Changes

==Drill stem tests==

==Drill stem tests==

[[file:production-testing_fig1.png|left|thumb|{{figure number|1}}Typical drill stem test pressure chart. (From <ref name=pt09r7>Earlougher, R. C., Jr., 1977, Advances in Well Test Analysis: Dallas, TX, American Institute of Mining, Metallurgical and Petroleum Engineers, Society of Petroleum Engineer's Monograph 5, 264 p.</ref>.)]]

[[file:production-testing_fig1.png|thumb|300px|{{figure number|1}}Typical drill stem test pressure chart. From Earlougher.<ref name=pt09r7>Earlougher, R. C., Jr., 1977, Advances in Well Test Analysis: Dallas, TX, American Institute of Mining, Metallurgical and Petroleum Engineers, Society of Petroleum Engineer's Monograph 5, 264 p.</ref>]]

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.

==Single-point tests==

==Single-point tests==

Single-point tests are usually simple productivity tests that typically involve a measurement (or estimate) of initial or average reservoir pressure and a measurement of flow rate and flowing bottomhole pressure (which can be estimated from flowing surface pressure) at stabilized producing conditions<ref name=pt09r1>Allen, T. O., Roberts, A. P., 1978, Production Operations, Volume 1 : Tulsa, OK, Oil and Gas Consultants International, 225 p.</ref>. From these data, the productivity index, PI, can be calculated as follows:

Single-point tests are usually simple productivity tests that typically involve a measurement (or estimate) of initial or average reservoir pressure and a measurement of flow rate and flowing bottomhole pressure (which can be estimated from flowing surface pressure) at stabilized producing conditions.<ref name=pt09r1>Allen, T. O., and A. P. Roberts, 1978, Production Operations, Volume 1: Tulsa, OK, Oil and Gas Consultants International, 225 p.</ref> From these data, the productivity index, PI, can be calculated as follows:

:<math>\mbox{PI} = \frac{q}{\bar{p} - p_{\rm wf}} (\mbox{for oil}) = \frac{q\mu B}{\bar{p}^{2} - p_{\rm wf}^{2}} (\mbox{for gas})</math>

:<math>\mbox{PI} = \frac{q}{\bar{p} - p_{\rm wf}} \mbox{ (for oil)} = \frac{q\mu B}{\bar{p}^{2} - p_{\rm wf}^{2}} \mbox{ (for gas)}</math>

where

where

* <math>\bar{p}</math> = initial or current average reservoir pressure (psia)

* <math>\bar{p}</math> = initial or current average reservoir pressure (psia)

* ''p''_wf = flowing bottomhole pressure (psia)

* ''p''_wf = flowing bottomhole pressure (psia)

* ''μ'' = viscosity (cp)

* ''μ'' = [[viscosity]] (cp)

* ''B'' = formation volume factor (rcf/MSCF)

* ''B'' = formation volume factor (rcf/MSCF)

The productivity index can be a useful indicator of well productivity and wellbore condition during the life of a well. PI will generally decrease over time due to declining reservoir pressure, changes in producing conditions, and/or [[production problems]].

The productivity index can be a useful indicator of well productivity and wellbore condition during the life of a well. PI will generally decrease over time due to declining reservoir pressure, changes in producing conditions, and/or [[production problems]].

Single-point tests can also be used to estimate formation permeability<ref name=pt09r15>Lee, W. J., Kuo, T. B., Holditch, S. A., McVay, D. A., 1984, Estimating formation permeability from single-point flow data: Proceedings of the 1984 SPE/DOE/GRI Unconventional Gas Recovery Symposium, Pittsburgh, PA, p. 175–186.</ref> with an iterative solution of the transient radius of drainage equation (Equation 2) and the pseudosteady-state flow equation (Equation 3), as follows:

Single-point tests can also be used to estimate formation permeability<ref name=pt09r15>Lee, W. J., T. B. Kuo, S. A. Holditch, and D. A. McVay, 1984, Estimating formation permeability from single-point flow data: Proceedings of the 1984 SPE/DOE/GRI Unconventional Gas Recovery Symposium, Pittsburgh, PA, p. 175–186.</ref> with an iterative solution of the transient radius of drainage equation (Equation 2) and the pseudosteady-state flow equation (Equation 3), as follows:

:<math>r_{\rm d} = \left(\frac{kt}{376\phi \mu c_{\rm t}}\right)^{1/2}</math>

:<math>r_{\rm d} = \left(\frac{kt}{376\phi \mu c_{\rm t}}\right)^{1/2}</math>

* ''s''′ = apparent skin factor

* ''s''′ = apparent skin factor

To solve for permeability, an arbitrary value of permeability is assumed (0.1 md is often a good first estimate), and Equation 2 is solved for ''r''_d,. Then, this value for ''r''_d is used in Equation 3 to solve for permeability. For each iteration after the first, use the permeability calculated from Equation 3 in solving for ''r''_d from Equation 2; this procedure usually converges in three to four iterations.

To solve for permeability, an arbitrary value of permeability is assumed (0.1 md is often a good first estimate), and Equation 2 is solved for ''r''_d. Then, this value for ''r''_d is used in Equation 3 to solve for permeability. For each iteration after the first, use the permeability calculated from Equation 3 in solving for ''r''_d from Equation 2; this procedure usually converges in three to four iterations.

The need to estimate an apparent skin factor, which is usually not known, is the biggest limitation of this method. Pressure buildup tests run in other wells in the same reservoir often provide a good estimate of typical skin factors. Low permeability wells are generally broken down and balled out after completion and prior to testing; in these wells, a skin factor of –1 to –2 is often a reasonable assumption. If a well has been damaged by [[drilling fluid]]s and the perforations have not been broken down, a skin factor of +2 to +5 (or more) is appropriate (see “Fundamentals of Fluid Flow”).

The need to estimate an apparent skin factor, which is usually not known, is the biggest limitation of this method. Pressure buildup tests run in other wells in the same reservoir often provide a good estimate of typical skin factors. Low permeability wells are generally broken down and balled out after completion and prior to testing; in these wells, a skin factor of –1 to –2 is often a reasonable assumption. If a well has been damaged by [[drilling fluid]]s and the perforations have not been broken down, a skin factor of +2 to +5 (or more) is appropriate (see [[Fluid flow fundamentals]]).

The single-point test method for estimating permeability is valid for constant flow rate production, constant bottomhole pressure production, or smoothly changing bottomhole pressures and flow rates. The method is recommended for estimating permeability from prefracture flow test data only; it does not work well with postfracture flow data. The method is particularly useful in low permeability reservoirs where operators do not run buildup tests routinely because of the long test times required to overcome wellbore storage effects and reach radial flow (see “[[Pressure transient testing]]”).

The single-point test method for estimating permeability is valid for constant flow rate production, constant bottomhole pressure production, or smoothly changing bottomhole pressures and flow rates. The method is recommended for estimating permeability from prefracture flow test data only; it does not work well with postfracture flow data. The method is particularly useful in low permeability reservoirs where operators do not run buildup tests routinely because of the long test times required to overcome wellbore storage effects and reach radial flow (see [[Pressure transient testing]]).

==Multi-point tests==

==Multi-point tests==

Multi-point tests are typically used to establish gas well deliverability and absolute open flow potential; these tests may also be referred to as gas well deliverability tests, backpressure tests, or flow-after-flow tests<ref name=pt09r1 />. Multi-point tests typically require the measurement of gas flow rates and surface pressures at four stabilized flow conditions; surface shut-in pressure is also measured. Generally, an increasing flow rate sequence is preferred to a decreasing rate sequence.

[[file:production-testing_fig2.png|thumb|300 px|{{figure number|2}}Multi-point test used to estimate absolute open flow potential.]]

The surface shut-in and flowing pressure measurements are converted to bottomhole conditions and a log-log plot of <math>\bar{p}^{2} - p_{\rm wf}^{2}</math> versus flow rate, ''q'', is generated (Figure 2). The four points define a straight line with a slope that is generally between 0.5 and 1.0. This straight line is extrapolated to determine gas flow rate at a point where the flowing bottomhole pressure is zero; this rate is referred to as the absolute open flow (AOF) potential of the well.

Multi-point tests are typically used to establish gas well deliverability and absolute open flow potential; these tests may also be referred to as gas well deliverability tests, backpressure tests, or flow-after-flow tests.<ref name=pt09r1 /> Multi-point tests typically require the measurement of gas flow rates and surface pressures at four stabilized flow conditions; surface shut-in pressure is also measured. Generally, an increasing flow rate sequence is preferred to a decreasing rate sequence.

[[file:production-testing_fig2.png|thumb|{{figure number|2}}Multi-point test used to estimate absolute open flow potential.]]

The surface shut-in and flowing pressure measurements are converted to bottomhole conditions and a log-log plot of <math>\bar{p}^{2} - p_{\rm wf}^{2}</math> versus flow rate, ''q'', is generated ([[:file:production-testing_fig2.png|Figure 2]]). The four points define a straight line with a slope that is generally between 0.5 and 1.0. This straight line is extrapolated to determine gas flow rate at a point where the flowing bottomhole pressure is zero; this rate is referred to as the absolute open flow (AOF) potential of the well.

Multi-point test data can also be used to estimate permeability using a variable rate flow test analysis<ref name=pt09r20>Odeh, A. S., Jones, L. G., 1965, Pressure drawdown analysis, variable-rate case, in Pressure Analysis Methods: Dallas, TX, American Institute of Mining, Metallurgical and Petroleum Engineers, Society of Petroleum Engineers Reprint Series No. 9, 256 p.</ref>. For gas wells, the data are plotted as

Multi-point test data can also be used to estimate permeability using a variable rate flow test analysis.<ref name=pt09r20>Odeh, A. S., and L. G. Jones, 1965, Pressure drawdown analysis, variable-rate case, in Pressure Analysis Methods: Dallas, TX, American Institute of Mining, Metallurgical and Petroleum Engineers, Society of Petroleum Engineers Reprint Series No. 9, 256 p.</ref> For gas wells, the data are plotted as

:<math>\frac{\bar{p}^{2} - p_{\rm wfn}^{2}}{q_{n}} \mbox{ versus } \frac{1}{q_{n}} \sum\limits_{j=0}^{n-1} \Delta q_{j} \log (t_{n} - t_{j})</math>

:<math>\frac{\bar{p}^{2} - p_{\rm wfn}^{2}}{q_{n}} \mbox{ versus } \frac{1}{q_{n}} \sum\limits_{j=0}^{n-1} \Delta q_{j} \log (t_{n} - t_{j})</math>

==Swab tests==

==Swab tests==

''Swabbing'' can be defined as pulling a full-diameter tool from the wellbore; this pulling action is similar to that of a plunger in a syringe, and it initiates fluid flow into the wellbore<ref name=pt09r26>Whittaker, A. H., 1987, Mud logging, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref>. On occasion, oil or gas wells may not flow fluid to the surface on completion. When this occurs, a swabbing unit is run to remove the hydrostatic column of fluid in the wellbore and allow the well to kick off and flow.

''Swabbing'' can be defined as pulling a full-diameter tool from the wellbore; this pulling action is similar to that of a plunger in a syringe, and it initiates fluid flow into the wellbore.<ref name=pt09r26>Whittaker, A. H., 1987, Mud logging, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers.</ref> On occasion, oil or gas wells may not flow fluid to the surface on completion. When this occurs, a swabbing unit is run to remove the hydrostatic column of fluid in the wellbore and allow the well to kick off and flow.

In some oil wells, the bottomhole pressure may be insufficient to lift fluid continuously. Because a surface flow rate cannot be maintained and measured, routine flow and buildup tests cannot be used to evaluate reservoir properties and determine well productivity. In these instances, a swabbing tool can be run at regular intervals to keep fluid flowing from the formation more or less continuously.

In some oil wells, the bottomhole pressure may be insufficient to lift fluid continuously. Because a surface flow rate cannot be maintained and measured, routine flow and buildup tests cannot be used to evaluate reservoir properties and determine well productivity. In these instances, a swabbing tool can be run at regular intervals to keep fluid flowing from the formation more or less continuously.

[[Category:Production engineering methods]]

[[Category:Production engineering methods]]