Class note on well testing

1. 1
Well Testing
1. Initial production tests at surface after wellbore cleanup
and fracing. Sometimes called initial potential or IP.
IP= Initial Production
IPF = flowing
IPP = pumping
COF = calculated
open-flow
CAOF = calculated
absolute
open flow

2. 2
Well Testing
2. Various types of surface pressure tests (usually for gas wells).
This data is also used to calculate bottom-hole pressures
3. THE DST!!! Or Drill Stem Test
Used in both oil and gas wells, in cased or uncased wells.
Very, very common test so learn about them!!
Used to determine
• formation permeability
• boundary conditions of reservoir
• formation pressures
• fluid (oil and water), and gas recovery from formation

3. 3
DST tool schematic

4. 4
Conventional DST recorder
Pressure
Time (~hours)
1 2 3 4 5 6 7 8 9 10 11 12
IHP
IpfP FpfP
ISIP
IFP
FFP
FSIP
FHP
ISI
period
Main
flow or
Final
flow
Pre-flow
FSI
period
FpfP = final pre-flow pressure
FFP = final flowing pressure
FHP = final hydrostatic pressure
FSIP = final shut-in pressure
IFP = initial flowing pressure
IHP = initial hydrostatic pressure
IpfP = initial pre-flow pressure
ISI = initial shut-in
ISIP = initial shut-in pressure
1
2
3
4
5
6

5. 5
1. As the DST tool is lowered down the hole, the hydrostatic tool measures the increasing weight of the
water/mud column in pounds per square foot (PSI). After the tool reaches either total depth (TD) or
the desired depth of the test it is opened to atmospheric pressure and a pressure drop is recorded
almost instantaneously. This is done to relieve the hydrostatic pressure from the annular space
within the tested interval.
2. The length of the pre-flow (sometimes called initial flow) is determined by the surface blow
monitored on the drill floor according to the following observations:
About 5 minutes in duration if the permeability is estimated to be > 15 md.
About 10 minutes in duration if the permeability is estimated to be > 15 md.
If the pre-flow period is too short the hydrostatic pressure will not be dissipated and the following
shut-in period may be under the influence of hydrostatic pressure.
At the end of the pre-flow period the tool is closed and the pressure below the packer is allowed to
build up. This is called the initial shut-in pressure (ISIP).
3. The purpose of the initial shut-in period is to record the reservoir pressure before any production has
occurred. It is important to have an initial shut-in period long enough to extrapolate a maximum
reservoir pressure. Many times it is too short to determine a reliable extrapolated reservoir
pressure. This can make it more difficult to determine if the reservoir is of limited areal extent.
When the initial shut-in period is complete, the tool is again opened. The purpose of this second
flowing period (Main Flow) is to allow reservoir fluid and gas to enter the drill string. Analysis of the
final flow data will help determine the flowing capabilities of the tested reservoir. Depending on
conditions, when the tool is opened the pressure will drop from reservoir pressure to the pre-flow
pressure and will record the weight of the formation fluid entering the drill string. If gas is present the
flowing pressure will reflect the upstream pressure of the gas flow.

6. 6
4. The duration of the final flow period (Main Flow) should be about 60 to 180 minutes, depending
on conditions and estimated permeability. The air blow at the surface will indicate whether
formation fluid or gas is entering the drill string. If gas flows to the surface a stabilized
measured rate is desirable for proper reservoir evaluation.
When the final flow period is concluded the tool is again closed for a second shut-in period
(Final Shut-in Period) which stops the flow of fluid and gas into the drill string. The pressure
below the packer is then allowed to build. The duration of the Final Shut-In Period should be
about 1.5 to 2 times as long as the Main Flow (second flowing period), depending again on
conditions and estimated permeability. In low permeable zones, longer shut-in times are
necessary for proper reservoir evaluation.
5. The purpose of this second shut-in period (Final Shut-in Period) is to once again measure the
reservoir pressure after a certain amount of production has occurred. Remember, during this
test period, fluid and/or is not being recovered. Only pressure is being measured. Proper
evaluation of the second shut-in data will help determine if the tested reservoir is of limited
areal extent. Skin damage, permeability, radius of investigation, and other reservoir parameters
can also be determined.
6. At the end of the Final Shut-in Period, the packer is released which allows the drilling fluid to
flow from the borehole annulus and into the test zone. Hydrostatic pressure is then recorded for
a second time. Because the pressure should be equalized (sometimes the packer gets stuck),
the packer can be easily be unseated from against the borehole walls so the tool can be
recovered.

7. 7
Main Flow Period Shut In Period Tripping out (or in)
Hydraulic valve
closed
Bypass ports
open
Packer deflated
to avoid
swabbing
Water and/or
hydrocarbons
recovered in
drill pipe
during this
flow period
Pressure
recorded
in both
flow and
shut-in
periods
Expanded
packer

8. 8
Hydrostatic pressure
Tool open
Initial flowing pressure
Final flowing pressure
Tool closed
Shut-in pressure
Pipe recovery
Pressures are at test depth