Thank you for your interest in becoming a member of the Society of Petroleum Engineers (SPE), the place for oil and gas professionals. SPE provides unparalleled insights, shared expertise, life-long learning and community strength to fuel the success of our members and the future of the industry. By becoming a member, you are part of that! We know it can be difficult making the case for membership to your manager. The justification template below can help you highlight how an SPE membership will benefit you and your company.

The following 8 pages are in this category, out of 8 total.

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.[1][2] 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.[2] The velocity at which the plunger travels up the tubing also affects plunger efficiency[2][3][4] (Figure 1). Very low velocities increase gas slippage and lead to inefficient operation and possible plunger stall.

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.[1] 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.[1] 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,[5] [6] [7] [8] 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.[1]

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.[1] 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.[1] 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.

You must log in to edit PetroWiki. Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. The following 8 pages are in this category, out of 8 total.

Once oil and gas are located and the well is successfully drilled and completed, the product must be transported to a facility where it can be produced/treated, stored, processed, refined, or transferred for eventual sale. Figure 1 is a simplified diagram that illustrates the typical, basic "wellhead to sales" concept. The typical system begins at the well flow-control device on the producing "wing(s)" of the wellhead tree and includes: A brief description of the associated piping/pipeline systems is given next. The well flowline, or simply flowline, is the first "pipeline" system connected to the wellhead. The flowline carries total produced fluids (e.g., oil, gas, and production water) from the well to the first piece of production equipment--typically a production separator.

Reservoir inflow performance is the reservoir pressure-rate behavior of an individual well. Mathematical models describing the flow of fluids through porous and permeable media can be developed by combining physical relationships for the conservation of mass with an equation of motion and an equation of state. This leads to the diffusivity equations, which are used in the petroleum industry to describe the flow of fluids through porous media. The diffusivity equation can be written for any geometry, but radial flow geometry is the one of most interest to the petroleum engineer dealing with single well issues. The solution for a real gas is often presented in two forms: traditional pressure-squared form and general pseudopressure form.

Most hydraulic pumping systems operate in centralized field facilities (tank batteries, other lease-level facilities). Sometimes, however, only a few wells in a field are suitable for hydraulic pumping, or spacing considerations make the use of centralized facilities impractical. To address the limitations of the central battery system, single-well systems have been designed, [1][2]. These have many of the same components as centralized facilities, but have been designed for efficient use by one, or sometimes two to three, wells. Several of the manufacturers of hydraulic pumping units offer packaged single-well systems that include all the control, metering, and pumping equipment necessary.