified component could reflect negatively on the manufacturer suggesting a lack of quality, disregard for standards, and low priority placed on safety.
Productivity: Certifications help ensure components safely perform in the application. Using non-certified components may delay approval of the equipment by Authorities Having Jurisdiction (AHJ) inspectors if they think additional on-site testing is needed.
"Certification marks offer peace of mind to retailers, regulators, consumers and end users the world over by indicating that your products have been independently tested and have met the required standards for safety and performance"
— CSA Group
Organizations and associations
For safety and performance standards, several organizations provide certifications, requirements, specifications and guidelines to verify that natural gas vehicle fuel systems and components offer the highest quality and reliability. These include:
Comprehensive range of fully certified products
Parker offers the most comprehensive range of fully-certified, multi-technology systems and components for natural gas vehicles and fueling stations. Our proven subsystems and components in fluid management, motion and fluid control, filtration, and temperature control provide NG solutions that offer improved service life, reduced risk, and greater value to customers. Here’s a snapshot of some of our product solutions:
High-pressure particulate filter FFC-112 is ideal for CNG-powered vehicles, such as airport shuttles and taxis, to protect critical engine components from contaminants in CNG fuel. The machined aluminum housing is anodized to enhance durability and its robust yet small, lightweight size allows for versatile installation and easy servicing. Both 1/4” NPT and 9/16” SAE connections are available on this 3600 PSIG rated assembly.
FM80 fuel regulation module is a fully integrated CNG flow control and regulation system for medium and heavy-duty vehicles and is constructed of robust anodized aluminum, a high-grade low-sulphur “Vericlean” stainless steel poppet, and Parker VG109 seals. Integrated internal regulator components, with fewer connections, work together to eliminate fuel line failures due to freezing, dampen flow induced vibration, reduce drop at high flow, and extend cycle life. Features include an advanced metal piston style regulator, coalescing filters, pressure sensors, lock-off solenoid valve, heat exchanger, and low-pressure relief valve all in one compact body. Exceeds industry standards for leakage and safety and is certified to ANSI NGV3.1 / CSA 12.3.
5CNG high-pressure CNG hose is specially developed for the conveyance of compressed natural gas. It is constructed of an electrically conductive nylon core designed to dissipate static build up and fiber reinforcement for maximum pressure and flexibility. The polyurethane jacket provides abrasion resistance and protection from outdoor elements including ultraviolet light. Conforms to and is listed per NFPA 52, ANSI/ CSA NGV 4.2, CSA 12.52, Class A & D Certificate # 1053249 (hoses for natural gas dispensing systems).
CNG fueling station
Seal-Lok™ for CNG o-ring face seal (ORFS Fittings) offers a leak-free design and a rugged construction to make them optimal for use in situations with high-pressure, vibration and impulse environments. Seal- Lok™ for CNG provides a zero clearance fitting system, which allows for ease of assembly in tight installation areas. Seal-Lok™ for CNG applications has been tested and certified by TUV according to the following standards: ECE R110 regulation (Economic Commission for Europe), ANSI NGV 3.1-2012/CSA 12.3-2012 (Natural Gas Vehicles/ Canadian Standards Association), and ISO 15500.
LNG on vehicle and fueling station
Metal LNG hose is designed for extreme chemical and temperature applications, Parker’s metal hose offers excellent chemical resistance with zero permeation. Hydro-formed design yields a uniform wall thickness, promoting even distribution of stress during flexing and reduces concentrated residual stress. Maintains its integrity up to 1200°F.
As natural gas technology continues to advance, manufacturers are motivated by their desire for quality and safety to verify that their components are tested and in compliance with the most current standards. Understanding applicable natural gas certifications provides assurance to both manufacturers and consumers that components and systems will perform safely and reliably.
This post was contributed by Steve Duricky, business development manager, Parker Hannifin
Selecting materials for a given application is one of the main design steps towards a safe and cost efficient system, yet a commonly overlooked stage, mainly performed from a purely economic standpoint. The benefits of selecting the best candidate alloys and controlling corrosion are numerous and include asset safety and integrity, optimum performance with minimal maintenance and shutdown time or longer life expectancy. All those these advantages ultimately lead to considerable cost savings.Using higher alloys for critical parts only.
Mixing dissimilar materials is a very common practice, more so when the alloy selection is primarily driven by cost and lead times. While there are numerous engineering applications where mixing dissimilar materials is not just an option but the best or only solution, there are many services where this practice does not add value and should be avoided. In the instrumentation market, Parker often encounters many customers experiencing corrosion problems. The most common solution in those cases is selecting new equipment made of a more corrosion resistant material to avoid a particular corrosion failure mechanism. Sooner rather than later, the cost of this new alloy comes into play and replacements need to be justified, so in an effort to try and keep this cost down, many customers decide to use this higher grade alloy in critical parts only.How can we define what is critical and what is not?
Let’s take an instrumentation tube and fitting/valve system for example. The oil and gas industry has traditionally used millions of this type of instrumentation in 300 series stainless steel material. However, not only are climate and operating conditions, as well as geographical locations harsher than they used to be and so are the design criteria and safety regulations and expected life-span. Where stainless steel was a material of choice twenty years ago in these types of highly corrosive environments, it is not fit for purpose any longer. Corrosion resistant alloys are more readily available than ever, but their outstanding properties are proportional to their price per kilo. There seem to be a general line of thought that regards ‘bulky’ components as ‘durable’ or ‘unbreakable’. It is for those reasons that too often, the tube is regarded as the critical part (due to its limited thickness) and the fitting or valve as the ‘less critical’ one. Therefore, the higher grade alloy is selected for the tube and a lower grade for the fitting or valve. But, is this a fair assumption?Does size really matter?
If instrumentation products suffered from just general corrosion and were subject to no tensile loads, where steady corrosion rates can be established and risk managed fairly easily, the above assumptions could have been acceptable. However, the reality is that instrumentation products usually face both localised corrosion and mechanical challenges, due to their inherent operating conditions.
Typical failure mechanisms in the oil and gas industry are due to the action of localised corrosion, such as pitting or crevices. The combined action of a corrosive environment and the presence of tensile stress, such as vibration, can cause stress corrosion cracking and the fatal failure of equipment in a matter of seconds. Chloride induced corrosion cracking is a prime example of failure mode in offshore applications. It just takes the presence of tensile stress and a flaw in the material caused by chlorides, to start crack propagation. When there is a fissure in a material and the right amount of tensile stress, large thicknesses will not stop cracks propagating across the grain boundaries. It will just take a bit longer than with thinner sections. Therefore, in such cases, size does not matter.
Fig. 1. Corrosive environment and vibration can cause stress corrosion cracking and failure of equipment after six months. Example shown is where the material for the instrument fitting was different to that of the tube and used in a corrosive offshore environment.Material not suitable for tubing = material not suitable for fitting
Safe and cost effective operations should include the right selection of materials and a good design to minimise unnecessary loads. If a material is not deemed as suitable for tubing, it should not be deemed as suitable for another component, as after all, both parts will be exposed to exactly the same operating and environmental conditions, and thus are exposed to the same failure mechanisms.
According to industry standards such as NORSOK M-001: Materials Selection standard, ‘’wherever dissimilar metals are coupled together in piping systems, a corrosivity evaluation shall be made. If galvanic corrosion is likely to occur, mitigation methods should be used’’. It also states that ‘’at galvanic connections between dissimilar materials without isolation/distance spool, it can be assumed that the local corrosion rate between the interface is approximately 3 times higher than the average corrosion rate’’. Cathodic protection in instrumentation systems does not tend to be cost effective, and isolation or distance spool between the tube and the valve or fitting is often not viable.
Intermixing materials should never be taken lightly but carefully evaluated. Material selection is paramount in order to develop cost efficient systems, avoid unnecessary risk, jeopardise assets, add complexity or face costly downtime at a later stage. Selecting the right materials for the application, and ensuring a safe installation are common solutions to trouble-free systems and at Parker we have the knowledge and expertise to help you engineer your success.
Clara Moyano is Innovation Engineer - Material Science at Parker Hannifin, Instrumentation Products Division, Europe.
From surgical equipment to cooking pans to skyscrapers, stainless steel has transformed the world as we know it today. Stainless steel is present in our daily lives and has made a significant impact in a wide variety of industrial applications. The oil and gas industry in particular has been no different, as operating conditions and extracting methods made stainless steel a very cost effective, convenient and reliable choice.Higher operating pressures and temperatures
Despite worldwide efforts to rely on renewable energies, oil and gas remains the skeleton of the energy supply at present. Many conventional reserves have been exhausted and oil and gas reservoirs found in very inaccessible locations and hostile environments are now usual targets for exploration. Pressures and temperatures that were deemed in the past as not viable are at present common operating parameters, imposing considerable limitations on existing equipment and technology and making the oil and gas industry face serious material related challenges.The emergence of the “Corrosion Resistant Alloy”
Nearly a decade ago, numerous oil and gas producers started specifying and using the low end of the Corrosion Resistant Alloys (CRAs) spectrum, including super austenitic stainless steels, duplex and super duplex varieties. This trend was mainly driven by failures experienced on existing equipment, where the basic stainless steel range could not perform appropriately. Awareness on corrosion cost and assets impact and safety have also been drivers for corrosion resistant alloy usage. Today, nearly every oil and gas producer includes CRAs in their portfolio. However, there is yet a lot to be learnt on how other CRAs could help optimise performance and integrity. In addition, the lower corrosion resistant alloy range is just an enhancement to the traditional stainless steel grades used for decades, but those have limitations as well, and are not the solution to every problem.Meeting the demands of an ever changing environment
Fig. 1 Parker 6 Moly tubing.
Over the last months we have observed an increased demand for more special alloys, such as the nickel-based ones. What is more, end users do not only seem to be interested in using those advanced materials but for the first time, they also require specific melting methods, controlled manufacturing routes and extensive mechanical and corrosion testing methods to ensure maximum equipment performance. This is just another indication of harsher environments and highly demanding production routes.
Both, onshore and offshore applications are major contributors to the CRAs fast growing demand. Onshore shale gas production has flourished in the past years due to the availability of new drilling technology, by using advanced materials to fight the extreme corrosion effects of shale gas and the higher operating pressures. On the other hand, the offshore market, especially deep water exploration, is emerging too, due to the development of subsea technology. Both those sectors are bound to grow very rapidly in the future, and so CRAs high demand is expected to continue for years to come.
Parker Instrumentation Products Division, with over 40 years of experience in CRAs, offers an extensive range of equipment in a variety of materials, including super austenitic grades (commonly referred to as 6 Moly), duplex and super duplex steels, Nickel- Copper alloys (Alloy 400), Nickel alloys (Alloy 825, Alloy 625, Alloy C276) and Titanium. We have the knowledge and expertise to face the fast pace of CRAs development and continuously changing and demanding market needs. We can help you engineer your success.
Table 1. Common uses of Corrosion Resistant Alloys.
Clara Moyano is Innovation Engineer - Material Science at Parker Hannifin, Instrumentation Products Division, Europe.
As we move into the future, the need for transportation is merging with society’s concerns about pollution, climate change, depletion of natural resources and the long-term sustainability of our planet — driving the adoption of alternative fuels and technologies.
In 2017, thousands from across the transportation industry attended the Advanced Clean Transportation (ACT) Expo in Long Beach, California on May 1-4 to learn about the latest alternative fuel technologies, policies, and the leading organizations driving innovation and sustainability.
Parker’s engineering experts were on-site to meet with visitors and talk about Parker’s proven multi-technology systems and components for compressed natural gas (CNG), liquid natural gas (LNG) and liquefied petroleum gas (LPG).
Parker’s unmatched offering of natural gas vehicle and fueling system products are certified to industry standards and organizational approvals, including:
“Certification marks offer peace of mind to retailers, regulators, consumers and end users the world over by indicating that your products have been independently tested and have met the required standards for safety
– CSA Group, www.csagroup.org
Here’s a review of some of the products we featured at the show:On-board fuel regulation module
Available with multiple options, the FM80 integrated gas regulator system provides advanced fuel handling performance. The piston regulator design delivers better control, fewer connections, reduced risk of leaks, and longer range. Features include:
On-vehicle CNG filters
Proper filtration is instrumental in preventing contaminants from ruining a fuel system. Installing a high-pressure particulate filter upstream of the pressure regulator removes damaging particulate matter, and installing a low-pressure coalescing filter downstream of the regulator removes unwanted oil aerosols. This two-stage system will protect engine components, reduce the risk of injector malfunction, and extend the life of the system.
Single ferrule tube fittings are designed to effectively seal and resist vibration and thermo-cycling conditions in process, and instrumentation system connections. These tube fittings utilize a single ferrule for easy make-up and excellent performance in vibration applications. The “spring loaded” effect of the single ferrule creates a constant tension between the fitting body and fitting nut. Manufactured from heat code traceable 316 stainless steel.
CNG tube assemblies
Parker’s custom tube assemblies are designed to match system specifications and eliminate warranty issues, provide increased durability and reliability, and reduce overall operating costs.
The CNGRP low pressure CNG hose is a flexible, lightweight hose that serves as primary conveyance of CNG downstream of the pressure regulator. Rated to 248°F(120°C) at 500 psi (34.5 bar).
Designed for extreme chemical and temperature applications, Parker’s metal hose offers excellent chemical resistance with zero permeation. Hydroformed design yields a uniform wall thickness, promoting even distribution of stress during flexing and reduces concentrated residual stress.
Fuel line breakaway
Specifically designed for CNG applications and pressures to 3,600 psi (248 bar), the NGVBCN2-P50 breakaway allows the hose to safely disconnect, preventing damage to the dispenser in the event of a “drive off".
Fueling nozzle and receptacle
Parker’s Kodiak Liquefied Natural Gas (LNG) Coupling was designed for fueling LNG vehicles. It offers easy single action connection with integral shut-off valves and hose swivel. Its design provides a thermal break to reduce freezing of the locking mechanism. The rugged Kodiak nozzle and receptacle wear surfaces are manufactured from hardened stainless steel for maximum resistance to wear and damage.
LPG control valves
LPG control valves are used on-board propane powered vehicles including school buses, transit vehicles, delivery trucks, and a growing number of propane autogas applications.
High-pressure CNG valves
Located between the pressure regulator and fuel injection system, Parker high-pressure, high-flow, two-way normally closed valves offer the highest burst pressure available. These valves can be combined with a coalescing filter, lowering the amount of contaminated natural gas within a system.
This post was contributed by Steve Duricky, business development manager, Parker Hannifin
Manufacture of cryogenic valves where oxygen is present requires careful adherence to strict BAM and DIN standards to avoid ignition during use.
It is a well known fact that oils and grease can spontaneously ignite and burn explosively in atmospheres which are enriched with oxygen. Indeed, all organic materials and most metals and metal alloys burn in oxygen. Oil and grease can cause a chain reaction in oxygen equipment which may even cause metal to burn or melt.Never lubricate a valve spindle with oil or grease.
When oil and grease come into contact with oxygen within a cryogenic valve, the remains of melted or burned metal are ejected out of the valve casing and oxygen can then leak out. This can cause fire to spread intensely and quickly to neighbouring inflammable material outside of the equipment. Oil and grease must therefore never be used to lubricate a valve spindle if it comes into contact with oxygen.
This is why it is so important when purchasing valves that are to be used in applications where oxygen is present to ensure they have been degreased for oxygen duty.Ensure that valves are inspected and checked for presence of oil and grease.
Image 1. Parker Bestobell's cryogenic globe valve - degreased for oxygen duty, assembled in clean room conditions and pressure tested prior to dispatch.
In many industrial systems, shut-off valves are installed and the screw threads are lubricated with oil and grease to reduce friction, which can cause an issue if oxygen is present within the application. To avoid this, it is essential to ensure that all valves are inspected and checked to ensure they are free from oil and grease. With Parker Bestobell’s valves these checks are carried out prior to despatch to the customer.Use only material and parts approved for the relevant operating conditions.
Pressure influences material behaviour, for example, by decreasing the ignition temperature and increasing the combustion speed. Therefore, in a pressure oxygen system, we use only materials and parts for which the design is approved for the relevant operating conditions.
To avoid any issues, Parker Bestobell valves are properly prepared through the use of suitable material pairs and a special construction design and careful manual finishing of the individual assembly under special clean room conditions. All materials used are tested at the Federal Institute for Material Testing (BAM) with test procedures in accordance with DIN EN 1797 in order to verify their usability in connection with oxygen.Parker Bestobell's valve cleaning procedures.
To check for the presence of oil and grease, each valve is subjected to a cleaning process specifically developed for the valve, regardless of its later use. Cleaning results are regularly monitored and are subject to the requirements of the European Standard EN 12300 “Purity for cryogenic operation”. Actual values must be far below the limiting value of 500 mg/m² stipulated in this standard because some customers’ specifications only allow 100 mg/m².
Due to our special cleaning procedure, Parker Bestobell achieves a purity value below 20 mg/m², which is four times lower, therefore greatly reducing any risks of ignition. The high purity of our cryogenic valves is documented and confirmed in the acceptance test certificate, providing reassurance to customers.
As a result, all Parker Bestobell cryogenic valves are suitable for oxygen use, which means that special instructions on the presence of oil and grease are not necessary for the customer to specify.
Steve Fidler is Product Manager, Bestobell Industrial Valves, Instrumentation Products Division, Europe of Parker Hannifin.
In the past, the process of product manufacturers supplying into Russia was relatively straightforward. The manufacturer (ie. Parker) gained a GOST R certificate for the product, which was the state standard obligatory certificate of compliance. The system builder then specified GOST R parts from Parker and if the product had the certification it could be supplied straight through to Russia.EAC Eurasian Conformity Certificate
Since the formulation of the Customs Union in 2010, involving Russia, Belarus Kazakhstan, GOST R has been superseded by the “EAC” Eurasian Conformity Certificate. Each EAC certificate conforms to one of the TRCUs (Technical Regulations of the Customs Union). The EAC has also been extended to Armenia, Tajikistan and Kyrgyzstan.
There are five types of TRCU certificates that could be relevant to Parker customers:
There are also two types of certificates, depending on the characteristics and application of the equipment.
The first is a Declaration of Conformity. Here the company effectively ‘self certifies’ the equipment, which requires them to submit just the technical details of the equipment to an accredited certification body.
The second is a Certificate of Conformity, which requires validation by an independent notified body, who would be required to inspect the manufacturing facility and carry out independent tests on the equipment being certified. There are independent notifiable bodies within all major markets who can provide this service and issue a certificate. The certification is usually valid on that equipment or system for between one to five years.Attaining EAC Certificate
One of the main differences for manufacturers outside Russia is the need to be supported when seeking an EAC Certificate of Conformity by a representative of the territory of the Eurasian Customs Union. This means that it is not possible for a manufacturer that is not registered in one of the countries of the Customs Union, to attain the EAC certificate independently. The applicant can be either a subsidiary of the producer on the territory of the Custom Union EAC, an importer, a distributor or a company that provides representation services.Parker Moscow
Parker has responded to the need for EAC certification to achieve TRCU standards by working through its local sales office in Moscow. This means we have achieved EAC certification for the majority of our products.
All our packaging destined for Russia or products being manufactured for Russia are now marked with the EAC certification on the packaging. There are clear guidelines from TRCU on the use of the EAC certification – in terms of size of the logo and visibility of the package space. Over the coming months, we will start product marking every certified product with the logo. As we have most of our products certified to EAC, this means we can supply into Russia quickly, effectively and with relative simplicity.Certification requirements for system builders.
One of the areas where the new certification method differs from GOST R is that the system builder is now also required to secure certification, either declaration or full, depending on the application. It is not enough just for the Parker product to have achieved this.
Companies who wish to sell to the Russian market need to be aware of the changes and the process of obtaining their own EAC certificate. For further details, visit the official TRCU website.
Graham Johnson is Product Manager, Downstream Analytical, Parker Hannifin, Instrumentation Products Division, Europe
One of the problems recognised early on with the storage of gases as liquids at cryogenic temperatures (typical -150oC) is boil-off gas (BOG). This occurs when heat from a variety of sources transfers into the tank causing the liquid to boil and the pressure in the tank to rise.What causes boil-off?
A number of conditions can lead to boil-off gas within a cryogenic vessel, this includes
For obvious reasons, cryogenic gases are stored in tanks at temperatures below their boiling point. This means that when heat enters a cryogenic tank during storage or transportation, some of the product in the tank continuously evaporates and boils off.
If there is a large temperature differential between the media being stored and its environment, heat ingress can occur through the floor, wall or roof of storage tanks by conduction, convection and radiation. When boil-off occurs it can lead to a great deal of product wastage – and once started, it can be continuous throughout the tank.Heat and pressure control
To minimise the risk of BOG, it is important to first understand that temperature and pressure are directly related. Inside the tanks, the product exists in an equilibrium between a thermodynamic liquid and vapour, depending on the given pressure and temperature. As temperature increases in an industrial gas storage tank, so does the pressure.
Controlling heat and pressure are the most important concerns of the cryogenic industry. Here the aim is to limit the transfer of heat into the cryogenic vessel when it needs to be stored or transported. By doing this it prevents boil off from occurring and liquid turning to vapour and venting from the tank.Choosing the right cryogenic valve
A great deal of innovation has gone into both the design of storage tanks and valves to minimise the risk of boil off. The boil-off effects of a very cold liquid hitting much warmer metal (the tank) need to be minimised. Innovation within Parker Bestobell has resulted in valves that are designed with minimum material mass to ensure cryogenic operating temperatures are reached as quickly as possible. This improves cool down times and reduces boil off when the product is in contact with the valve, therefore lowering risk.
Cryogenic storage tanks are also designed to minimise the heat that is transferred from the warm external environment into the cryogenic liquid so that vaporisation is less than 0.05% of the total tank content per day. Choice of cryogenic valve is essential to ensure the design is effective in reducing the risk of boil-off gas under cryogenic conditions.
Steve Fidler is Product Manager, Parker Bestobell Industrial, Instrumentation Products Division, Europe.
Instrumentation tubing clamps are often used in very arduous environments, where they are faced with severe environmental conditions and high temperatures. The correct specification of clamp is therefore vitally important as there are materials available which can withstand these harsh conditions.Material selection
High temperatures can cause an issue with some clamp designs as they are not manufactured specifically to withstand them. For example:
For many applications in the oil and gas, petrochemical and industrial sectors, these clamps would not be sufficiently robust.
The obvious choice is metal clamps. And, in some cases aluminium is used, which operates effectively up to temperatures of 300oC but it does have the risk of galvanic corrosion when used in combination with other materials.6Mo - corrosion and heat resistant material
The Norwegian offshore standard NORSOK Z-CR 010 states that instrumentation tubing clamps shall be made of non-corrosive material, stainless steel AISI 316 or flame resistant plastic. However, our experience in the oil and gas industry and extensive investment in R&D has led us to conclude that in most cases only 6Mo material will do. Super austenitic stainless steel 6Mo is a high performance alloy designed specifically for providing corrosion and heat resistance. 6Mo is renowned as a material that has an extremely high temperature tolerance, making it suitable for a wider range of upstream and downstream applications. It is often used as a replacement in critical components where alloy 316/316L has failed or is considered unsuitable.Parker’s Snap-Trap®+ tube clamp system
Instrumentation clamping can be exposed to extremely high temperatures either via the temperature of the internal media or externally, as in a recent project that Parker supplied. Working through an EPC contractor, Parker recommended the instrumentation clamp Snap-Trap®+, manufactured from 6Mo, to a cement works in Spain. The tubing lines were manufactured from 316 Stainless Steel and passed very close to the hot kiln, where temperatures were in excess of 500oC. Parker’s Snap-Trap®+ clamping system was specified as it is capable of withstanding these high temperatures and could effectively hold the tubing lines in place without risk of deterioration of the clamps.
Snap-Trap®+ is also very quick and easy to install and requires no nuts or spanners – just a simple tool working on a lever principle ensures correct installation quickly. This can help to reduce installation costs and allow productivity to begin earlier.
So, when it comes to instrumentation tube clamps for offshore or other hazardous environments, specifying 6Mo is essential. Opting for toughened plastic, or even 316 Stainless Steel, can lead to issues with inability to withstand high temperatures or corrosion. Use of 6Mo clamps and tubing avoids these issues and therefore extends asset life and improves levels of safety in critical operations.
Jim Breeze is Product Manager, Instrumentation Connections and Process Valves, Parker Hannifin, Instrumentation Products Division, Europe.
Providing uninterrupted power for monitoring and control equipment is essential in many oil and gas upstream, midstream and downstream applications, from a safety, economic and environmental point of view. The nature of these operations places them in remote locations, which means they are off the electrical power grid. This further implies a sparse population, with limited engineering and technical resources available to maintain these assets. In addition, these locations are usually accompanied by harsh, inhospitable conditions, such as extreme cold, intense heat, or the challenging conditions of being offshore.
The focus for many oil and gas companies is to ensure sufficient primary and back-up power should they experience loss of voltage from their battery systems. The batteries used can be either Lead Acid or Lithium Ion. Since batteries are drained when connected to a load, there is a growing need for a reliable battery charging options.
There is also a drive to reduce emissions in the oil and gas sector, which is leading to increasing interest in technologies that consume little to no hydrocarbons and have a positive environmental impact.
Having readily available ‘on-demand’ battery charging capability is a very attractive proposition for companies operating in remote, off-grid locations. Providing an extremely compact battery charger, offers greater convenience and space saving benefits in a space-restricted offshore operation. Lastly, there are transportation and storage benefits of using these kinds of compact designs in offshore or land-based, remote locations.
Using back-up power directly from the grid can be expensive, which is why more operators in remote locations are choosing renewable forms of energy such as solar, turbine and wind to power electronic instruments on gas pipelines.
Differential pressure battery chargers, like an alternator in a car, ensures the battery maintains its charge by providing a cyclic burst of energy for the instances when the battery voltage drops below the set level. When the voltage drops, the control system will detect the need to charge the battery and allow the gas to pass through the turbine to generate the current needed to charge the battery. When the power in the battery returns to the required voltage, it will enter into standby mode until the next charging cycle.
Parker offers the DB1 Differential Pressure Battery charger as an alternative to solar panel systems and large battery packs that are used to power electronic instruments on gas pipelines. Unlike solar panels, the DB1 can be installed in almost any location and is not affected by snow, ice, rain or dust build up. It is also extremely compact and lightweight and is capable of charging 365/24/7 on demand.
The DB1 is capable of producing a 12 or 24 volt power output to keep the battery fully charged in remote locations. It consistently monitors the battery’s temperature and charge level and produces up to 50 watts of power.
A growing application for this type of battery charger is Well Injection. Well injection applications stimulate the flow of oil. The pressure difference between the gas being injected into the well and the pressure resulting from the gas exiting the well is what spins the turbine on the DB1. This is particularly relevant on off-shore platforms, where there are unmanned well jackets.
The most common application is at the city gate stations or what are called regulator stations. These sites are located on the outer limits of a city on a gas pipeline. Gas pressure is reduced from 800-900 psi to 100-200 psi. This pressure difference is what is used to spin the turbine and generate the charge for the battery.How the technology works
Battery chargers, such as the DB1, use the differential pressure developed across a pressure regulator on natural gas pipelines to run a small turbine-powered generator. Controlled start-up for these kinds of units makes turning the system ‘on’ as simple as flicking a switch. The generator output is used to charge a lead acid battery – similar to our Thermo-Electric Chargers (TECs). However, unlike the TECs, the DB1 does not consume any natural gas. Power is produced by allowing a small portion of the gas (up to 1440 psig system pressures) to flow through a turbine, bypassing the pressure regulating valve. The amount of gas flowing through the turbine is low relative to the total line flow, and remains stable, keeping the DB1 transparent to the pressure control system. The pressure regulator automatically adjusts for the slight decrease in flow resulting when the DB1 runs.
The power produced by the DB1 is micro-processor controlled to provide the ideal temperature compensated battery charging current and voltage to the battery. The DB1 also provides internal diagnostics to detect possible system problems. The system status can be locally or remotely monitored using the open collector alarm output. An optional communications controller is available to provide real-time communications with the DB1.Differential pressure battery chargers
Demand is increasing for differential pressure battery chargers. Some of the reasons why include the ageing workforce increase and the skills shortage are important socio-economic factors. These factors point to a lack of knowledge transfer particularly with regards to asset maintenance. In addition, oil and gas companies are also looking to reduce their power usage.
The DB1 can be used anywhere in the world. It can be installed directly on the pipeline as it is Class 1 Division 1, Group D. As a compact unit, the DB1 is the right system for the times, as it meets all the requirements for no emissions, no use of conventional power, compact design and minimal user intervention. It is therefore little surprise that there was been an increase in demand for these products to meet the needs of the oil and gas industry.
B.J. Jackson is product manager, Parker Hannifin, Instrumentation Products Division