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Understanding the principles of fluid flow through the production system is important in estimating the performance of individual wells and optimizing well and reservoir productivity. In the most general sense, the production system is the system that transports reservoir fluids from the subsurface reservoir to the surface, processes and treats the fluids, and prepares the fluids for storage and transfer to a purchaser.Figure 1.1 depicts the production system for a single well system. The basic elements of the production system include the reservoir; wellbore; tubular goods and associated equipment; surface wellhead, flowlines, and processing equipment; and artificial lift equipment.
- 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)
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- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Figure 1.1--Production System and associated pressure losses.[1] 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 radial diffusivity equation for a slightly compressible liquid with a constant viscosity (an undersaturated oil or water) is ....................(1.1) The solution for a real gas is often presented in two forms: traditional pressure-squared form and general pseudopressure form. The pressure-squared form is ....................(1.2) and the pseudopressure form is ....................(1.3) The pseudopressure relationship is suitable for all pressure ranges, but the pressure-squared relationship has a limited range of applicability because of the compressible nature of the fluid.
Summary Petroleum engineers are routinely required to predict the pressure/production behavior of individual oil wells. These well-performance estimates assist the engineer in evaluating various operating conditions, determining the optimum production scheme, and designing production equipment and artificial-lift systems. In this paper, commonly used empirical, inflow performance relationships for estimating the pressure/production behavior during two-phase flow are investigated. Relationships studied include those proposed by Vogel; Fetkovich; Jones, Blount, and Glaze; Klins and Majcher; and Sukarno and Wisnogroho. Each method is described briefly, and the methods used to develop the relationship are discussed. On the basis of actual vertical-well data, the relationships are used to predict performance for 26 cases. The predicted performance is then compared to the actual measured rate and pressure data. The variation between the predicted and measured data is analyzed, and from this analysis, an assessment is made on the use of inflow performance relationships and of the quality of the performance estimates. Introduction When considering the performance of oil wells, it is often assumed that production rates are proportional to pressure drawdown. This straight-line relationship can be derived from Darcy's law for steady-state flow of a single, incompressible fluid and is called the productivity index (PI). Evinger and Muskat were some of the earliest investigators to look at oilwell performance. They pointed out that a straight-line relationship should not be expected when two fluid phases are flowing in the reservoir. They presented evidence, based on multiphase flow equations, that a curved relationship existed between flow rate and pressure. This work led to the development of several empirical inflow performance relationships (IPRs) to predict the pressure/production behavior of oil wells producing under two-phase flow conditions. These estimates assist the engineer in evaluating various operating conditions, determining the optimum production scheme, and designing production equipment and artificial-lift systems. This paper reviews and compares five IPRs proposed in the literature for predicting individual-vertical-well performance in solution-gas-drive reservoirs. The IPRs studied are Vogel; Fetkovich; Jones, Blount, and Glaze; Klins and Majcher; and Sukarno and Wisnogroho. Each IPR was developed for various conditions but essentially represents vertical wells producing from a single solution-gas-drive reservoir under boundary-dominated flow conditions. A homogeneous reservoir is assumed in all the methods except for Fetkovich's; however, Wiggins et al. have shown that this assumption does not restrict the applicability of an IPR method. Using data from 26 field cases, the five IPR methods are used to predict the pressure/production behavior for the individual cases, and the predictions are compared to the actual well performance and to the other methods' predictions to develop an understanding of their reliability. Deliverability Methods Vogel developed one of the earliest IPRs based on simulation data for 21 reservoir data sets representing a wide range of reservoir rock and fluid properties. Vogel noticed that the shapes of the pressure/production curve for these cases were very similar. He made the curves dimensionless by dividing the pressure at each point by the reservoir pressure and by dividing the flow rate by the maximum flow rate to obtain the dimensionless inflow performance curve. He observed that all the points fell within a narrow range and developed the following relationship to describe the dimensionless behavior.
- Asia > Indonesia > Sumatra > South Sumatra > Tanjung Miring Timur Field > Talang Akar Formation (0.94)
- Asia > Indonesia > East Kalimantan > Makassar Strait > Kutei Basin > Sangatta Field (0.94)
- North America > United States > Oklahoma > Anadarko Basin > Seminole Field (0.91)
Abstract Petroleum engineers are routinely required to predict the pressure-production behavior of individual oil wells. These estimates of well performance assist the engineer in evaluating various operating conditions, determining the optimum production scheme, and designing production equipment and artificial lift systems. In this paper, commonly used empirical inflow performance relationships for estimating the pressure-production behavior during two-phase flow are investigated. Relationships studied include those proposed by Vogel, Fetkovich, Jones, Blount and Glaze, Klins and Majcher, and Sukarno. Each method will be briefly described and methods used to develop the relationship will be discussed. Based on actual vertical well data, the relationships are used to predict performance for twenty-six cases. The predicted performance is then compared to actual measured rate and pressure data. The variation between the predicted and measured data are analyzed. From this analysis, recommendations are made on the use of inflow performance relationships to predict performance, collection of data, and the quality of performance estimates. Introduction When considering the performance of oil wells, it is often assumed that production rates are proportional to pressure drawdown. This straight-line relationship can be derived from Darcy's law for steady-state flow of a single, incompressible fluid and is called the productivity index (PI). Evinger and Muskat 1 were some of the earliest investigators to look at oilwell performance. They pointed out that a straight-line relationship should not be expected when two phases are flowing in the reservoir. They presented evidence based on the multiphase flow equations that a curved relationship existed between flow rate and pressure. This work led to the development of several empirical inflow performance relationships (IPRs) to predict the pressure-production behavior of oil wells producing under two-phase flow conditions. These estimates assist the engineer in evaluating various operating conditions, determining the optimum production scheme, and designing production equipment and artificial lift systems. This paper reviews and compares five IPRs proposed in the literature for predicting individual well performance in solution-gas drive reservoirs. The IPRs studied includes those of Vogel,2 Fetkovich,3 Jones, Blount and Glaze,4 Klins and Majcher,5 and Sukarno.6 Using data from 26 field cases, each method is used to predict the pressure-production behavior for the individual cases. The predictions are compared to actual well performance and to predictions of the other methods to develop an understanding of their reliability. Deliverability Methods One of the earliest IPRs was developed by Vogel 2 based upon simulation data for twenty-one reservoir data sets representing a wide range of reservoir rock and fluid properties. Vogel noticed the shape of the pressure-production curves for these cases were very similar. He made the curves dimensionless by dividing the pressure at each point by the reservoir pressure and the flow rate by the maximum flow rate to obtain the dimensionless inflow performance curve. He observed that all the points fell within a narrow range and developed a relationship to describe the dimensionless behavior. Vogel's IPR is
- North America > United States > Oklahoma > Lucien Field (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Keokuk Field (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Burbank Field (0.99)
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Early estimates of gas well performance were conducted by opening the well to the atmosphere and then measuring the flow rate. Such "open flow" practices were wasteful of gas, sometimes dangerous to personnel and equipment, and possibly damaging to the reservoir. They also provided limited information to estimate productive capacity under varying flow conditions. The idea, however, did leave the industry with the concept of absolute open flow (AOF). AOF is a common indicator of well productivity and refers to the maximum rate at which a well could flow against a theoretical atmospheric backpressure at the reservoir. The productivity of a gas well is determined with deliverability testing.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
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- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)