Changes

Production tests are run to obtain an indication of well productivity. Some production tests are performed in open hole (such as drill stem tests) and can be used in making completion decisions. Others (such as single-point, multipoint, and swab tests) are performed after the well is completed and generally involve routine measurements of oil, gas, and/or water production under normal producing conditions. The test results can be used to determine reservoir properties, to assess the degree of damage or [[stimulation]], to identify production and reservoir problems, or to satisfy the reporting requirements of regulatory bodies. Production tests can also be performed when more conventional well tests (such as pressure drawdown and buildup tests) are impractical due to time constraints, well conditions, or extremely low well productivity.

Production tests are run to obtain an indication of well productivity. Some production tests are performed in open hole (such as drill stem tests) and can be used in making completion decisions. Others (such as single-point, multipoint, and swab tests) are performed after the well is completed and generally involve routine measurements of oil, gas, and/or water production under normal producing conditions. The test results can be used to determine reservoir properties, to assess the degree of damage or [[stimulation]], to identify production and reservoir problems, or to satisfy the reporting requirements of regulatory bodies. Production tests can also be performed when more conventional well tests (such as pressure drawdown and buildup tests) are impractical due to time constraints, well conditions, or extremely low well productivity.

==Prill stem tests==

==Drill stem tests==

 

Drill stem tests (DSTs) are used to obtain (1) samples of the reservoir fluid, (2) measurements of static bottomhole pressure, (3) an indication of well productivity, and (4) short-term flow and pressure buildup tests from which [[permeability]] and the extent of damage or stimulation can be estimated<ref name=pt09r14>Lee, W. J., 1982, Well Testing: Dallas, TX, Society of Petroleum Engineers of AIME, 159 p.</ref>. A DST is run in the open hole after drilling, and is often used in deciding whether to complete a particular zone. The total test duration is frequently a function of hole condition, and the tool assembly must be retrieved from the open hole after the test is completed (see “[[Drill stem testing]]”).

Drill stem tests (DSTs) are used to obtain (1) samples of the reservoir fluid, (2) measurements of static bottomhole pressure, (3) an indication of well productivity, and (4) short-term flow and pressure buildup tests from which [[permeability]] and the extent of damage or stimulation can be estimated<ref name=pt09r14>Lee, W. J., 1982, Well Testing: Dallas, TX, Society of Petroleum Engineers of AIME, 159 p.</ref>. A DST is run in the open hole after drilling, and is often used in deciding whether to complete a particular zone. The total test duration is frequently a function of hole condition, and the tool assembly must be retrieved from the open hole after the test is completed (see “[[Drill stem testing]]”).

To run a drill stem test, a special DST tool is attached to the drill pipe and run in the hole opposite the zone to be tested. A DST tool typically includes two or more clock-driven, bourdon-tube recording pressure gauges, a set of flow valves, and one or two packers. The tool isolates the formation from the mud column in the annulus. When the tool is opened, reservoir fluid can flow into the drill pipe (and possibly to the surface); pressure is recorded continuously during the test.

To run a drill stem test, a special DST tool is attached to the drill pipe and run in the hole opposite the zone to be tested. A DST tool typically includes two or more clock-driven, bourdon-tube recording pressure gauges, a set of flow valves, and one or two packers. The tool isolates the formation from the mud column in the annulus. When the tool is opened, reservoir fluid can flow into the drill pipe (and possibly to the surface); pressure is recorded continuously during the test.

Most DSTs (Figure 1) consist of two flow periods and two shut-in periods. The pressure gauges record the initial hydrostatic mud pressure (''p''_ihm) while going into the hole. The initial flow period (''p''_ifl to ''p''_ffl'')'' is a short production period, usually only 5 to 10 min. Pressure rises during the flow period as fluid collects in the drill stem above the pressure gauges. The objective is to release the hydrostatic mud pressure and draw down the formation pressure only slightly. The first shut-in period (''p''_ffl to ''p''_isi) should be long enough to allow the reservoir pressure to return to its initial value. A shut-in time of 1 hour is usually preferred.

Most DSTs ([[:file:production-testing_fig1.png|Figure 1]]) consist of two flow periods and two shut-in periods. The pressure gauges record the initial hydrostatic mud pressure (''p''_ihm) while going into the hole. The initial flow period (''p''_ifl to ''p''_ffl'')'' is a short production period, usually only 5 to 10 min. Pressure rises during the flow period as fluid collects in the drill stem above the pressure gauges. The objective is to release the hydrostatic mud pressure and draw down the formation pressure only slightly. The first shut-in period (''p''_ffl to ''p''_isi) should be long enough to allow the reservoir pressure to return to its initial value. A shut-in time of 1 hour is usually preferred.

 

In the second flow period (''p''_if2 to ''p''_ff2), the objective is to capture a large sample of formation fluid and to reduce the pressure as far into the reservoir as possible. This flow period should be at least 1 hour, and if reservoir fluid is produced to the surface, flow rates should be measured. The second shut-in period (''p''_ff2 to ''p''_fsi) is longer than the first and is used to estimate formation properties in a manner similar to that for analyzing conventional buildup tests. The duration of the final shut-in period depends on well behavior during the flow test; it may range from one-half to twice the flow time. Comparison of the final or extrapolated reservoir pressure from this second shut-in period to that from the initial shut-in period may suggest depletion has occurred during the DST. If so, the zone being tested is a limited, noncommercial reservoir. Following the second shut-in period, the final hydrostatic mud pressure is measured (''p''_fhm) and the DST tool is pulled from the hole.

In the second flow period (''p''_if2 to ''p''_ff2), the objective is to capture a large sample of formation fluid and to reduce the pressure as far into the reservoir as possible. This flow period should be at least 1 hour, and if reservoir fluid is produced to the surface, flow rates should be measured. The second shut-in period (''p''_ff2 to ''p''_fsi) is longer than the first and is used to estimate formation properties in a manner similar to that for analyzing conventional buildup tests. The duration of the final shut-in period depends on well behavior during the flow test; it may range from one-half to twice the flow time. Comparison of the final or extrapolated reservoir pressure from this second shut-in period to that from the initial shut-in period may suggest depletion has occurred during the DST. If so, the zone being tested is a limited, noncommercial reservoir. Following the second shut-in period, the final hydrostatic mud pressure is measured (''p''_fhm) and the DST tool is pulled from the hole.