Well Testing

This is not an exhaustive presentation of well test analysis, it is intended to provide some basic information to jog the memory of the occasional user.

Well testing takes place at various times and for various purposes during the life of a well. The focus of this review is on the preliminary testing of a well used to determine whether a well should be completed or not. The information yielded includes:

• contents of porous zone - fluid or gas,
  

• the chemistry and viscosity of the gas or fluid
  
• permeability - an approximation,
  
• reservoir pressure
  
• flow rates
  
• formation damage

Drill Stem Tests (DST's) are still the most effective and accurate means of quickly testing a formation. They are run by attaching a testing tool to the drill pipe. Many new approaches have been developed to enable testing from a wire line tool, closed chamber testing or for testing many zones without the need to trip out of the hole. In Closed chamber testing the testing tool is closed in at the surface when the formation is flowing and only open at the surface when it is shut-in at the formation.

The testing tool has packers to isolate the zone of interest from the rest of the well - a bottom hole test has one packer to isolate the bottom hole from the rest of the well bore, while a straddle test has two packers to isolate a zone. Accurate information can only be obtained if the packers effectively isolate the zone therefore packers must be seated in competent zones.

The pressure data plotted against time during a test is recorded either mechanically on a chart in the testing tool or electronically transmitted to the surface. The shape of the curve during the various phases of the test give considerable information about the quality of the test and the quality of the reservoir. Pressure readings at certain points during the test help to quantify this informaton:

1. Initial Hydrostatic Pressure
   

2. Initial Flowing Pressure
   
3. Final Initial Flow Pressure
   
4. Initial Shut-in Pressure
   
5. Initial Final Flow pressure
   
6. Final Flow Pressure
   
7. Final Shut-in Pressure
   
8. Final Hydrostatic Pressure

The time required for each phase of the test will depend on the quality of the reservoir:

Initial flow period (time between points 2 and 3) should be less than 5 minutes - the longer the initial flow, the longer the wellbore will have to be Shut-in to return to virgin reservoir conditions.

Initial Shut-in period (time between points 3 and 4) should be at least 60 minutes

Final Flow period (time between points 5 and 6) should be at least 60 minutes

Final Shut-In Period (time between points 6 and 7) should be at least 2 times the Final Flow

Pressure point 1 is the hydrostatic pressure on the tool when it is seated ready for the test, it should be the same reading as 8.

Pressure point 2 is the pressure when the tool is first opened to the formation.

The shape of the curve between points 3 and 4 and points 6 and 7 should be similar with pressures 4 and 7 being nearly the same.

References and further links for information on this topic will soon be provided from this page.