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
Internal
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
Internal
Internal
DST tool schematic
Pressure
Pre-flow
FpfP = final pre-flow pressure
FFP = final flowing pressure
FSI
period
Main
ISI
flow or
period
Final
flow
IHP
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
FHP
ISIP
6
3
FSIP
1
4
FFP
IFP
IpfP 2 FpfP
1
Internal
Time (~hours)
7
10
Conventional DST recorder
11
12
4
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.
Internal
Pre-Flow OR IF (Initial Flow)
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 -10 minutes in duration if the K 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
ISIP (Initial Shut-In 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).
Internal
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.
Main Flow (Second Flow)
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.
7
Internal
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.
Final Shut-In Period (FSIP)
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.
Internal
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.
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.
Internal
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.
Water and/or
hydrocarbons
recovered in
drill pipe
during this
flow period
Hydraulic valve
closed
Bypass ports
open
Expanded
packer
Packer deflated
to avoid
swabbing
Pressure
recorded
in both
flow and
shut-in
periods
Internal
Main Flow Period
Shut In Period
10
Tripping out (or in)
Pressures are at test depth
Hydrostatic pressure
Tool open
Initial flowing pressure
Final flowing pressure
Tool closed
Shut-in pressure
Pipe recovery
Internal
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