Well Testin

1
Well Testing

• 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
Well Testing

• 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
DST tool schematic
4
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
FSI period
Main flow or Final flow
Pre-flow
ISI period
IHP
Pressure
FHP
5
ISIP
6
Trip in Hole (TIH)
3
FSIP
Trip out of hole (TOH)
1
4
FFP
IFP
FpfP
IpfP
Time (hours)
2
1 2 3 4 5 6
7 8 9 10 11 12
Conventional DST recorder
5

• 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.
• 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 gt 15 md.
• About 10 minutes in duration if the
  permeability is estimated to be gt 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).
• 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

• 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.
• 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.
• 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
Water and/or hydrocarbons recovered in drill pipe
during this flow period
Hydraulic valve closed Bypass ports open Packer
deflated to avoid swabbing
Expanded packer
Pressure recorded in both flow and shut-in periods
Tripping out (or in)
Main Flow Period
Shut In Period
8
Pressures are at test depth
Hydrostatic pressure Tool open Initial flowing
pressure Final flowing pressure Tool
closed Shut-in pressure
Pipe recovery