Summary An oil-water flow pattern classification and characterization for wellbores is proposed based on the integrated analysis of experimental data, including frictional pressure drop, holdup, and spatial phase distribution, acquired in a transparent test section (2-in. i.d., 51-ft long) using a refined mineral oil and water ?o/?w=0.85, ?o/?w=20.0, and ?o-w =33.5 dyn/cm at 90°F). The tests covered inclination angles of 90°, 75°, 60°, and 45° from horizontal. The oil-water flow patterns have been classified into two major categories given by the status of the continuous phase, including water-dominated flow patterns and oil-dominated flow patterns. It was found that most water-dominated flow patterns show significant slippage but relatively low frictional pressure gradients. In contrast, all the oil-dominated flow patterns exhibit negligible slippage but significantly larger frictional pressure gradients. Six flow patterns have been characterized in upward vertical flow; three were water dominated and three were oil dominated. In upward inclined flow there were four water-dominated flow patterns, two oil-dominated flow patterns and a transitional flow pattern. Flow-pattern maps for each of the tested inclination angles are presented. A mechanistic model to predict flow-pattern transitions in vertical wells is proposed. The transitions to the very-fine-dispersed flow patterns were evaluated by combining the concepts of turbulent kinetic energy with the surface free energy of the droplets, while the transitions to the churn flow pattern and the phase inversion were predicted based on the concept of agglomeration. The model compares favorably with the measured data. Introduction Two-phase flow of oil and water is commonly encountered in wellbores; however, its hydrodynamic behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the oil industry. Multiphase flows are characterized by the existence of diverse flow configurations or flow patterns, which can usually be identified by a typical geometrical arrangement of the phases in the pipe. Inherent to each flow pattern are characteristic spatial distributions of the interface, flow mechanisms, and distinctive values for design parameters such as pressure gradient, holdup, and heat-transfer coefficient. There is clear evidence that accurate knowledge of oil-water flow patterns, their ranges of existence as a function of flow rates and pipe inclination angles, and values for their associated hydrodynamic parameters are crucial in a number of production-engineering applications. These include production optimization, optimum string selection, production-logging interpretation, downhole metering, and artificial lift design and modeling. Additionally, the understanding of oil-water flow in wellbores is fundamental in determining the volumes of free water in contact with the pipe that could cause scaling and corrosion of the pipe after prolonged exposure. This paper addresses the fundamental problem of identifying and characterizing oil-water flow patterns and predicting flow-pattern transitions for conditions pertinent to oil-water producing wells. Literature Review Despite being a subject of permanent interest for the petroleum industry, the issue of oil-water flow patterns in wellbores has barely been addressed in the technical literature. A limited number1–3 of experimental studies have been found that provide a description of the flow patterns for low-medium viscosity oil and water. Govier, Sullivan, and Wood1 and Zavareh, Hill, and Podio2 conducted investigations in vertical flow, while Scott3 and Zavareh, Hill, and Podio covered inclinations near the horizontal and near the vertical, respectively. A larger number of related studies concentrated on measuring the holdup, mainly for oil-dispersed systems, focusing on finding expressions for the slip velocity that could be used in the interpretation of production logs. More recently, Hasan and Kabir4 and Tabeling et al.5 provided the first insights into the modeling of oil-water flow in wellbores. The vertical oil-water data available in the literature1,2,6 suggest that the flow patterns can be grouped into two major categories, including a water-dominated region and an oil-dominated region. Also, Govier, Sullivan, and Wood reported a highly turbulent region between the oil- and water-dominated regions, that was designated as slug flow, in analogy to gas-liquid flow. However, the flow-pattern classification and designation in analogy to gas-liquid flow does not provide a clear and distinct description applicable to oil-water flow. For instance, the so-called slug flow denotes a disorganized distribution of different size droplets but without the presence of a clearly defined bullet-shaped droplet that characterizes slugs and Taylor bubbles in gas-liquid slug flow. Moreover, the fundamental slugging mechanisms of pickup and shedding are not likely present in oil-water flow. The investigation of Zavareh, Hill, and Podio supports the existence of water- and oil-dominated regions; however, it did not distinguish any flow pattern at the transition between the two flow regions in vertical flow. Since their study was conducted in a large-diameter pipe, Zavareh, Hill, and Podio gave only limited information of the flow patterns occurring at high flow rates. Nevertheless, they identified a finely dispersed flow pattern called dispersed-bubble flow, occurring at high water flow rates, that was not reported by Govier, Sullivan, and Wood. The two studies2,3 conducted in inclined pipes were limited to flow patterns in the water-dominated region. There are no published flow pattern data in the oil-dominated region for any inclination other than vertical and horizontal, and no information on the oil-water flow patterns existing for inclinations ranging from 30° to 75°. There are very limited data relating flow patterns and their associated hydrodynamic parameters, including holdup and pressure drop, for most operational oilfield conditions.

Two-phase flow of oil and water is commonly observed in wellbores, and its behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the petroleum industry. Among the most significant applications of oil-water flow in wellbores are production optimization, production string selection, production logging interpretation, down-hole metering, and artiflcial lift design and modeling. In this study, oil-water flow in vertical and inclined pipes has been investigated theoretically and experimentally. The data are acquired in a transparent test section (0.0508 m id., 15.3 m long) using a mineral oil and water {po/p^ = 0.85, MO/MW = 20.0 & Oo-^ = 33.5 dyne/cm at 32.22° C). The tests covered inclination angles of 90, 75, 60, and 45 deg from horizontal. The holdup and pressure drop behaviors are strongly affected by oil-water flow patterns and inclination angle. Oilwater flows have been grouped into two major categories based on the status of the continuous phase, including water-dominated and oil-dominated flow patterns. Waterdominated flow patterns generally showed significant slippage, but relatively low frictional pressure gradients. In contrast, oil-dominated flow patterns showed negligible slippage, but significantly large frictional pressure gradients. A new mechanistic model is proposed to predict the water holdup in vertical wellbores based on a driftflux approach. The drift flux model was found to be adequate to calculate the holdup for high slippage flow patterns. New closure relationships for the two-phase friction factor for oil-dominated and water-dominated flow patterns are also proposed. Introductory RemarksIn the petroleum industry, multiphase flow is a common occurence in production of oil and gas. Two-phase flow of oil and water is commonly encountered in wellbores; however, its hydro-dynamic behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the oil industry.Multiphase flows are characterized by the existence of diverse flow configurations or flow patterns, which can usually be identified by a typical geometrical arrangement of the phases in the pipe. Inherent to each flow pattern are a characteristic spatial distribution of the interface, flow mechanisms, and distinctive values for design parameters such as pressure gradient, holdup, and heat transfer coefficient. There is clear evidence that accurate knowledge of the oil-water flow patterns, their ranges of existence as a function of flow rates and pipe inclination angles, are crucial in predicting many hydrodynamic parameters. These include pressure gradient and holdup in a number of production engineering applications, such as production optimization, optimum string selection, production logging interpretation, downhole metering, and artificial lift design and modeling.A fundamental problem in production engineering is to determine the actual volumetric flow rates of each of the phases flowing at any location in the wellbore. This in...

An oil-water flow pattern classification and characterization for wellbores is proposed based on the integrated analysis of experimental data, including frictional pressure drop, holdup and spatial phase distribution, acquired in a transparent test section (2 in. ID, 51 ft long) using a refined mineral oil and water (=0.85, =20.0 and =33.5 dyne/cm at 90 F). The tests covered inclination angles of 90, 75, 60 and 45 from horizontal. The oil-water flow patterns have been classified into two major categories given by the status of the continuous phase, including water dominated flow patterns and oil dominated flow patterns. It was found that most water dominated flow patterns show significant slippage but relatively low frictional pressure gradients. In contrast, all the oil dominated flow patterns exhibit negligible slippage but significantly larger frictional pressure gradients. Six flow patterns have been characterized in upward vertical flow; three were water dominated and three were oil dominated. In upward inclined flow there were four water dominated flow patterns, two oil dominated flow patterns and a transitional flow pattern. Flow pattern maps for each of the tested inclination angles are presented. A mechanistic model to predict flow pattern transitions in vertical wells is proposed. The transitions to the very fine dispersed flow patterns were evaluated by combining the concepts of turbulent kinetic energy with the surface free energy of the droplets, while the transitions to the churn flow pattern and the phase inversion were predicted based on the concept of agglomeration. The model compares favorably with the measured data. Introduction Two-phase flow of oil and water is commonly encountered in wellbores; however, its hydrodynamic behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the oil industry. Multiphase flows are characterized by the existence of diverse flow configurations or flow patterns, which can usually be identified by a typical geometrical arrangement of the phases in the pipe. Inherent to each flow pattern are characteristic spatial distributions of the interface, flow mechanisms and distinctive values for design parameters such as pressure gradient, holdup and heat transfer coefficient. There is clear evidence that accurate knowledge of oil-water flow patterns, their ranges of existence as a function of flow rates and pipe inclination angles, and values for their associated hydrodynamic parameters are crucial in a number of production engineering applications. These include production optimization, optimum string selection, production logging interpretation, -downhole metering and artificial lift design and modeling. Additionally, the understanding of oil-water flow in wellbores is fundamental in determining the volumes of free water in contact with the pipe that could cause scaling and corrosion of the pipe after prolonged exposure. This paper addresses the fundamental problem of identifying and characterizing oil-water flow patterns and predicting flow pattern transitions for conditions pertinent to oil-water producing wells. Literature Review Despite being a subject of permanent interest for the petroleum industry, the issue of oil-water flow patterns in wellbores has barely been addressed in the technical literature. A limited number of experimental studies have been found that provide a description of the flow patterns for low-medium viscosity oil and water. Govier et al. and Zavareh et al. conducted investigations in vertical flow, while Scott and Zavareh et al. covered inclinations near the horizontal and near the vertical, respectively. A larger number of related studies concentrated on measuring the holdup, mainly for oil dispersed systems, focusing on finding expressions for the slip velocity that could be used in the interpretation of production logs. P. 601^

The production of large volumes of water is common in wells producing from strong aquifer reservoirs, such as most of the fields in the Oriente basin of Ecuador and neighboring Marañón and Putumayo basins in Peru and Colombia, respectively. In most cases, as the water cut increases it restricts the production of oil and creates production problems, including scale deposition, corrosion and even sand production. This increases the need for treatments thus increasing operating costs. On the lifting and processing sides, additional volumes of water require larger artificial lift units with higher energy loads, and facilities that often need to be upgraded in order to separate and handle significantly larger-than-design fluid rates. At the end of the cycle, formation waters need to be treated, cleaned and disposed off adequately in water disposal wells.The water problem is costly. If it is not addressed in a proper and timely manner the only option left to the operator is shutting-down producers, with a heavy impact on economics, particularly given the current oil price environment. Twenty years of experience with formation water issues in the Oriente and Marañón basins indicate that only a small percentage of water shut-off treatments have been successful. Lack of success is generally related to failure in performing analysis to understand the exact source of the unwanted water. A classification of the 10 main water problem types in producer wells is included in this paper.The integrated approach to formation water management looks at the problem comprehensively, starting with an understanding of the water flow mechanisms in the reservoir and the identification of the water breakthrough mechanism at the producer well, followed by the detection of production bottlenecks in the wellbore and the surface facilities, and finishing with analysis of water disposal or reinjection to complete the cycle. Once the problems and constraints in each part of the water cycle are understood they must be considered together to determine the most critical bottlenecks in the production system. The accurate identification of the water problems is absolutely essential in the selection of effective water management solutions for the facilities, injectors and/or producers. Proper understanding of producer problems can lead to effective water shut-off, improved lift and increased production. The timely resolution of flow and energy bottlenecks at production facilities can allow higher flow rates to be managed while longer-term solutions are put in place. Accurate understanding of the water mechanisms in injectors, combined with close monitoring at the field level can help increase injectivity (and injection profile in waterflooding operations) and significantly reduce disposal costs.The integrated approach to water management was implemented in the Villano field, operated by AGIP Oil Ecuador in a rainforest environment in Block 10, Ecuador. Villano is producing 107,000 BWPD. The facilities are operating at design limits, with no extra capac...

Summary The traditional means of artificial lift production for vertical and deviated wells in the Orinoco oil belt in eastern Venezuela used to be rod pumping and top-drive progressive cavity pumps (PCPs), particularly for wells with production rates ranging from 200 to 600 barrels of oil per day (BOPD) of extra-heavy oil (8°API gravity and viscosities of 2,000 cp at a reservoir temperature of 133°F). After 1995, with the implementation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones, electrical submersible pumps (ESPs) became an alternative to handle higher production volumes (Ramos and Rojas 2001). More recently, top-drive PCPs have also been installed to produce extra-heavy oil at high rates. Hybrid artificial lift technologies, such as bottom-drive progressive cavity pumping, which combine features of the ESP and the PCP systems, have recently been successfully evaluated in the Orinoco belt to exploit extra-heavy oil reserves economically. A typical completion assembly includes a multisensor gauge to obtain downhole pressures, temperatures, and vibration amplitudes of the system, and to detect power-cable current leaks; a four-pole motor; a protector; a 4:1-ratio gear box; and the PCP. The functional design of the bottom-drive PCP facilitates the handling of viscous and abrasive fluids, increases the flow rate, and diminishes the operational costs. Further advantages of this application include the complete elimination of tubing wear by eliminating the need for a rod string, greater torque capacity, lower surface maintenance cost, lower load and horsepower requirements, and lower frictional losses. The application of bottom-drive PCPs in the Cerro Negro area has resulted in production rates of up to 1,000 BOPD of extra-heavy oil with 50% lower horsepower requirements in comparison to those of conventional top-drive PCP systems. Introduction The Orinoco oil belt is located on the northern side of the lower Orinoco River in eastern Venezuela. It covers an area of approximately 20,850 square miles and contains the country's largest deposits of extra-heavy oil, estimated to be 1.2´1012 barrels of oil in place (OIP). The Cerro Negro area is located in the eastern part of the Orinoco belt; it covers 70 square miles, with an estimated OIP of 18.5´109 barrels of extra-heavy oil (Fig. 1). The extra-heavy oil that is currently being produced in the area has gravity values ranging between 6 and 10°API, with an average value of 8.5°API, and viscosities of 2,000 to 5,000 cp at a reservoir temperature of 130°F. To exploit these extensive extra-heavy oil reserves economically, new drilling and production technology implementations have been significant over the last 10 years, particularly the use of horizontal and multilateral wells and the development of artificial lift systems, resulting in new production targets of 2,000 BOPD per well compared to the former 200 BOPD per well. Wells with productivity potentials greater than 1,000 BOPD are typically completed with either ESPs or conventional PCPs. To achieve the advantages of both ESP and PCP production methods and to reduce the lifting cost, a bottom-drive PCP system was evaluated for the production of extra-heavy oils. A discussion of the applicability of this artificial lift method and a comparison with the top-drive PCP system are presented in this paper.