Artificial lift is used worldwide in approximately 85% of the wells, thus its impact in overall efficiency and profitability of production operations can not be overemphasized. Selection of a particular lift method for a given application is carried out, to a large extent, by production engineers utilizing the method more readily available to them both in terms of their past experience and current access to knowledge and technology. It has been recognized for a long time, that this is a shortcoming of most engineering disciplines and results, more often than not, in sub-optimal designs. Expert systems can help engineers in quickly selecting, from updated technology, the best options available to them for the problem at hand. The work presented here describes knowledge gathering and coding techniques, general program structure, program validation runs, and field verification of SEDLA, an expert system developed to help in the selection of the best lift method for a well or group of wells.1
Summary Many low-volume gas wells produce at suboptimum rates because of liquid loading caused by an accumulation of liquids in the wellbore that creates additional backpressure on the reservoir and reduces production. Plunger lift is an artificial lift method which can use reservoir energy to remove these accumulated liquids from the wellbore and improve production. Lacking a thorough understanding of plunger lift systems leads to disappointing results in many applications. This study develops a plunger lift model that couples the dynamic nature of the mechanical plunger lift system with the reservoir performance. The model takes advantage of previous work and incorporates frictional effects of the liquid slug and the expanding gas above and below the plunger. The model considers separator and flowline effects and includes modeling of transient production behavior after the liquid slug has arrived at the surface. An improved understanding of plunger lift dynamics can lead to improved efficiency, increased production and recovery, and extended well life. Introduction A free piston or plunger traveling up and down the tubing has been used for different applications in oil and gas production for decades. The most widespread use is in conventional plunger lift. This method is an artificial lift technique characterized by the use of reservoir energy stored in the gas phase to lift fluids to the surface. Fig. 1 is a schematic of a typical plunger lift installation. The plunger acts as an interface between the liquid slug and the gas which helps reduce the characteristic ballistic-shape flow pattern of the higher velocity gas phase breaking through the liquid phase during production. With appropriate installation and well-production characteristics, gas produced by the reservoir is stored primarily in the tubing-casing annulus while a liquid slug is accumulated in the tubing. During this condition, called the buildup stage, the flowline valve at the surface is closed with some gas also accumulated in the tubing above the liquid slug. After a time, when the casing pressure at the wellhead is believed to be adequate, the flowline valve opens and production begins. Gas at the top of the liquid slug expands and the plunger, along with the accumulated liquid, begins traveling up the tubing in a period called the upstroke stage. Gas stored in the tubing-casing annulus expands and provides the energy required to lift the liquid slug. As the plunger approaches the surface, the liquid slug is produced into the flowline. In some cases, especially for gas wells, additional production after the plunger has surfaced is appropriate, increasing the flowing time for each cycle. Such a period is called afterflow in oil wells and blowdown in gas wells. After this period of flow, the flowline is closed, the buildup stage starts again, and the plunger falls to the bottom of the well starting a new cycle. Using the plunger as a solid interface between the expanding gas in the annulus and the liquid slug helps prevent gas breaking through the slug and decreases liquid fallback. Liquid fallback is undesirable because it represents volume loss from the original liquid slug during each cycle. The additional liquid increases the bottomhole flowing pressure and, hence, decreases production. In general, plunger lift installations are used to produce high gas-liquid ratio (GLR) oil wells or for unloading liquids in gas wells. Major advantages over other artificial lift methods for lifting liquids, such as sucker rod pump installations, are the relatively small investment and reasonable operating costs. Limitations include having a sufficient GLR to supply the energy for lifting liquids from the wellbore, and sand-production problems. The main disadvantages of plunger lift systems, however, are the complexity of the lifting process and a lack of understanding of optimizing and troubleshooting the lift method. Several authors have addressed the modeling of plunger lift installations. Static models have been proposed and are accepted widely for design due to their simplicity.1–3 Dynamic models also have been published to describe the phenomena of a plunger lift cycle.4–10 Accuracy of the dynamic models does not always outweigh the time and data required for designing and analyzing plunger lift system performance. The dynamic model developed in this paper overcomes some of the assumptions used in previous models. It includes reservoir performance, gas expansion with friction effects, and the transient behavior of the gas above the slug when the surface valve is opened. It also incorporates a blowdown or afterflow period for production after the liquid slug surfaces. The upstroke modeling includes a transition phase that accounts for the production of the slug to the flowline. Plunger Lift Model Fundamental conservation equations were used to derive the model, which analyzes the dynamics of the plunger lift system using properties in multiple control volumes, one next to the other, including the flowline, tubing, and annulus. The model is divided into upstroke, blowdown, buildup, and reservoir performance components. The upstroke component separates the dynamics of the plunger and liquid upstroke from the boundary conditions given by the gas system above the slug and the gas system behind the plunger. The blowdown component produces the slug to the separator and accounts for additional gas production after the plunger surfaces. The buildup component describes the increase in system pressure, the accumulation of fluids (liquids and vapors) in the system during shut-in, and accounts for the downstroke behavior of the plunger. Finally, the reservoir performance component describes the influx of fluids into the wellbore throughout the plunger cycle. Upstroke Component. To model the dynamics of the system during the upstroke, three different elements are used. Fig. 2 is a schematic of the system being modeled. The liquid slug traveling from the bottom of the well to the surface is analyzed as a separate element with given boundary conditions consisting of the pressures at the top of the slug and at the bottom of the plunger which are determined in the second and third elements. The pressure at the top of the slug is obtained by analyzing the gas expansion above the slug when the valve is opened. The pressure at the bottom of the plunger is determined by analyzing the gas expansion in the tubing below the plunger and in the tubing-casing annulus. Plunger and Liquid Slug Dynamics. For the liquid slug traveling through the tubing, a control volume occupied by the liquid contained in the slug with average properties is used. As Lea4 originally did in his work, the equation of momentum is applied for a single-phase liquid, assuming the liquid density is constant. If no liquid is gained or lost from the control volume shown in Fig. 3, the equation of momentum can be solved for the acceleration of the slug in the tubing.
Accurate determination of oil, water, and gas production rates is an important element of oilfield management and optimization. Multiphase flow meters (MPFM) are being accepted more and more for well testing, reservoir management, production allocation, production monitoring, and fiscal metering. In addition to common MPFM applications, this study shows how a multiphase flow meter may be used as a valuable tool to evaluate water production problems of the well by imposing transient flowing conditions to the well and tracking characteristic parameters such as flowrates, water cut and gas oil ratio with the equipment during the test. Representative curves are shown in this study in order to identify some common wellbore problems associated with water conformance. The curves were obtained through numerical reservoir simulation using a number of cases related to the most important problems: water channeling in stratified formations, mechanical wellbore integrity, water conning, and oil-water contact advance. The flowrate at the well should be shortened to a half of the current flowrate with a choke for several hours then, the dimensionless pattern curves of the water cut and gas oil ratio gathered in this study should be matched with the measurement of the MPFM on site in order to characterize the nature of the water problem. This application represents a new tool used to identify the sources of water production. The tool is easy and quick to apply, and complements other analytical techniques being used like diagnostics plots based on production history, water-oil ratio performance and production logs. All of them are used to differentiate between the different mechanisms of water invasion, so that an appropriate treatment may be selected to control undesirable water production. IntroductionDuring the petroleum exploitation, the production of water can come from an aquifer or from injector wells in a waterflooding process. When excess of water production exists, the costs associated to surface facilities, artificial lift systems, corrosion and scale problems increases. Besides, the recovery factor decreases as oil is left behind the displacement front. These factors reduce the economic indicators. The drastic influence of water production must be soon detected and the source of such problem must be identified in order to apply effective and suitable techniques to control this production.
Most of the world hydrocarbon reserves represent extra-heavy oils. Exploitation of most of these reservoirs has not been carried out mainly due to the difficulty to produce the high-viscosity of extra heavy oils. Cold production can be achieved in the Orinoco Oil Belt through advanced horizontal wells. However, in many cases the drawdown exerted creates gas or sand production problems or excessive water production when an aquifer exists. Primary recovery factor under these conditions rarely go beyond 6%; and 3% in the presence of an active aquifer. On the last decade several thermal mechanisms have been studied to increase the recovery of these types of reservoirs. This study analyzes the effect of bottom-hole electric heating on the production and recovery factors of extra-heavy oil reservoirs.The study was carried out by numerical simulation, analyzing the most influential parameters through an experimental matrix of 24 cases run in a horizontal well of 2000 feet. Four types of oils were studied, 8.1, 10, 12 and 15°API gravity. Reservoir thicknesses used were 300 feet and 80 feet. Two different heating rates were used (1.6e07 and 5e07 BTU/Day). The boundary conditions used in the model correspond to the installation of a typical downhole pump in Orinoco Belt. Several parameters were analyzed such as pressures, temperatures, viscosities, production rate, gas-oil ratio, in order to determine the effect of the heating. Based on this study, electric heating represents a good option for good sand quality reservoirs with low API gravity oils where a small change of temperature generates great change in viscosity. Special grid refinement must be performed within the wellbore in order to allow the simulator to accurately estimate the properties and conditions in this area where significant changes occur. Electric heating reduces the viscosity near wellbore and increases the bottom-hole pressure avoiding excessive gas liberation near the well. This creates favourable conditions for production delaying an oil relative permeability drop. Based on the simulations studied, this method increases the recovery factor up to 60% the one obtained in cold production for a typical extra heavy oil. 2
Many low volume gas wells produce at suboptimum rates due to liquid loading. This situation is caused by an accumulation of liquids in the wellbore that creates additional backpressure on the reservoir and reduces production. Plunger lift is an artificial lift method which can utilize reservoir energy to remove these accumulated liquids from the wellbore and improve production. Unfortunately, the lack of a thorough understanding of plunger lift systems leads to disappointing results in many applications. This study develops a plunger lift model that couples the dynamic nature of the mechanical plunger lift system with the reservoir performance. The model takes advantage of previous work and incorporates frictional effects of the liquid slug and the expanding gas above and below the plunger. The model considers separator and flowline effects and includes modeling of transient production behavior after the liquid slug has arrived at the surface. An improved understanding of plunger lift dynamics can lead to improved efficiency, increased production and recovery, and extended well life. Introduction A free piston or plunger traveling up and down the tubing has been used for different applications in oil and gas production for decades. The most widespread use is in conventional plunger lift. This method is an artificial lift technique characterized by the use of reservoir energy stored in the gas phase to lift fluids to the surface. Fig. 1 is a schematic of a typical plunger lift installation. The plunger acts as an interface between the liquid slug and the gas which helps reduce the characteristic ballistic-shape flow pattern of the higher velocity gas phase breaking through the liquid phase during production. With an appropriate installation and well production characteristics, the gas produced by the reservoir is primarily stored in the tubing-casing annulus while a liquid slug is accumulated in the tubing. During this condition, called the buildup stage, the flowline valve at the surface is closed with some gas also accumulated in the tubing above the liquid slug. After a certain time, when the casing pressure at the wellhead is believed to be adequate, the flowline valve opens and production begins. The gas at the top of the liquid slug expands and the plunger, along with the accumulated liquid, begins traveling up the tubing in a period called the upstroke stage. The gas stored in the tubing-casing annulus expands and provides the energy required to lift the liquid slug. As the plunger approaches the surface the liquid slug is produced into the flowline. In some cases, especially for gas wells, additional production after the plunger has surfaced is appropriate, increasing the flowing time for each cycle. Such a period is generally called afterflow in oil wells and blowdown for gas wells. After this period of flow, the flowline is closed, the buildup stage starts again, and the plunger falls to the bottom of the well starting a new cycle. The use of the plunger as a solid interface between the expanding gas in the annulus and the liquid slug helps prevent gas breaking through the slug and decreases liquid fallback. Liquid fallback is undesirable as it represents volume loss from the original liquid slug during each cycle. The additional liquid increases the bottomhole flowing pressure and, hence, decreases production. In general, plunger lift installations are used to produce high gas-liquid ratio (GLR) oil wells or for unloading liquids in gas wells. Major advantages over other artificial lift methods for lifting liquids, such as sucker rod pump installations, are the relatively small investment and reasonable operating costs. Limitations include having a sufficient GLR to supply the energy for lifting liquids from the wellbore and sand production problems. The main disadvantages, however, of plunger lift systems are the complexity of the lifting process and a lack of understanding of optimizing and troubleshooting the lift method. P. 295^
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.