Plunger lift technology has been applied systematically and successfully to unload liquids from marginal tight gas and coalbed methane wells in San Juan North Basin. This article presents the recommended practices, case studies, and results of excellent plunger lift application and optimization. A production increment of over 4 MMcfd has been achieved and sustained on about 40 plunger lift installations. Most wells that were chosen for plunger installations were either on a plug and abandon (P&A) list or on temporary abandon (TA) status. Neither gas production nor anticipated production uplift from wells could justify installation of a more costly artificial lift system such as sucker-rod pump to de-water wells. Amazingly, production uplift of more than 200 Mcfd, and/or production increment of over 300%, was realized on some wells. It important to note that many operations use the practice of surfacing plungers by auto-venting, thereby releasing greenhouse gas (GHG) into the atmosphere. Plungers were operated successfully in San Juan North operations without this practice. All these results were achieved through applications of new plunger lift technology, efficient plunger type selection, monthly and quarterly reviews, proper maintenance, optimization and monitoring, i.e. effective utilization of plunger lift data. The strong alliance that was formed with the plunger equipment provider was one of the important inputs to our plunger lift journey. This new approach is a significant departure from the conventional ways of operating plungers, whereby service companies traditionally supply plunger hardware to the producing companies to operate with little "service" involved. Also, the field operations' teams, with their perseverance, offered a very important contribution to this successful venture. Introduction Gas wells, as a result of depleting reservoir pressure, show a decrease in production over time. The liquids that are associated with the produced gas tend to accumulate in the gas well. The associated liquids could be water, oils or condensates. This liquid loading heightens and futher reduces the gas flow rate. Turner et al.1 and Coleman et al.2 models, give the minimum gas flow rates required to lift the entrained liquid droplets at certain wellhead pressure. There are a host of artificial lift methods3 available to de-liquefy gas wells, one such method being plunger lift. Given the consideration of low rates, economic feasability, well characteristics and mechanical integrity, plunger lift became the obvious choice. Plunger lift is an intermittent form of artificial lift which utilizes the natural energy of the reservoir to lift the liquids out of the wellbore. The feasibility and consideration of plunger lifts are discussed in the literature4–9. This article brings to light success stories of wells with low flow rates that were not producing to their full potential and would at times have to be shut in to build up pressure. The operator and plunger provider tie-up coupled with vital input from the field helped establish a setup wherein regular monitoring and field input resulted in a production increment of over 4 MMcfd for about 40 wells. The wells were chosen on the basis of their plunger viability, and plunger selection was made based upon sealing, depth of down-hole stop, bottomhole pressures, line pressure, annular communication, sand and paraffin production, etc. The availablity of the SCADA system allowed dynamic monitoring of changes and their effect on the wells. In addition to conventional plunger lift, multi-stage plunger lift technology was used, and plunger enhanced chamber lift (PECLTM) 10 is being considered for the future. Details are provided in the following sub-sections. Geology San Juan Basin, which runs along northwestern New Mexico and southwestern Colorado (Fig. A-1), is one of the most prolific natural gas producing regions in North America. The three major reservoirs, namely upper cretaceous Dakota, Mesa Verde group and Pictured Cliffs sandstone (Fig. A-2), have produced 22 Tcf of gas as of 2004 according to Fassett et al11. The Basin and Blanco Fruitland coal, which overlies the Pictured Cliffs sand (Fig. A-2), conformably holds a resource base on the order of 50 Tcf of coal bed methane (CBM) as per Kelso et al12.

IntroductionPump slippage occurs primarily on the upstroke, occurs through the plunger-barrel interface, and serves to lubricate the plungerbarrel action. Usual industry minimum requirements are quoted to be in the range of 2 -5% of production to provide lubrication. This figure could come under scrutiny when slippage becomes better defined. If the slippage is too large, then the system becomes inefficient. This can be due to a worn plunger-barrel, and/or travelling valve, or sizing the pump with an excessive clearance.Recent tests (1)(2)(3) indicate that older equations (4,5) used by industry for years may have over-predicted the slippage. If verified, then pumps can be sized with larger clearances, reducing plungerbarrel friction, and possibly eliminating some of the compression at the bottom of the rod string without allowing excessive leakage. In this paper, a derivation of the slippage equation is developed, which also gives a contribution to slippage due to plunger velocity.Since buckling considerations may arise from pump clearance and other factors, rod buckling equations are presented and reviewed. Rods buckle due to outside forces acting up against the bottom of the rod string on the downstroke. It is well known that buoyancy forces do not contribute to buckling (6) . Thus, only negative "effective" forces that exclude buoyancy contribute to AbstractNew results for downhole beam or rod pumps from fairly recent test data are in conflict with traditional relationships. Additional testing is in progress. A pump with large plunger/barrel clearance will cause high fluid slippage. A pump with smaller clearance will cause less fluid slippage, but a tighter fit will tend to increase rod buckling at the pump to a greater degree and may lead to advanced pump and rod wear rates. Therefore, it is important to be able to predict pump slippage and also related forces at the downhole pump. Considerations for pump leakage and example calculations are presented using the older and the new pump slippage relationships. A derivation to account for the pump velocity effects on slippage is also presented. The effect of pump clearances on possible rod buckling above the pump is also studied. Further additional possible causes of rod buckling are presented, discussed, and compared. The results will help the reader to decide on sizing pump clearances to provide leakage for pump lubrication without losing too much on pump efficiency. Several ideas on the sources of rod buckling, such as flow through the travelling valve, and the plunger-barrel interaction are presented and compared. A review of methods to combat rod buckling above the pump is presented. buckling and "true forces" that include buoyancy should not be used when considering buckling. An example of how to calculate the rod projected area and buoyancy induced pressure forces is presented and examples of calculating "true forces" and "effective forces" are also presented.Contributing factors to rod buckling include the force to slide the plunger in the barrel and also ...

The rising portion of plunger cycle makes use of some type of designed sealing mechanisms on the plunger. These sealing techniques reduce the amount of gas that bypasses (leakage) the surfacing plungers. When falling, many plungers have mechanisms designed to allow increased leakage or slippage enabling the plungers to fall faster. Modeling techniques, for leakage about a rising plunger, shown in this paper are shown as analogous to orifice type flow restriction. For fast falling plungers the model is developed is similar to objects experiencing drag in a field of gas velocity. Data collected for this type of modeling is presented from suspension tests and confirmed with dynamic test data. Model ratification is done with some dynamic test data. Special two-piece and conventional plungers are hereby modeled from suspension and dynamic testing. The results should help the operators to select specific plunger hardware for specific conditions and should assist in modeling plunger cycles. Introduction Plunger lift is a common artificial lift method of producing liquids from a gas well to improve gas flow, usually without the addition of any outside energy or extra gas. The need for plunger lift arises as the reservoir pressure decreases and lower gas velocity fails to lift liquid from the well. The objective of plunger lift is to keep the wellbore free of liquids and associated pressure drop by lifting liquids on an intermittent basis to the surface. The feasibility of plunger lift is widely discussed in the literature[1–5]. This paper chiefly will deal with modeling and predicted results for plunger rise, plunger fall and also the lifting of liquid slugs over the plunger. The direct outcome of these results is to help assist the operators on the plunger hardware to be selected and in the set-up of the duration of the plunger cycles. Gas slips upward around the plunger when it rises in the wellbore during the plunger cycle. The percentage of leakage5 compared to the gas production is relatively small. This leakage can gradually reduce the pressure under the plunger and reduce lifting energy if too much gas slips past. However, conventionally the plunger is designed with sealing contours or mechanisms to prevent the gas from underneath the plunger to leak to the liquid slug above it. Considered here also, is the modeling of the two-piece plunger and the conventional ‘sealing mechanism’ used with plungers for the rising and falling portion of the plunger cycle. In addition, modeling for lifting of the liquid slug is also provided showing how effects of the liquid slug size can affect the average rise velocity of the plunger along with other parameters. The details can be found in the following sub sections. These new considerations in modeling help provide a better understanding, of plunger cycles and operation. Data obtained from experimental runs from a test site was input into the model developed. The experimental data was obtained by suspension and dynamic testing. The results from the models were in the approximate range of measured data, thus validating the model. Two-Piece Plunger. The plunger consists of a hollow cylindrical piston and a ball below. The hollow cylindrical piston could be changed in length, material used, thickness, size and number of grooves depending upon usage but is usually a fixed configuration with various materials available. The two-piece plunger cycle[5,6] typically requires about 5 to 10 seconds of shut-in time and the well is producing even when the plunger components are falling to the bottom of the tubing. The model developed is presented in Appendix A. Fig. D-1 shows the various types of two-piece plungers currently being used in the industry and Fig. D-2 shows the mechanical components. The shifting rod seen in Fig. D-2 generally has a taper to it with large diameter towards the bottom of the rod. This helps facilitate holding the hollow cylinder at the top while the well is producing.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractUsing adiabatic compression of gas in the pump, a model is shown that can be used to calculate the down-hole pump dynamometer card for various degrees of pump fill of liquids and gas at various degrees of pressure. The load release portion of the card is emphasized. It is shown how the lower pressure gas in the pump promotes what is commonly termed fluid pound or slap and higher pressure gas in the pump promotes what is termed gas interference.The equations that are needed to model these effects for inclusion into wave equation pump models are presented and example calculated pump cards are shown, calculated from wave equation simulations. Since even with so-called fluid pound, gas is first compressed before the plunger encounters the mostly incompressible fluid in the pump, the traveling valve always encounters compressed gas sufficient to open the valve before the plunger "hits" the fluid. This is true as long as gas is in the barrel when incomplete fluid fill occurs. Given this fact, the time step in wave equation solution is examined as the load release in the so called "fluid pound" can happen over a very short time and longer time steps in the wave equation simulation could mask forces from short term forces.The effects of rapid load release on forces in the rods are studied vs. what the forces might be due to the commonly supposed forces from impact with the fluid when "fluid pound" is modeled. Other parameters such as pump fillage, intake pressure and sinker bars are examined for their effects on calculated rod compression

Presented here is an analysis of an artificial lift concept, which is to "rope-lift" liquids out of the wellbore, based on viscous drag between the moving rope and a liquid column in the annular space of the inner tubing wall and the rope ( Figure 1). This differs from other methods of lift with details in References (1) and (2), and other methods summarized by Brown (3) . AbstractThe Conveyer Lift Pump uses viscous drag to lift liquids. The pump utilizes a flexible continuous rope or conveyer, affixed about a sheave at the top and bottom of the well moving upward inside the production tubing, viscously dragging or lifting the fluid from the well. Presented here are mathematical derivations for the flow rate, the quantity of fluid to be lifted, the required drag force at the rope surface, the power input required by the system, and efficiency of this lift system. Concentric and eccentric solutions are presented.