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We will leave USC at 7:30 AM to take the Boat ride to the Islands at 9am. The tour will take about 2 hours and we shall return by 1pm. We will be visiting one of the 4 islands in the Long Beach Harbor that are the sites of drilling and production into the East Wilmington Oilfield. THUMS islands, built in the 1960s, allow the eastern portion of the field to be produced with environmental, spatial and logistical efficiency. Come and learn how these islands are both beautiful and practical. The tour will include a boat ride around Long Beach Harbor, a behind-the-scenes tour of one of the islands, a close-up view of an active drill rig, the production office where all the island wells are monitored, and award-winning landscaping designed by the same architect who created Disneyland’s Tomorrow Land. All must wear closed-toed, flat shoes (no heels or open-toed shoes allowed). Goggles and hardhats will be provided.
Natural-gas wells suffer from liquid loading if the gas-flow rate is insufficient to carry liquids to the surface. Because of the technique’s many advantages, plunger lift has been used widely in gas wells for the removal of liquid columns and the rescue of dying gas wells from liquid loading. Fast-declining, older, unconventional oil wells require artificial lift experts to deal with and explore a population of miles-long horizontal wells that do not follow the established rules of thumb.
An important consideration related to intermittent gas lift operations is the injection-gas breakthrough and resulting loss of the liquid production per cycle from the injection gas penetrating the liquid slug during the time required to displace this slug to the surface. The produced-liquid slug can be a small fraction of the starting slug size because of injection-gas breakthrough. The losses are greater when the injection-gas pressure is low and the required depth of lift is near total depth in a deep well. For example, a 12,000-ft well with a bottomhole flowing pressure of 300 psig and an available injection-gas pressure of only 450 psig can be gas lifted intermittently with the proper plunger. The well could not be gas lifted successfully from this depth without a plunger.
Plunger lift is commonly used for production of low volume, high gas-oil ratio (GOR) or high gas-liquid ratio (GLR) wells. A plunger lift candidate must meet GLR and pressure requirements, but the method of installation and the mechanical setup of the well also are extremely important. Installation is a frequent cause of system failure. This page focuses on the installation and appropriate maintenance of plunger lift equipment. For reference, Figure 1 is a full wellbore schematic of major plunger-lift components, and Figure 1 is a plunger-lift troubleshooting guide. Numbers represent rank in order of most likely solution. There are many plunger-lift manufacturers and equipment options, so quality and design vary. Purchasers have the ultimate responsibility for investigating the manufacturing process. Manufacturers who use International Organization for Standardization (ISO) 9000/9001 standards or equivalents help to ensure that customers will receive a quality product.
Plunger lift systems can be evaluated using rules of thumb in conjunction with historic well production, or with a mathematical plunger model. Because plunger lift systems typically are inexpensive and easy to install and test, most are evaluated by rules of thumb. Plunger lift operation requires available gas to provide the lifting force, in sufficient quantity per barrel of liquid for a given well depth. The minimum GLR requirement is approximately 400 scf/bbl per 1,000 ft of well depth and is based on the energy stored in a compressed volume of 400 scf of gas expanding under the hydrostatic head of 1 bbl of liquid. One drawback to this rule of thumb is that it does not consider line pressures.
Plunger lift is used for recovery, primarily in high gas-oil ratio (GOR) wells, in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to 1,500 psia, and liquid rates of 1 to 100 B/D. These are common ranges of application, but not necessarily limits of operation. The most common plunger lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high gas liquid ratio (GLR) oil wells, in conjunction with intermittent gas lift operations,    and to control paraffin and hydrates. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection.
Plunger lift has become a widely accepted and economical artificial lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Figure 1). Plunger lift uses a free piston that travels up and down in the well's tubing string. It minimizes liquid fallback and uses the well's energy more efficiently than does slug or bubble flow. As with other artificial lift methods, the purpose of plunger lift is to remove liquids from the wellbore so that the well can be produced at the lowest bottomhole pressures. Figure 1--Plunger installed in Canada. In recent years, the advent of microprocessors and electronic controllers, the studies detailing the importance of plunger seal and velocity, and an increased focus on gas production have led to a much wider use and broader application of plunger lift.
Figure 1.1--Plunger installed in Canada. This cycle can occur over hours or days in wells that have stabilized flow rates below the critical unloading rate. Such is the behavior of many wells that are temporarily shut in or blown to atmosphere to unload liquids. Plungers currently are being used in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to 1,500 psia, and liquid rates of 1 to 100 B/D. These are common ranges of application, but not necessarily limits of operation. The most common plunger-lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high-GLR oil wells, in conjunction with intermittent gas lift operations, and to control paraffin and hydrates. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection. For this use, when plunger lift is installed, paraffin, hydrates, and salt should be removed so that the plunger will travel freely up and down the tubing. Given initially clean tubing, a plunger excels at preventing formation of such deposits because of the scraping action of the plunger against the walls of the tubing, along with slugs of warm reservoir fluids. Wellbore configurations for plunger lift include wells with an open annulus (most desirable), wells with packers, slimhole wells (2.875-in. Also, plunger lift is used in conjunction with intermittent gas lift, external gas supplies/injection, wellhead compression, vent options to tanks or low-pressure systems, some sand production, tubing/casing flow control (three-valve controllers), and carbon dioxide (CO2) floods. Most commonly, plunger lift is applied in a gas or oil well with sufficient pressure and GLR to operate the system without additional supply gas. It is desirable to have tubing with no packer in the well. The annular space provides a storage area (volume chamber) for the gas under pressure and allows this gas to work freely on the plunger and liquid slug. Gas can flow from the casing to the tubing and provide lift with little restriction, and inflow from the reservoir is not relied on as the plunger moves up the hole. Because the stored-gas pressure provides the means to lift the plunger and liquid slug, adequate GLR and well pressures are critical.
Plunger lift is used primarily in low rate, high gas-oil ratio (GOR) wells. This page focuses on the features desired in key equipment required to operate a plunger lift operation. Desirable features in a plunger include efficient sealing, reliability, durability, and the ability to descend quickly. Rarely does a plunger exhibit all these characteristics, though. Usually a plunger that excels at one aspect sacrifices others. A wide variety of plungers is available to accommodate differences in well performance and operating conditions. The plunger seal is the interface between the tubing and the outside of the plunger, and probably is the most important plunger design element. Most plungers do not have a perfect seal; indeed, turbulence from a small amount of gas slippage around the plunger is necessary to keep liquids above and gas below the plunger. A more efficient seal limits slippage and allows the plunger to travel more slowly, which reduces the energy and pressure required to lift the plunger and liquid load. Less efficient seals allow excessive slippage, and so increase the energy and pressure required to operate the plunger. The velocity at which the plunger travels up the tubing also affects plunger efficiency (Figure 1). Very low velocities increase gas slippage and lead to inefficient operation and possible plunger stall.
A typical plunger-lift system mainly comprises a piston or plunger, a surface control valve (SCV), a catcher, a lubricator or shock spring, a bumper spring, and a plunger sensor. In addition, casing and tubing serve as key components during the plunger-lifting process. Existing plunger-lift models can be categorized broadly into static and dynamic models. Although many dynamic plunger-lift models have been studied in the literature, a universally validated model with thorough understanding of the transient behaviors of gas and liquid still is unavailable. Because of incomplete consideration of plunger dynamics or oversimplified assumptions, most existing models suffer from questionable applicability. This problem can be remedied by incorporating or proposing in-depth closure relationships and performing parametric studies to find the most-suitable one. In this study, based on previous modeling frameworks, a new transient plunger-lift model for liquid unloading in gas wells is presented. Compared with previous models, improvements have been made in the equations of plunger rising and falling velocities. The present model also accounts for different reservoir performances, which provides more-accurate and -reasonable predictions of these velocities.