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

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

DST tool schematic

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

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 > 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). 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.

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.

Main Flow Period Shut In Period Tripping out (or in) 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 Main Flow Period Shut In Period Tripping out (or in)

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