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Summary Modern completion techniques have greatly increased the production-rate capability of wells. Many wells have the potential to produce more liquid and gas, but the use of tubing anchors in certain wellbore locations chokes the gas flow up the casing and results in increased backpressure against the formation, which restricts production from the well. A gaseous liquid column can form above the tubing anchor and cause high pressure in the gas below the tubing anchor that restricts the liquid and gas flow from the reservoir. Often, low pump fillage and low production rates are blamed on a poor gas separator, when actually the separator is operating efficiently and is separating the liquid from the gas. In the condition described, all of the liquid in the wellbore below the tubing anchor falls to the pump and is being removed by the pump. The problem is that high pressure in the gas column below the tubing anchor is restricting production from the well. Additional production is available if the high pressure that is restricting production from the formation is removed. The accumulation of a gaseous liquid column above the tubing anchor when constant low pump fillage is observed indicates that liquid exists above the tubing anchor whereas only free gas exists from the tubing anchor down to the pump. Limited liquid production falls down the casing wall, while the casing annulus is almost completely filled with gas if the pump is set below the formation (McCoy et al. 2013). Field testing with automated fluid-level-measurement equipment to perform liquid-depression tests verifies that a gaseous liquid column exists (Rowlan et al. 2008) above the tubing anchor and a gas column exists below the tubing anchor in wells with high fluid levels, with low pump fillage, and with the tubing anchor located above the pump. These field data were acquired on several wells and are shown to verify the preceding analysis of the well's performance. This fluid-distribution condition is not generally known. Locating the tubing anchor below the pump prevents this condition and will improve production in these wells.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
Summary This article deals with phenomena associated with gravity-induced separation along the completed interval of inclined wells. The model developed computes liquid accumulation and production performance. From the results it is shown that both the overall inflow performance and the gas-liquid ratio observed at the surface are affected by the downhole separation. It is shown that downhole separation may be constrained by either backseepage to the reservoir or countercurrent flooding along the wellbore. The liquid backflow rate limit due to flooding has been derived explicitly, providing a design parameter for downhole separation devices. Introduction With multiphase flow along the completed wellbore, there will be some tendency of accumulation of heavier and more viscous fluids. If the heavier fluid accumulates in an upwardly inclined wellbore, its weight will increase the bottom well pressure. This reduces the inflow. If the bottom well pressure exceeds the surrounding reservoir pressure, some of the accumulated fluid may seep back to the reservoir, thus reducing the liquid fraction produced. It is commonly recognized that a pressure drop along a completed wellbore may affect local inflow and thereby also overall inflow performance. Work on this topic has mostly considered a pressure drop caused by single phase flow. However, most wells produce more than one fluid, which usually implies a larger pressure drop than is predicted by single phase flow models. Experimental work on two-phase flow along horizontal pipes with local inflow was undertaken by Ihara and co-workers. They found that the pressure drop along horizontal, completed wellbores can be predicted by standard two-phase models, although an improved model was also proposed. Gonza´lez-Guevara and co-worker presented an inflow simulation model. They found that inflow along the wellbore is strongly affected by the incline of the wellbore. These works have simplified the modeling by neglecting the backseepage of liquids from the wellbore to the reservoir and the corresponding backflow of liquids along the wellbore. However, when backseepage occurs, it can have a profound effect on the downhole separation and inflow performance, as will be shown. The current work includes the backseepage and backflow of liquids along the wellbore with special emphasis on the associated phenomenon of countercurrent flooding, which may limit the downhole separation. The model may be used to predict well performance and to develop a completion design that minimizes the detrimental effects of liquid accumulation. The mechanisms quantified may also be utilized to promote downhole separation of unwanted liquids. Wellbore Performance Prediction Fig. 1 illustrates the inflow, liquid accumulation, and backseepage along an inclined wellbore. For a constant production rate over a period of time, the downhole conditions should approach steady state. This implies a steady-state distribution of inflow and liquid holdup along the completed interval. In an upwardly inclined wellbore, the accumulated liquid will provide backpressure, which increases towards the bottom of the well. In Fig. 1, the location where the wellbore pressure reaches the reservoir pressure is denoted by xL This will be called the liquid level. Inflow of gas and liquid occurs above this liquid level. Below the liquid level, the wellbore pressure exceeds the reservoir pressure. Thus, there will be no inflow, and liquid that flows back along the wellbore will accumulate there. Backseepage may occur below the liquid level and is governed by pressure and injectivity. For natural backseepage, driven by gravity, the liquid level will vary with the production rate. For backseepage driven by downhole injection devices, the location and operation of such devices will determine the location of the liquid level.
- Europe (0.93)
- North America > United States (0.46)
Introduction As easily accessible petroleum basins have matured, exploration and development have expanded farther offshore and to remote areas. New development challenges are in deep water and in marginal fields with smaller reserves. The facilities required in these new developments are similar in function to conventional processing facilities, but the packaging requirements can be quite different. Process facilities can now be placed literally anywhere between the reservoir and the product pipeline, including subsea and downhole. Obviously, minimizing surface equipment size and weight reduces costs for deepwater platforms. In addition, the trend of tying smaller fields to a larger processing facility, in a hub-and-spoke arrangement, has led to novel production approaches. Oil/water or liquid/gas can be partially separated closer to the reservoir to reduce the size of surface equipment, eliminate or reduce the size of flowlines, or to facilitate pumping.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.93)
- North America > United States > Oklahoma (0.93)
- North America > United States > Louisiana (0.93)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Abstract Gravity and viscosity differences will cause gas-liquid separation already along the completed interval. For wells completed over longer intervals, the heavier liquid will accumulate and may build up sufficient static pressure to seep back to lower layers of the reservoir. The model developed computes production performance with two-phase inflow, two-phase flow along the completed interval and possible back-seepage of accumulated liquid. From the results follow that both the apparent inflow performance and the gas-liquid ratio observed at surface are affected. It is shown that downhole separation may be constrained by either back-seepage to the reservoir, or counter-current flooding along the wellbore. The liquid backflow rate limit due to flooding has been derived explicitly, providing a design parameter for downhole separation devices. P. 497
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Well Operations and Optimization > Downhole fluids separation, management and disposal (0.84)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (0.69)
Technology Focus Shallow-water offshore production began before 1900 and continues to be important today. Technology to maximize economic production from shallow-water fields can be adapted from onshore or deepwater technologies. Improvements in monitoring-system capabilities (and costs) are direct contributors to optimizing well and facilities operations. Several case studies illustrate the benefits of applying existing technology to increase production in mature operations. The first case study is of a gas/condensate field. Typical liquid-handling strategies were first applied to mitigate production decline, including converting the test separator to a low-pressure separator. Regular well testing is required for allocation and reservoir management. Previously, low-pressure wells were shut in during the well tests, resulting in production losses. Clamp-on sonar meters allow well testing every 2 months without shutting in production. Data from the sonar metering and other production-surveillance techniques have been used to optimize well cycling. The second case study describes implementation of through-tubing technology for sand control at a normally unmanned platform. The platform is located in shallow water with onerous sea states. Significant sand production began from an unconsolidated oil zone when the original gas well was converted to commingled production. This paper describes the selection and installation of through-tubing sand control and subsequent selection and installation of through-tubing gas lift. Critical success factors for well rejuvenation at this marginal field include managing marine issues and crane limits. The last case study discusses installation of a downhole electric heater in an offshore heavy-oil well. Heating heavy-oil reservoirs is uncommon offshore. This successful heater application uses a three-phase system with a cold section to protect the electrical submersible pump (ESP) used to lift the oil. Distributed-temperature sensing monitors temperature profiles in the well. Cable connections—power for the heater and the ESP—are critical for successful operation. JPT Recommended additional reading at OnePetro: www.onepetro.org. IPTC 16858 Downhole Electrical Heating for Heavy-Oil Enhanced Recovery: A Successful Application in Offshore Congo by F. Bottazzi, Eni, et al. OTC 23948 Full-Scale Testing of Distributed-Temperature Sensing in Flexible Risers and Flowlines by Nick Weppenaar, NOV Flexibles, et al. OTC 23968 Large-Diameter-Riser Laboratory Gas Lift Tests by G. Zabaras, Shell, et al.
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (4 more...)