Gas Well Deliverability Testing What is deliverability testing? The "deliverability" of a gas well can be defined as the well's capacity to produce against the restrictions of the well bore and the system into which the well must flow. These restrictions are barriers which must be overcome by the energy in the reservoir. Reducing the size of the well bore or increasing the pressure of the system into which the well must produce, increases the resistance to flow and therefore reduces the "deliverability" of the well. The deliverability test allows prediction of flow rates for different line and reservoir pressures. Deliverability testing goes under several names such as "back-pressure testing", "4-point testing", "open flow potential testing", and "AOF testing". The terms "open flow potential" and "absolute open flow" refer to the theoretical maximum flow rate from the reservoir if the sand face pressure were reduced to atmospheric. A "deliverability test" usually requires the well to be produced at several rates. The flowing pressure at the sand face for each rate and the sand face pressure after build-up are then determined. The pressure/flow data are used to determine AOF or deliverability. deliverability tests are used by regulatory agencies to allocate production quotas and by pipeline operators to contract for gas purchases. Halliburton deliverability tests Deliverability testing requires accurate measurement of well-head pressures and flow rates under rapidly changing conditions. The SPIDR gauge is ideally suited for this activity. It's high accuracy internal pressure transducer records instantaneous pressures, even though they may be changing rapidly. This is impossible with a dead-weight tester. The SPIDR gauge is also more accurate than a field dead-weight tester. The two-pen circular chart recorder normally used for flow measurement is difficult to read and relatively inaccurate. The SPIDR gauge interfaces with an electronic d/p cell to measure differential pressure across an orifice plate. The meter-run may be located several hundred feet from the well-head where the SPIDR gauge is located. A diagram of the SPIDR gauge d/p cell installation can be seen here. It is not necessary to replace the two-pen recorder when using the electronic d/p cell. The SPIDR gauge system permits continuous digital display of flow rates and well head pressures during the test. A key to accurate determination of "deliverability" is the ability to reliably convert well-head pressures to down-hole pressures for both static and flowing conditions. This is especially important for wells with significant fluid production. The SPIDR gauge software for converting well head pressure to bottom hole pressure has been proven over thousands of tests. The conversion to bottom-hole pressure is accurate for wells producing up to 150 barrels of fluid per million cubic feet of gas. The software can also generate the AOF and deliverability plots shown in this Technical Alert. Use of the SPIDR gauge system reduces the work load associated with deliverability testing thereby reducing the cost. Theory The flow of gas to the well bore can be described by the equation: where BHPsi is the shut-in bottom-hole pressure and BHPwf is the flowing bottom hole pressure at flow rate Q. The coefficient "C" is a constant that includes the drainage radius, radius of the well bore, reservoir permeability, formation thickness, gas compressibility and viscosity, and reservoir temperature. The exponent "n" accounts for non-ideal gas behavior and nonsteady state flow. Under ideal conditions, "n" equals 1.
The gas flow equation can be rewritten by taking the log of the equation: From this equation it is evident that a plot of the log of the flow rate against the log of the bottom hole pressure differences squared, will yield a straight line of reciprocal slope "n" as shown at right. The intersection of the straight line with the square of the shut-in bottom-hole pressure yields the theoretical flow from the reservoir (AOF) if the sand face pressure were reduced to zero. For a given well, the terms "C" and "n" may often be considered as constants. However, for wells with low permeability, "C" will decrease with increasing flow time. It will then be necessary to use the Isochronal or Modified Isochronal deliverability tests described below. The value of "n" will normally fall between.5 and 1.0. Values outside this range are not considered valid. A value of "n" equal to 1 indicates steady state viscous flow and a value of.5 indicates steady state turbulent flow. Once the value "n" has been determined for a given well, subsequent tests may use the "one-point" method. This technique assumes that the slope of the deliverability curve does not change with time. The "one-point" test requires the well-head pressures at one stabilized flow rate and after a stabilized shut-in. The well-head pressures are converted to bottom-hole pressures and the AOF is calculated from the equation:
To find the "deliverability" of the well against any line pressure, the equation is modified by substituting surface pressures for bottom-hole pressures: The "deliverability" is calculated after substituting the flow rate (Qwf) of the well with its corresponding well-head pressure (WHPwf), and a recent shut-in well-head pressure (WHPsi). The deliverability can then be calculated for any line pressure (Pline). Deliverability Test Procedures The "deliverability" test requires that the well be produced at several different rates, usually four. As a general rule, the rates should be high enough to create drawdowns of 5, 10, 15, and 20%, of the shut-in well-head pressure. The rates must also be sufficiently high to continuously unload produced fluids. The flow rate and the flowing well-head temperature should be accurately recorded at the end of each flow period. The flow periods must be of sufficient duration to achieve stabilized flow which is defined as pressure changes of less than 0.1% of the shut-in well-head pressure over 15 minutes. The figure at right is a diagram of the conventional deliverability test. The flowing well-head pressures (Pwfi) at the end of each flow rate(q1-q4) are converted to bottom-hole pressures and squared. The squared pressures are then subtracted from the square of the shut-in bottom-hole pressure (Psi). These differences are plotted against the flow rates on a log-log scale as shown in the previous graph.
When it is difficult or impractical to achieve stabilized flow because of low reservoir permeability, the Isochronal or Modified Isochronal multipoint test isused. In the Isochronal test, care is taken that the flow periods are of equal duration. At the end of each flow period, the well head pressure is allowed to return to the initial shut-in pressure (Psi). The last flow in the sequence is of extended duration in order to achieve stabilized flow. A diagram of the isochronal test is shown at right. Four sets of flow rate/whp values should be taken during each flow period. For the sake of clarity, the four data sets are only shown for flow period Q2. After converting the well-head pressures to BHP values, the plot shown below and to the right is constructed.
The slope of each line should be similar. The flowing well-head pressure at the end of the extended flow period is converted to bottom-hole pressure and used to locate the Stable Flow point on the previous plot. A line of the same slope is drawn through the Stable Flow point to obtain the AOF. To further shorten the test period for low permeability wells, the Modified Isochronal test is used. This test differs from the Isochronal test in that the flow periods and shut-in periods are of equal duration. The well is not allowed to build back to its pretest shut in pressure. The next plot shows the Modified Isochronal deliverability test. When plotting the data, care should be taken that the build-up pressure before each flow rate is used when calculating (Psi2 - Pwf2) for each flow. The plot is constructed and the AOF determined in the same manner as described for the Isochronal deliverability plot. 2012 Halliburton. All Rights Reserved