VENDOR SUPPLIED EQUIPMENT: ENSURING PSV DESIGN MEETS PSV SPEC

Transcription

1 VENDOR SUPPLIED EQUIPMENT: ENSURING PSV DESIGN MEETS PSV SPEC Jeffrey Heil, P.E. Inglenook Engineering, Inc Amesbury Lane Sugarland, TX Brian Pack, P.E.* BP America Production Company 501 Westlake Park Blvd Houston, TX Synopsis A review of vendor packaged well site and gathering facility gas conditioning equipment demonstrates the need for owner/operator review or oversight of overpressure protection design. Abstract Gas processing facilities often include standard equipment and process units that are assembled onto one or more skids by the vendor or packager. These systems may be sold or are often rented to operators for use at their facilities. Much care is taken during procurement to ensure the packaged equipment meets various operating company standards on a wide range of design details, such as, pressure and temperature rating, metal thickness and corrosion allowances, paint color, and welding procedures; however, experience shows that the overpressure protection system design is often overlooked or looked at in isolation, which does not allow the packager to view process hazards outside of the equipment being supplied. The operator is then left to retrofit appropriate relief systems on delivery, or worse, inadequate overpressure protection systems are placed into service. The Authors will share their experience in review of several common packaged, skid mounted systems and provide recommendations for specific relief system design issues commonly found with each type of system. In closing, a work process and generalized checklist will be recommended in order to help facilitate communication between the operator and supplier of these systems, ensuring alignment exists between the operator and packager, and the relief system design is consistent with industry, or operator, standards. *The views in this paper are entirely the authors and do not necessarily reflect the views of, or conditions or events occurring at, BP America Production Company or its affiliates.

2 VENDOR SUPPLIED EQUIPMENT: ENSURING PSV DESIGN MEETS PSV SPEC Jeffrey Heil, P.E.: Inglenook Engineering; Sugarland, TX Brian Pack, P.E.; BP America Production Company; Houston, TX Introduction Operators of oil and gas processing facilities often have a unique relationship with the equipment that they are responsible for operating in a safe and cost effective manner. Due to limited internal resources, limited operations or maintenance experience, and/or in an effort to minimize engineering costs and reduce delivery time, certain common pieces of equipment found at upstream and midstream processing facilities is rented, leased or purchased in the form of a packaged equipment skid from a third party vendor or packager. A side effect of relying on a third party vendor is that the operator of the equipment does not have the same level of intimacy with the equipment design as they would if the equipment were designed for a specific facility, overseen by a dedicated design team and subject to the operator s internal quality assurance standards. While these issues can be addressed between the operator and packager through supply chain agreements, often these can become complex or difficult to enforce when large volumes of equipment are purchased or rented. As a result, procuring complex packaged equipment, such as a multi-stage gas compressor or wellhead three phase separator, is sometimes treated similarly to procuring a simple methanol injection pump skid. As long as the packaged equipment can meet the desired operating conditions such as pressure and throughput, it is often accepted by the operator and installed with few additional questions asked. Often, the smaller the operator, the more correct this generalization becomes. In this scenario, the operator assumes that the packager knows and designs to the operator s and industries design practices, while the packager assumes that the operator would have disclosed any specific requirements for the packaged skid being supplied. In many aspects of the design these assumptions are valid, largely due to various API Design Specifications for common types of processing equipment. Unfortunately, the relief system design for equipment contained on packaged equipment skids often suffers from this standardized equipment approach and in many cases may not be sufficient to prevent overpressure of the equipment or a potential loss of containment. The amount of information available as a reference for relief system design can be overwhelming to an engineer who does not have an established background in this niche of process engineering. Federally adopted regulations (ASME Section VIII, Boiler and Pressure Vessel Code), industry standards (API Standard 520 Parts 1 and 2, Sizing, Selection and Installation of Pressure Relief Devices and API Standard 521, Pressure Relieving and Depressuring Systems) and Recognized And Generally Acceptable Good Engineering Practices (RAGAGEP) can all help an engineer in designing an adequate relief system for a given process. Additionally, there are literature references that outline common relief system deficiencies at the refinery or plant level (Berwanger et al., 2000; Pack et al., 2013) and suggested methods to establish a well thought out relief system design (Wright et al., 1997; Melhem, 2013). These references fail to address the gap that forms when the design of a relief system is left partly to chance in the belief that, a) there is a basis of design developed by the packager the first place; and, b) the packager employs engineers who possess the necessary relief system design experience. It has been observed on a number of occasions for such systems that, a) the relief system design is present, but does not address all aspects of the packaged equipment operation; or, b) more commonly, there is a blanket installation of a pressure relief device on all similar pieces of equipment with no supporting

3 engineering design. The operator may be unaware of the potential problem because in their mind it is someone else s equipment and the owner must have an accurate relief system design basis for it, or they bought a complete package and the relief system design basis must be correct and included in the supporting documentation. The packager may be unaware of the potential problem because they may be inexperienced in relief system design, were not given clear guidance on relief system design requirements, or cannot fully predict the effects of equipment outside of the packaged skid being provided will have on the relief system design for the particular skid. Through the Authors experience in reviewing over 5,000 pressure relief systems in upstream and midstream operations, a trend was observed where specific deviations from industry best practices (concerns) were routinely identified in preassembled equipment skids. Specific types of preassembled equipment skids often contained similar relief system design concerns allowing some conclusions about their relief system designs to be drawn and recommendations to address these concerns to be made. This paper will discuss a series of relief system design concerns that are often found in three specific types of assembled or packaged equipment skids found at gas conditioning facilities. While many of the concerns discussed in this paper are specific to a particular piece of packaged equipment, some are common issues present in more than one type of equipment skid. The installation of non-api 526 pressure relief devices resulting in excessive device back pressure and assuming combustible fluids will not result in an area pool fire are two such examples. Beginning at the wellhead, this paper first discusses a three phase separator and inlet heater skid, often referred to as a gas production unit (GPU). From here, a typical portable compressor skid is discussed, which may be found throughout upstream and midstream processes depending on pressure requirements. The final type of packaged equipment discussed is a skid mounted dehydration unit found routinely at the wellsite downstream of the three phase separator. Following the discussion of the potential relief system design concerns with these three types of skid mounted systems, a set of recommendations is made and a specific guideline suggested assisting both the operator and the packager in ensuring that the relief system design meets the appropriate relief system specifications. Wellhead Three Phase Separator Introduction Production streams from typical on-shore oil and gas wells are conditioned through a three phase separator with some form of pre and post heating ability, usually through a heated glycol bath. This combination of equipment is often referred to as a gas production unit (GPU). The system separates the multiphase inlet stream into individual gas, oil and produced water streams that may be further processed or sent directly to storage, be it a tank or pipeline. Due to the common functionality and design criteria of wellhead 3-phase separators across a production asset and the industry in general, these systems often come in the form of a third party packaged skid unit. The packaged skid includes the choke valve, direct or indirect heated glycol bath, separator, heater fuel gas scrubber and all associated instrumentation. Multi-phase flow from the wellhead (or sand separator if one is used) is preheated through the skid mounted heater and then flows through the production choke valve, which drops the pressure from wellhead pressure to pipeline pressure or something less than pipeline pressure if downstream compression is required. After the choke valve, flow generally makes one or more passes through the aforementioned heater in order to counter some of the cooling that occurred due to the pressure drop and Joule-Thomson effects, before entering the three phase separator. Gas exits the separator where further

4 processing may occur, such as dehydration and/or compression and is then sent to a gathering system pipeline. A small secondary gas stream is often taken off of the separator, sent through a final heating pass and then depressured to the skid s fuel gas system that fuels the heater and operates some instrumentation. Oil and produced water exit the separator through independent level control valves. Liquid flow is sent downstream for further processing and/or storage. Figure 1 outlines the wellhead separation process, shows the boundaries of the packaged inlet separation skid and highlights some of the common relief system design concerns found on this type of a skid. Figure 1: Wellhead 3-Phase Separator Schematic Increased Flow through Choke Valve Wellsite separation units are designed to a maximum operating pressure and throughput capacity with a protecting pressure relief device specified that has stamped capacity greater than that of the production skid. Flow into the production skid is controlled by the production choke valve that has either a fixed or adjustable choke orifice installed. The size of this orifice and upstream wellhead pressure directly affects the amount of flow that passes through the choke valve. Increases in upstream pressure or, more commonly, the size of the orifice will result in an increase in flow to the separator. The duration of the increase in flow is a function of how much flow the formation is capable of producing. If the increased capacity of the orifice is less than the formation production rate, flow may be sustained indefinitely. If the capacity of the orifice is greater than the formation production rate, flow will become un-choked and limited by the formation once the initial pressure difference across the valve reaches steady state. In a fixed choke valve, the diameter may be increased due to erosion or erosion-corrosion of the fixed choke orifice within the device over time. Erosion or erosion-corrosion is usually greatest during the initial stages of a well s life when production pressure is also highest, further increasing the potential for higher than expected flow across the choke valve. The diameter of an adjustable choke valve can be increased through the purposeful or inadvertent opening of the valve past its intended set point, or

5 instrumentation error if the choke valve is connected to a process control system. Increases in upstream pressure are not typical during the life cycle of a wellhead, but are not impossible either. The application of enhanced recovery techniques such as hydraulic fracturing or horizontal drilling can greatly increase the production rate and operating pressure of a wellhead. The Authors have encountered installations where a vertical or horizontal well was taken off line, additional horizontal laterals drilled increasing the well s pressure, and the same separation skid reconnected when the well was brought online. Whether a separation skid is installed at a wellhead operating at a higher pressure than anticipated or the choke valve is opened beyond the current desired set point, the end result is the same: an increase in flow going to the separator. If the separator and downstream equipment can handle this increased flow, it is possible the design gap will go unnoticed until an overpressure scenario occurs and, because relief devices often have a lower excess capacity margin than the equipment they protect, a problem may arise. The most common overpressure scenario that occurs is one or more of the separator outlets getting blocked in. Closing one or more of the separator outlet valves prior to isolating the wellhead is a leading cause of production separator blocked outlets and has led to several scenarios resulting in a relief device opening. If such a scenario occurs and the protecting pressure relief device does not have sufficient capacity to handle the excess flow from the well, excess overpressure of the inlet separator may occur. Correctly identifying all credible flow related overpressure scenarios and ensuring that the installed pressure relief device has sufficient capacity to protect against them is an important aspect of the design of any separation process. Ensuring that the following flow related overpressure scenarios are accounted for in an inlet separator s relief system design will help to ensure that adequate overpressure protection is installed on the separator in question. While a standard relief system design is acceptable, an evaluation to ensure that the actual capacity the separator may be exposed to does not exceed that of the pressure relief device, must always be made. 1. Blocked Vapor Outlet The installed pressure relief device should be able to pass the maximum vapor rate entering the separator skid assuming that the upstream well is operating at its shut-in pressure and that any inlet choke valves are in their wide open position. Careful attention to erosion or erosion-corrosion allowances in fixed choke valves is also required. 2. Blocked Oil Outlet The installed pressure relief device should be able to pass the maximum oil rate entering the separator skid assuming similar conditions as for the blocked vapor outlet scenario. Careful attention should be paid to flashing potential in the oil stream as this can greatly reduce the capacity of a pressure relief device. 3. Blocked Water Outlet The installed pressure relief device should be able to pass the maximum oil rate entering the separator skid assuming similar conditions as for the blocked vapor outlet scenario. Potential for Upstream Restriction ASME Section VIII Division 1 UG-135(b)(1) states that The opening through all pipe, fittings, and non-reclosing pressure relief devices (if installed) between a pressure vessel and its pressure relief valve shall have at least the area of the pressure relief valve inlet. The intent of this clause is to ensure that the piping and equipment upstream of the relief device can pass the required relief rate, reducing the likelihood of excessive overpressure occurring upstream of the relief device connection. There are several ways that the inlet to a pressure relief device could become restricted, reducing the ability of the device to protect against an overpressure scenario. These include items such as the installation of

6 reducers, reduced port valves and valves that may fail in the partially closed position (such as butterfly valves and gate valves orientated with the stem vertical) upstream of the relief device. Less obvious but equally troublesome restrictions are also present such as filter elements, blockages in demisting pads and heat exchanger tubes as discussed in the portable gas compressor section. These blockages are often the result of wet gas, cold temperatures and inadequate insulation or heat tracing. Potential restrictions in a relief path may be found in a variety of equipment installations beyond the Inlet Separator. While these are all of concern, the potential for freezing of fluid in an upstream demister pad or within the relief device are especially relevant to upstream separation operations where wet gas streams and freezing temperatures may be present. Incidents have been observed in the past where an un-insulated pressure relief device did not open during an overpressure scenario because the cold wet gas stream inside of a separator had caused sufficient ice to form inside of the relief device inlet such that operation of the device was impaired. Contributing factors to this included insufficient heating of the separator s contents, insufficient or no heat tracing of the relief device and no insulation to retain heat from the process to reduce the likelihood of ice formation. If a demister pad is included in the separators design, it can be subject to similar concerns. The small openings in the demister pad gradually build up ice due to the wet gas stream and freezing temperatures and may eventually freeze off to a point where high pressure fluid on the upstream side of the pad cannot flow to the protecting pressure relief device on the downstream side of the pad. Ensuring that restrictions in the relief path are avoided is straight forward, but requires thinking beyond the separation skid and realizing the effects external conditions such as weather can have on the system s relief design. By ensuring the following actions are taken, restrictions in a relief system may be avoided and the ability of the device to protect against an overpressure scenario may be enhanced. 1. Use full port block valves along the relief path that are locked in the open position. Butterfly valves should be avoided and gate valves should be installed with the valve stem in the horizontal position so that a failure of the stem will not result in the gate closing the valve. 2. If relief device freezing is possible, consider heat tracing and insulating the pressure relief device, minimizing the potential for ice formation within the device internals. 3. If a demisting pad or other vessel internals are used, install the pressure relief device on the upstream or inlet side of the potential blockage so that in the event a blockage does occur, the device will relieve system pressure from the point where the pressure is being generated. Non API-526 Relief Device Spring loaded conventional pressure relief devices are designed to balance a number of objectives. They must be reliable, able to pass specified quantities of fluid under a variety of conditions and cost effective. Reliability of a relief device is ensured through the use of all mechanical components, routine testing and inspection and by ensuring that the conditions a valve is exposed to falls within a set of specific design limits tailored to ensure stable valve operation. Two important parameters in ensuring valve stability (and reliability) are the inlet and outlet pressure drop that occurs when the valve is flowing at its desired capacity. Inlet pressure drop has received some press over the past few years in industry publications (Smith et al., 2011; Bazsó et al., 2013), through industry sponsored organizations such as the American Petroleum Institute Sub Committee on Pressure Relieving Systems and the Design Institute for Emergency Relieving Systems and may play less of a factor in valve stability than once thought. Impact on stability aside, inlet pressure drop is generally more dependent on the piping leading up to the relief device than the design of the relief device. The rationale for this is that inlet fluid

7 operates at close to constant density and the relief device inlet is almost always greater in cross sectional area than the relief device orifice so choking potential is minimal. Outlet pressure drop or built up back pressure on the other hand can be highly dependent on the relief device design, especially when vapor or flashing liquid relief occurs, increasing the potential for choking and high back pressure within the relief device outlet connection. The American Petroleum Institute has attempted to help relief device users navigate the complex relief device inlet, orifice and outlet combinations that will result in the best chances for valve stability through the API Standard 526, Flanged Steel Pressure Relief Valves standard. Table 1 outlines some of the valve inlet, orifice and outlet combinations that are covered by API Standard 526 and suitable for installation on wellhead separator skids. Table 1: Select API 526 Devices Inlet API Orifice - Outlet 1-D-2 1½-D-2 1½-D-3 1-E-2 1½-E-2 1½-E-3 1½-F-2 1½-F-3 1½-G-3 2-G-3 1½-H-3 2-H-3 2-J-3 3-J-4 3-K-4 3-K-6 3-L-4 4-L-6 Unfortunately, some vendors prevalent in upstream operations manufacture pressure relief valves that do not follow API 526 design specifications. Relief valves having inlet and outlet connections of the same diameter, or an orifice and outlet connection of the same diameter, are good indicators that a valve is a non-api 526 relief device and more prone to valve instability due to high built-up back pressure. Examples of such non-api 526 relief device are shown in Table 2. Table 2: Typical non-api 526 Devices Inlet API Orifice - Outlet 1-D-1 1-E-1 1-E-1½ 1-F-1½ 1½-G-2 2-G-2 1½-H-2 2-H-2 API Standard 520 Part 1, Sizing and Selection of Pressure Relief Devices sets a built up back pressure limit for most conventional pressure relief device protecting against a non-fire overpressure scenario at 10% of the device s set point unless alternative guidance, supported by testing, from the vendor exists. While many factors such as set pressure, fluid properties and relief device outlet piping play into the built up backpressure for a relief device installation, anecdotal experience shows that the end result is sometimes an installation that does not meet API Standard 520 Part 1 guidance. Excess built up backpressure may lead to reduced valve capacity, valve instability, resulting in the rapid cycling of the valve open and closed and, in severe instances, failure of the relief device to fully open

8 when required to do so. Packaged wellhead separation skids often utilize non-api 526 pressure relief devices, especially on the separator and fuel gas scrubber that may experience excess built up back pressure resulting in overpressure of the skid, but non-api 526 pressure relief devices may be found in a variety of equipment installations. Avoiding a potential overpressure scenario due to valve instability is relatively manageable: select only ASME Certified API 526 conforming pressure relief devices and calculate the built-up outlet pressure losses for that device, ensuring that the potential for choking in the device outlet is taken into account. The potential for choking in the relief device outlet can be checked by calculating the pressure drop using a pipe diameter equal to that of the relief device outlet. It should be noted that all ASME certified pressure relief devices are tested to operate properly (even non-api 526 devices), but these are often not tested with any additional pipe fittings and thus not always realistic tests. Portable Gas Compressor Introduction Many on-shore production wells, especially in the United States, operate at lower pressure and require some form of secondary gas compression in order to meet processing and delivery requirements. Depending on the operation, gas compression may come in the form of large 1,000+ horsepower gas compressors installed in a centralized compression facility or small 100 horsepower compressors installed at the wellsite. Portable gas compressors may be used to compress the gas stream off one or more separators to pipeline pressure, to generate a high pressure gas lift stream for injection into a well or to aid in the recovery of vapors off of a site s low pressure storage tanks. Independent of size, the operation of these compressors and their design is often very similar with the only difference being the size of the skid on which they are assembled. Anecdotal experience tends to show that the smaller the compressor skid, the more common it is in the production environment and the more prone it is to relief system design deficiencies; therefore, these will be the focus of this paper (although parallels can be drawn to larger compressor skids). Gas enters the portable compressor skid through an inlet scrubber where any suspended liquids are removed from the stream before entering the first stage of compression. Gas exits the first compression stage and flows through a compressor motor driven air cooler to remove heat in the stream associated with near-isentropic compression. The stream then passes through another gas scrubber prior to exiting the compression skid if it is a single stage unit or entering the second compression stage if it is a multistage unit. Two stage reciprocating gas compressors are generally more efficient and common in this type of application. If two stages of compression are present, the gas stream enters the second stage of compression, is cooled again and then may or may not pass through a discharge scrubber before proceeding downstream. Portable compressors may be electrically driven, but in many upstream oil and gas field operations are gas driven, allowing them to be almost self-sufficient. Figure 2 outlines the portable gas compression process, shows the boundaries of a typical packaged two-stage compression skid and highlights some of the common relief system design concerns found on this type of a skid. One common issue identified with packaged equipment skids is the inability to predict the effects of factors outside of the skid limits on the skid relief systems. The potential for an increase in suction pressure during a blocked outlet is one such example of this. The potential for reverse flow from a downstream pipeline in the event of check valve failure is another. Both of these are routinely identified as having not been considered in the compressor s relief system design. Installation of the relief device downstream of the gas cooler, which may freeze off, is another common concern and is similar to the

9 concern of the freezing potential of a demister pad discussed in the potential for upstream restriction section of this paper and will not be discussed again. Secondary effects central to the skid such as an increase in rod loading above its allowable limit may also go unaddressed in a relief system design due to a lack of relief system design experience. Figure 2: Portable Compressor Schematic Secondary Effects of a Blocked Outlet Two secondary effects of a blocked compressor outlet are going to be discussed. The first, a potential increase in inlet pressure, is external to the compressor skid meaning it is influenced by factors beyond the skid boundaries that were likely not addressed in the original design. The second, a potential increase in rod loading due to an increase in the operating ratio of the compressor is integral to the compressor design, but also goes unaddressed in many designs, especially at lower suction pressures. The outlet of a reciprocating compressor may be blocked in by several different events. The most common is the inadvertent closure of a downstream valve creating a block in the downstream line. Other scenarios resulting in the same outcome include a control valve failing closed, an ice plug forming in a downstream gas cooler or a rod failure resulting in the piston of a downstream stage failing in such a position that flow through the compressor is blocked. Whatever the cause, the outcome will be one of two scenarios. In the first scenario, a high pressure, temperature, rod loading or some other process alarm recognizes conditions outside of the design envelope and shuts the compressor down before any significant raise in pressure occurs. Portable skid mounted units generally have minimal controls such as this and if they do, they are operated by a common process control system reducing the likelihood that alarm two will trip and shutdown the compressor if alarm one fails to trip. Additionally, API Standard does not allow the relief system designer to take credit for any favorable process control responses that would reduce the relief requirement for a particular overpressure scenario. API

10 Standard 521 Annex E outlines specific integrity level requirements that must be met if instrumentation credits are to be taken. This leads to scenario two where no positive control response is observed and the pressure within the system begins to build until one of the mechanical limits of the system is exceeded. A properly designed pressure relief device will protect against the latter scenario, ensuring that the pressure within the system does not exceed the system s maximum allowable overpressure. One commonly overlooked aspect of relief system design is the impact on the system in question that the upstream or downstream process may have on it. In this case, blocking the outlet of a compressor often results in an increase in inlet or suction pressure to that same compressor. If the upstream source of pressure supplying feed to the compressor suction is a producing well, the pressure within that well will begin to build as soon as the outlet is blocked, up to the well s shut-in pressure or some other limiting pressure such as an intermediate pressure relief device set pressure. Increases in upstream pressure may result in an increase in flow through the compressor and the required capacity of the relief device in question. The increase in suction pressure reduces the required compression ratio to reach relief conditions, increasing the volumetric efficiency and corresponding compressor capacity. Selecting the correct process conditions and resulting required relief rate is an important aspect of designing a pressure relief system. The second scenario is an overlooked blocked outlet resulting from the compressor s piston cylinder. Often a packager will design and supply a portable compressor skid that can be used throughout a wide operating envelope. This allows for maximum versatility in the compressor s application, but may result in some design aspects being overlooked. Specifying a compressor skid that has a large gap in the normal discharge pressure and the protecting relief device set point represents one of these gaps. For example, a compressor stage that normally compresses a 100 psia feed stream up to 400 psia has a compression ratio of 4. If the same stage continues to compress a stream during a blocked outlet scenario, until the relief device begins to open at 1,455 psia, the end compression ratio will be Compression ratios for reciprocating compressors are generally limited to a maximum of 8 per stage (GPSA Fig 13-9) as past this point, rod loading begins to climb, increasing the likelihood of damage to the compressor internals. A better design would be to set the protecting relief device to psia (pressure ratio of 6-8), allowing enough of an operating margin for proper operation under normal conditions, but also minimizing rod loading and damage potential during a blocked outlet scenario. This scenario was chosen for the sole reason that it represents a common installation observed throughout the industry, especially at older fields with lower wellhead pressures. When trying to determine the required relief rate for a blocked compressor outlet, the following thought process should typically be followed. Many of the calculations referenced in the below process are detailed in Chapter 13 of the Gas Producers and Suppliers Association (GPSA) Handbook. 1. Determine what the maximum expected compressor suction pressure will be for the blocked outlet scenario in question. 2. Using the known design details for the compressor including available horsepower, fluid at suction conditions and fluid relief conditions, determine the compressor capacity. Note that it is possible that a compressor is horsepower limited. 3. In systems that have a large difference in normal operating pressure and relief pressure, high compression ratios (> 8) may be present resulting in high rod loadings. This will most commonly show up as low or negative volumetric efficiencies. When specifying a relief device s set point, care

11 should be taken to ensure that high rod loading would not be required for relief to occur as this can result in mechanical damage to the compressor and a possible loss of containment. 4. Determine what the maximum or design flowrate is from the upstream system. A compressor can only compress the amount of gas that is fed to it and in some installations this may be less than the compressor s capacity. 5. The required relief rate should be equal to the lower of the compressor capacity or the design flow rate from the upstream system at the protecting device s relief pressure. Reverse Flow through Recycle Line Any time a downstream system operates at a higher pressure than an upstream system, there is a potential for reverse flow and possible overpressure of the upstream, lower pressure system. API Standard states that, a single check valve is usually insufficient to prevent overpressure from the higher pressure system. Depending on the installation, the reverse flow event has the potential to continue for extended durations, especially in oil and gas operations when large pipelines are involved. The most common cause of a reverse flow overpressure scenario occurring is the failure of a check valve between the low and high pressure systems, especially when compression is involved. Reverse flow in portable compression skids is usually limited to the latent failure of a downstream check valve that is not realized until a recycle or start-up valve is opened and the lower rated suction side of the compressor is exposed to higher discharge pressure. The key aspect here is that the check valve failure occurs latently and goes unidentified until the recycle or start-up valve is opened. The most common time when this sequence of events occurs is during start-up or shut-down operations when the path is open, but the compressor is not in operation. Figure 3 outlines the reverse flow path on the system drawing for additional clarity. Figure 3: Reverse Flow Path

12 Industry guidance (API Standard 521) states that if a single check valve is present on the downstream line, the full wide open failure of that check valve should be considered. In such a scenario, the required relief rate can be significant and is usually based on the capacity of the piping and fittings from the downstream high pressure source and the protected lower pressure system. If multiple dissimilar check valves are installed, the likelihood of multiple failures decreases, especially if the check valves are inspected and maintained. This is the desired design for high pressure/low pressure interfaces like those being discussed as the recommended required relief rates drops to the equivalent flow through an orifice equal to 1/10 th of the diameter of the largest check valve in the downstream line. Some installations may have more than one check valve resulting in the reverse flow case becoming a lesser relief case, but many contain only a single check valve as shown in Figure 3 with no additional valves downstream of the compression skid before encountering larger volumes of higher pressure fluid resulting in higher potential required relief rates When installing a portable compressor skid, care should be given to ensure the installed pressure relief device provides sufficient overpressure protection against any reverse flow scenarios present. The easiest way to accomplish this is to ensure that there are at least two dissimilar check valves immediately downstream of the compressor discharge prior to entering any larger vessels or downstream pipelines and that an overpressure design basis accompanies the provided documentation for the compressor. Reverse flow is especially likely when the downstream system contains a large volume of fluid. If the downstream volume is smaller, such as a small separator vessel, a settle out calculation to determine the maximum upstream system pressure should be completed as a scenario credibility check. Dehydration Unit Introduction Gas recovered from the wellhead through the use of an inlet separator will be saturated and depending on well conditions, may contain a significant amount of water. Due to the detrimental effects of water on pipeline integrity, collection and transmission pipelines have strict requirements for allowable water content. Reducing the water content of a natural gas stream then becomes an important aspect of gas production. Newer operations are beginning to incorporate centralized gas processing (dehydration, sweetening and compression) techniques, but in many cases dehydration of a saturated gas stream is completed at the wellsite. In installations such as this, the volume of gas being processed is smaller; therefore, smaller skid mounted dehydration units are often needed to meet pipeline specifications. The wet gas stream enters the dehydration skid through an inlet particulate filter designed to protect the dehydration column from contamination and prolong the quality of the glycol. Once filtered, the stream enters the contactor on the bottom and rises through the column internals, contacting lean glycol flowing from the top of the column down to the bottom. Through this exchange, glycol absorbs water from the gas stream and dry gas exits the top of the column and the dehydration skid. In some installations, the dry gas stream may pass through an overhead coalescer ensuring that no glycol is carried over in the gas stream, prior to leaving the skid. Rich glycol is pumped from the bottom of the contactor to a glycol reboiler where water is driven off of the glycol stream and vented to the atmosphere. The now lean glycol stream passes through a filter and back to the top of the contactor where the cycle is repeated. Figure 4 outlines the portable gas dehydration process, shows the boundaries of a typical packaged dehydration skid and highlights some of the common relief system design concerns found on this type of a skid.

13 Figure 4: Dehydration Skid Schematic Gas Breakthrough at Spec Break Portable dehydration skids generally contain two primary systems, the glycol or dehydration contactor and a glycol regeneration system. The dehydration contactor will usually operate at a higher pressure and is responsible for ensuring that the lean glycol contacts the gas stream allowing moisture in the gas stream to be absorbed by the glycol stream, drying the gas stream. A glycol regeneration system is then required to drive off this absorbed water vapor, usually through a combination of increased temperature and reduced pressure. As a result of the reduced operating pressure of the regeneration system, a specification break usually occurs at the level control valve connecting these two systems. In the event that the level control valve fails in the open position, glycol in the contactor would drain into the regeneration still and the higher pressure vapor within the contactor would enter the lower rated regeneration still and surge tank, resulting in a potential overpressure scenario. Depending on the design pressure of the intermediate exchangers, filters, and piping, the potential for overpressure may be present upstream of the regeneration system as well. The potential for an unidentified gas breakthrough overpressure scenario is one of the most commonly overlooked scenarios in the relief system design of existing systems for both packaged and unpackaged systems. A lack of experienced relief system design engineers involved in compiling packaged equipment only increases the potential for an undersized pressure relief device due to this scenario in packaged equipment skids. Such an oversight in relief system design is troublesome due to the high flow rates that can often occur as a result of the scenario. When credible, gas breakthrough is typically the design scenario for a system and ultimately determines the required relief device size. When analyzing a system where a specification break occurs across a control point, such as the level control valve between a contactor and regenerator, a series of steps may be taken to ensure that the potential for gas breakthrough is taken into account.

14 1. Determine the maximum normal operating pressure of the upstream gas contactor. This may require reviewing upstream systems such as a gas compressor, inlet separator or well head. In wellsite operations, this will usually be the highest possible upstream pressure or is limited by an upstream pressure relief device. If this maximum upstream pressure is less than the lowest MAWP of the system in question, then overpressure due to gas breakthrough is not credible. 2. If the maximum upstream pressure exceeds the lowest MAWP of the system in question, gas breakthrough is most likely credible. The next step should be to look at the volume of liquid present in the upstream system and the available vapor space in the protected system. If the upstream volume exceeds the available downstream volume then liquid relief may also be a credible overpressure scenario and will occur before gas breakthrough does. If there is sufficient vapor space to handle the liquid, then only vapor relief of the gas breakthrough is typically needed, but cases may be present requiring two-phase relief consideration. 3. The required relief rate for a gas breakthrough overpressure scenario should be determined based on the maximum upstream (gas contactor) pressure as previously discussed, the piping and fittings along the flow path and the protected system s (glycol heater / still) maximum allowable overpressure. This often includes a combination of pipe, control valve and possibly orifice flow calculations. Combustible Liquid Pool Fire NFPA 30, Flammable and Combustible Liquids Code states that it shall apply to the storage, handling, and use of flammable and combustible liquids NFPA 30 is one of the underpinning guidelines, and in many states a regulation, that requires the protection of pressurized vessels against the effects of an external or pool fire. Most of the work in industry has centered on flammable liquids (Flash Point < 100 F) and specifically liquids that closely resemble gasoline. As a result of this focus, a common misconception exists that only flammable liquids may form a pool fire capable of overpressuring a pressure vessel. As stated by the opening section of NFPA 30, combustible liquids (Flash Point 100 F) are also capable of fueling a pool fire and resulting in an overpressure scenario. When reviewing systems containing or in the vicinity of combustible liquids such as lube oil, glycol, non-aqueous amine and sulfur, the argument that pool fire is not credible as no flammable liquids are present is routinely made. It is the hope of the Authors that the scope of NFPA 30 corrects this misconception and opens the door for a discussion on how different types of liquids may impact a systems relief system design basis. While the system being discussed is a glycol dehydration column, the key points of this discussion are equally applicable to other combustible liquids found in the gas processing industry such as amines, lube oils and molten sulfur. The glycol contactor, filters, heater, surge vessel and make-up storage tanks represent a significant quantity of glycol that may be onsite and in the immediate vicinity of a glycol dehydration skid; therefore, the formation of a pool fire fueled by this glycol should be considered. One important aspect that does require consideration is the heat content of glycol compared to gasoline, which is the basis for industry s common fire heat input calculations. API Standard provides guidance for calculating the heat input for typical hydrocarbons such as gasoline or kerosene and are used for the majority of external fire required relief rate calculations. As these may result in overly conservative required relief rates for fluids having lower heats of combustion such as most glycols, more detailed calculations may be desired and are allowed by API Standard 521. One method of easily addressing the difference in heat output between different fluids is to assign a set of derating factors to the widely used API fire heat input equations (Hauser et al., 2001). Using the Burning Rate Factor formula in Hauser et al., the derating factor for a typical glycol is approximately 0.5. The

15 derating factor is directly applied to the amount of heat predicted by the API Standard 521 fire input equations having a direct impact (reduction) on the required relief rate for the external fire scenario in question. The potential for an external or pool fire scenario to have been omitted for equipment containing, or in the vicinity of, combustible fluids may be found in a variety of equipment installations beyond the Glycol Contactor. Ensuring that a system is adequately protected against overpressure due to vapor generation as a result of an external or pool fire is a scenario that can be identified and quantified as such; unless the only source of liquid in the area is not flammable or combustible, the potential for a pool fire should be considered. Liquids not representing a potential fire source are called Class 3B liquids by NFPA and are identified as having a flash point > 200 F. Once the credibility of a potential external fire scenario has been established, the required relief rate may be used using the following general guidance: 1. The liquid level used should be equal to the maximum normal liquid level in the system, including any trays or column hold-up, up to the established maximum fire height, usually 25 feet above grade. This is often a level dump set point or the elevation of the uppermost nozzle of a vessel if no other limiting factor is present. 2. Wellsites and unattended facilities typically do not contain any firefighting capabilities; therefore, credit for adequate drainage and firefighting is not usually justified. 3. When multiple vessels are protected by a common pressure relief device, the required relief rate should be calculated for each individual vessel and then adiabatically mixed to yield the total required relief rate for the system. 4. If the fluid is expected to have a reduced heat of combustion compared to gasoline, which glycol does, the burning rate factor can be calculated in accordance with Hauser et al., 2001 and applied to the calculated required relief rate. 5. Fire proof insulation as described in API Standard may be used to reduce the fire heat input and thus required relief rate for protected systems. PSV Installed Incorrectly Incorrectly installing a pressure relief device can decrease the effectiveness of a system s protecting pressure relief device. With the potential for vendor specific allowances to the installation of pressure relieving devices, this aspect of relief system design may not receive enough emphasis when it is not an integral aspect of a project. The glycol dehydrator provides an example platform to illustrate some of the most common installation errors observed. Installing a relief device below the liquid level of a vessel where vapor relief is possible, installing a relief device horizontally and using undersized common outlet lines are three issues found commonly on portable dehydration skids. One common constraint in designing and assembling skid mounted systems is that nozzle or connection availability may become limited, especially when trying to design a skid that may be used in a variety of applications from low cost off-the-shelf components. Limited connection availability may result in a pressure relief device being installed in a location or orientation on the protected system that could result in inadequate overpressure protection or damage to the device. API Standard 520 Part states that, Pressure relief valves should be mounted in a vertical upright position. Installing a pressure relief device in the upright position ensures that all of the components within the valve remain in proper alignment and that the valve reseats correctly, minimizing leakage. A horizontally orientated valve may also result in improper forces on the valve spring and, in severe instances, may prevent the device from opening properly when required to do so, leading to a potential excess overpressure scenario. Another

16 issue in horizontal installation arises when the device s tail-pipe is oriented at 90 degrees (vertical) when the connection is threaded. Cases of the resulting momentum created through the relief have unscrewed the valve from the equipment it is protecting. Relief device location plays an important role when the device is in liquid service, but vapor relief is possible. The most common situation for this to occur is in liquid filled vessels that may be subjected to vapor generation during an external fire scenario. Installing a pressure relief device below the liquid level or point where vapor liquid disengagement is expected to occur may result in significant liquid relief prior to vapor relief. If the relief device is designed for this scenario, having a liquid required relief rate equal to the rate of volumetric displacement caused by the vaporized liquid, this would be acceptable, but the device is rarely designed to such a scenario. As the volumetric displacement scenario often results in a much larger relief requirement than the vapor flow rate, it is desirable to size the relief device for the vapor relief scenario. Doing this requires that the relief device be in the vapor space of the vessel and that sufficient vapor liquid disengagement exists to preclude two phase relief from occurring. As long as the relieved fluid is not highly viscous or foamy, ensuring that the relief device is installed above the vessel liquid level or at the top of the vessel if liquid full is usually sufficient. If liquid or two-phase relief is suspected, it should be sized accordingly for these conditions and may result in a larger relief device requirement. The potential for a restriction in a relief device s inlet line is discussed for the Wellhead Inlet Separator Skid in detail. Restrictions in a relief device s outlet may not fail ASME Section VIII code, but can quickly result in high outlet pressure drop, valve instability and a reduction in relief device capacity. One installation that is common with smaller relief devices and especially when they are in liquid service is to tie multiple PSV outlet lines together to a single drain line. If the individual exit lines and common drain line are appropriately sized for all credible overpressure scenarios this would not be a problem, but proper sizing is not always completed. The principal drivers for inappropriate outlet line sizes are either missed scenarios or a failure to complete outlet pressure drop calculations in the first place. Failure to recognize that an external fire scenario may be present on a liquid glycol filter is one commonly missed scenario. Failure to account for common mode relief scenarios is another often overlooked situation. In this example, a pool fire around the glycol skid may result in the relief device on both filters opening, doubling the flow through common sections of the individual system PSV exit lines and severely reducing their capacity and ability to function properly. While quantifying the outlet pressure drop for all credible overpressure scenarios for each in-service relief device is important, the following steps may be taken to help minimize the likelihood of high backpressure on the installed pressure relief devices. 1. Whenever possible, use dedicated relief device exit lines with no in-line restrictions. 2. If a common header is to be used, such as to a glycol drain, ensure that all common mode failures such as multiple relieving devices in a single fire zone are taken into account. Recommended Guidelines for the Operator & Packager Because of the ubiquitous use of packaged equipment across upstream gas conditioning facilities and onshore production wellsites, it is important that operator and packager work together to ensure relief systems are not overlooked. While it is recognized that many packagers do not have the expertise in design of relief systems, the operator should likely take a more active assurance role to ensure relief systems are adequately assessed. This may require the use of internal operator expertise to provide a