This document outlines the testing requirement for barriers in Well Operations.
1 INTRODUCTION
Actual pressure test requirements and values will be stated and documented in the Well Programme.
HSEQ planning, management and execution, onshore and offshore, recognise pressure testing as a safety critical activity. Pressure testing shall be subject to the operating regulations of the MODU or Platform. Vessels and associated pipework to be pressure tested shall be barriered off to regulatory distance and announced on tannoy as per MODU procedures, and shall be inspected prior to testing by the responsible person assigned to the management of the pressure test.
2 GENERALITIES
1. The values of the different pressure tests should not exceed at any point the values that have been used for the Well Design.
2. Pressure test shall be carried out in the direction of the flow.
3. Prior to installation on the well, the BOP shall be pressure tested on stump to the maximum working pressure.
4. Where practicable, water should be used as the pressure test fluid. Prior to any pressure test, the area should be barriered off and personnel notified and / or evacuated.
5. The COMPANY Well Operations Supervisor shall witness all Pressure tests taking place on his rig.
6. Each test shall be recorded. Details of the test shall be reported on the Daily Drilling Report (DDR) and the IADC report.
7. Casing pressure test value will represent, during the entire life of the well, the maximum pressure to which this casing can be pressure up to.
8. If Nitrogen operations are planned then all the surface equipment to be used is to be pressure tested with a non-energised fluid (water for example), to the required test pressure, prior to testing with Nitrogen or gas as required.
3. BOP and WELLHEAD TESTING
PRESSURE TEST FREQUENCY
1. The pressure test frequency for surface well control equipment shall be:
a. A minimum of every 14 days unless written dispensation is obtained from the Affiliate Well Operations Manager or his delegate. A period of 21 days shall not be exceeded.
b. After installation of BOP on the wellhead.
c. After any BOP, wellhead or associated equipment component has been changed or repaired
d. After each casing run
e. Prior to conducting a DST.
PRESSURE TEST VALUES
1. Pressure tests on BOPs and valves should include a low pressure test of 1.4 to 2.1 MPa (200 to 300 psi) for 5 minutes before proceeding to the high pressure test.
2. All well control equipment, except the annular BOP, shall be pressure tested as a minimum to 110% of the maximum prognosed wellhead pressure.
3. Pressure testing values must not exceed the values used for the casing design calculations, (taking into consideration the mud weight when pressure testing casing strings and tubing).
4. Annular BOPs shall be pressure tested on drill pipe to a maximum of 70% of rated pressure (if not otherwise specified in manufacturer recommendations).
5. All well control equipment shall be pressure tested to their working pressure at least once at the beginning of the operations, thereafter the pressure test value can be adjusted to the maximum anticipated wellhead pressure.
6. Wellhead seals shall be pressure tested according to the manufacturer’s recommendations. When a casing is directly exposed to the pressure test fluid, the pressure value must not exceed 80% of the collapse resistance of the casing taking into consideration the possible tension applied to the casing.
4 CASING AND TUBING TESTING
1. Casing and liners shall be pressure tested prior to drilling out the shoe. The Well Operations programme shall state the pressure test values.
2. Note that for Workovers / Interventions, the pressure test value of any of the casings must not exceed the pressure test value to which the casing was exposed during the original drilling of the well. 3. Production casing and liners will be pressure tested and inflow tested on critical wells prior to well testing. Any displacement to a lighter fluid which can result in an underbalanced condition shall be performed in such a way that any potential for an influx can be detected and controlled.
4. The COMPANY Well Operations Supervisor must ensure that the pressure testing results is reported on the IADC and Daily Drilling Report. A test report will be filled in and test charts attached.
5. Maximum surface test pressure for new casing shall not exceed the lowest value of:
a. Eighty per cent (80%) of casing API internal yield rating of the weakest casing or connection in the string,
b. Wellhead working pressure,
c. BOP working pressure.
6. Due consideration shall be given to:
a. The density of fluid columns inside and outside the casing,
b. The Design Factors,
c. The impact of pressure testing on tensile loads,
d. The impact of pressure testing on cement sheet, e. Casing wear and / or corrosion.
7. Minimum test pressure for surface and intermediate casing shall be calculated as follows: surface pressure with the well full of gas limited by the expected formation fracture gradient at shoe plus 500 PSI.
8. Minimum test pressure for production casing and liners shall be equivalent to the shut-in tubing pressure on top of the annulus completion fluids. Refer to the Casing and Tubing Design Manual for more details.
9. For drilling, liner overlaps shall be pressure tested to a minimum of 7.0MPa (1000psi) over formation leak-off pressure at the shoe of the previous casing, this is for the purpose of leak detection.
10. For testing the liner overlaps will be pressure tested to the pressure corresponding to tubing leak over DST annulus fluid.
11. The integrity requirements of any additional working loads, such as annular pressure operated tools, shall also be taken into consideration.
12. An inflow test shall be done when the hydrostatic head at the top of the liner is expected to drop below the formation pressure isolated by the liner.
13. Tubing strings shall be pressure tested to the maximum anticipated wellhead pressure, plus a safety margin of 500psi for gas wells and 1000psi for oil wells.
5 LEAK-OFF AND FORMATION INTEGRITY TESTING
GENERALITIES
1. LOT and FIT are operations that are performed prior to start of drilling a section to ensure that the formation fracture gradient at shoe will allow the drilling of the following section with the planned mud weight and associated ECD.
2. The success of this delicate operation is essential for the safe pursuit of the drilling of the well. FIT / LOT are extremely important when drilling Exploration wells where the fracture gradient values are not empirical but extrapolated from offset wells or calculated. The result could influence the design of the future development wells.
3. The requirement for any Leak-off Tests (LOT) or Formation Integrity Tests (FIT) shall be detailed in the Well Programme.
4. A LOT or FIT shall be carried out as a minimum 3 to 5 metres into new drilled formation below the casing shoe for each casing below the surface casing, unless a dispensation is granted.
5. The absolute maximum surface pressure to perform a LOT or FIT shall be the lesser of:
a. Casing pressure test
b. Wellhead pressure test
c. 80% of casing internal yield rating
d. Any other limiting factor for the well.
6. The continuous slow pumping method shall be used for performing LOTs and FITs. Such tests shall be carried out using the cement unit.
7. The COMPANY Well Operations Supervisor shall witness all LOTs and FITs and shall plot and retain a chart showing volume pumped against pressure.
8. The results of any FIT or LOT shall be reported on the Daily Drilling Report and the IADC report.
FORMATION INTEGRITY TEST (FIT)
For a FIT the well bore is pressured up to a pre-determined value. No injection is expected nor seen.
However, sometime the fluid starts to inject into the formation. In such case pumping must be stopped at once to avoid fracturing the formation which could jeopardise the well objectives – the FIT has become a LOT:
LEAK OFF TEST (LOT)
1. During a Leak off Test we are looking for the injection point into the formation.
2. At the injection point, the pressure versus volume curve deflects, when the injection point is seen a MAXIMUM of 1.5 barrel (230litres) can be pumped and then the pumping is stopped, as shown in the graph below.
The graph above is an example of a good LOT.
The Graph below show a typical bad LOT where the formation was fractured.
ISOLATION PLUGS
1. Plugs which are part of the barriers will be pressure tested preferably in the direction of the flow.
2. Pressure Tests on cement plugs shall be carried out as per LOTs or FITs
3. The maximum pressure test for cased hole plugs (cement or mechanical) shall not exceed the lowest value of:
o Eighty per cent (80%) of casing API internal yield rating of the weakest casing in the string,
o Wellhead rated working pressure,
o BOP rated working pressure.
4. Consideration shall be given to:
o The density of fluid columns inside and outside the casing,
o The design factors,
o The impact of pressure testing effects on tensile loads,
o Casing wear and / or corrosion.
5. The minimum pressure test for a cement plug shall be 7.0MPa (1000 psi) above formation leak-off.
ACCEPTANCE CRITERIA FOR PRESSURE TESTS
1. Test pressures shall be held for a minimum of 3 minutes for low pressure and 10 minutes for high pressure after the pressure has stabilised at the required pressure value.
2. However the test will be deemed acceptable if, after a period of 10 minutes, the pressure has stabilised and is not less than 95% of the originla pressure.