In the transient region, the reservoir is infinite-acting, and the flowing bottomhole pressure is a linear function of log At. The flowing bottomhole pressure is shown as a function of time on both linear and semilog plots. Flow regimes that occur at different flow times are shown in Figure 5-132 for a well flowing at a constant rate. More advanced concepts can be found in the foregoing references or in the extensive literature on this subject that has appeared in recent years. From information in these references several definitions will be given, and the basic concepts of well test analysis will be summarized. Several excellent references on well test analyses are available, and a good discussion of difficulties in interpretation of data is available in a recent text. Multiwell testing for characterizing anisotropic reservoirs has been popularized by the increased use of sophisticated simulation software. Variable rate tests are useful when wellbore storage is a problem. Drawdown and injection tests are run less frequently due to problems with maintaining a constant rate. Buildup and falloff tests are most popular because the zero flow rate is readily held constant. Single-well tests such as buildup, falloff, drawdown, injection, and variablerate describe the isotropic reservoir adjacent to the test well while multiple well tests such as long term interference or short term pulse describe the characteristics between wells. There are a number of methods to generate the transient data available to the reservoir engineer. The transient period should not exceed 10% of the previous flow or shut-in period. Transient pressure data are generated by changing the producing rate and observing the change in pressure with time. Pressure transient analysis is a powerful tool for determining the reservoir characteristics required to forecast production rates. Society of Petroleum Engineers.Production rates depend on the effectiveness of the well completion (skin effect), the reservoir permeability, the reservoir pressure, and the drainage area. A New Productivity Index Formula for ESP-Lifted Wells. Productivity Index Prediction for Oil Horizontal Wells Using different Artificial Intelligence Techniques. WorldCat Noteworthy papers in OnePetroĪlarifi, S., AlNuaim, S., & Abdulraheem, A. This same concept can be applied to injection wells to calculate an injectivity index (II), using the same equations.ġ. This approach is less common, as the production and pressure data are more readily available, and in most cases can be more accurately measured.
Oil well drawdown skin#
K = permeability, md h = net thickness, ft u = fluid viscosity, cp B = formation volume factor, rb/STB re = external boundary radius, ft rw = wellbore radius, ft S = Skin The productivity index can also be expanded to a semi-steady state Darcy law type formulation where: The difference (Pe - Pw) is called the pressure drawdown.Įxample 2: Q = 500 STB/D Pe= 3000 psi Pwf = 250 psi J = Productivity Index, STB/day/psi Q = Surface flowrate at standard conditions, STB/D Pe = External boundary radius pressure, psi Pwf = Well sand-face mid-perf pressure, psiĪ well is producing 1000 STB/D of liquid with a pressure drop of 500 psi would have a J=2 STB/D/psi.Ī subsurface pressure gauge is used to determine the static pressure Pe after a sufficient shut-in period and also the flowing bottom-hole pressure, Pw, after the well has flowed at a stabilized rate for a sufficient period of time. The units typically are in field units, STB/D/psi as shown below: The productivity index is the ratio of the total liquid surface flowrate to the pressure drawdown at the midpoint of the producing interval.
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