Atención a la diversidad en la programación

The following list defines specific requirements and guidelines for well barriers:

a) All WBEs, control lines and clamping arrangements shall be resistant to environmental loads (chemical exposure, temperature, pressure, mechanical wear, erosion, vibration, etc.). b) All production or injection wells shall be equipped with a tree.

c) A DHSV shall be installed in the completion string for all wells penetrating a hydrocarbon bearing reservoir or wells with sufficient reservoir pressure to lift fluids to surface or seabed level

(including supercharged injection formations).

d) All production or injection wells shall have an annular seal between the completion string and the casing or liner, i.e. production packer.

e) It shall be possible to install a tubing hanger plug (or a shallow set tubing plug) and a deep set tubing plug in the completion string.

f) The tubing bore shall have continuous pressure transmitter monitoring at the wellhead/ tree level with alarms.

g) The pressure in the A-annulus shall have continuous pressure transmitter with alarms at the wellhead / tree level with safe operating pressure limits defined.

h) All accessible annuli shall be equipped with pressure gauge(s) with safe operating pressure limits defined.

7.4 Well barrier elements acceptance criteria

The following table describes requirements and guidelines which are additional to the requirements in Section 15.

Table 17 – Additional EAC requirements Table

no. Element name Additional features, requirements and guidelines

1 Fluid column There shall be sufficient fluid, including minimum 100 % well volume, available on

the location to maintain the minimum acceptable density.

4 Drilling BOP The drilling BOP shall be capable of shearing all tubular (including any lines and/or

wire strapped to the tubular) and sealing the wellbore. If this is not possible, (e.g. for completion assemblies), it shall be possible to:

a) lower the assembly below the BOP, or b) drop the string below the BOP, or

c) close the BOP on a suitable tubular within a distance equivalent to the length of a stand.

7.5 Well control action procedures and drills 7.5.1 Well control action procedures

The following table describes incident scenarios for which well control action procedures should be available. This list is not comprehensive and additional scenarios may be included based on the planned activities.

Table 18 – Well control action procedures

Item Description Comments

1. Well influx/inflow (kick) or fluid loss while

running or pulling the completion string A stab-in (tubing) safety valve shall be prepared (with the same connections as the string) and be ready for use at all times.

2. Running non-shearable items across BOP shear rams

3. Running completions with multiple control lines

4. Running and installation of sand screens Surge and swab effects. Inability to shut-in the well with perforated pipe through the BOP.

5. Planned or emergency disconnect of marine riser

Applies to subsea operations

6. Drive or drift-off Applies to DP vessels

7. Anchoring failure Loss of one or more anchors/ anchor chains

7.5.2 Well control action drills

The following well control action drills should be performed:

Table 19 – Well control action drills

Type Frequency Objective Comments

Kick drill – completion Once per crew before

start-up of main operation

Response training to an influx while running lower or upper completion

Use procedure which covers the upcoming operation(s). Emergency disconnect of

marine riser (including SSTT if used) drill

Once per crew as soon as practical after rig-up

Response training Without physically

disconnecting the riser, including SSTT if used, simulating all the steps required for planned and emergency disconnect

7.6 Completion string design 7.6.1 General

All completion, liner and tie-backs strings shall be designed to withstand all planned and/or expected stresses, including those induced during potential well control situations. The design process shall be for the full life cycle of the well, including abandonment. Degradation of materials shall be taken into

7.6.2 Design basis, premises and assumptions

The following shall be assessed to establish the dimensioning parameters for the design process: a) reservoir pressure during well life, including reservoir fluids and/or gas properties;

b) planned well trajectory and bending stresses induced by well doglegs and curvature; c) casing design;

d) well control and maximum well kill pressure;

e) planned production and/or injection rate and associated fluid and/or gas properties; f) annulus pressure management of accessible annuli;

g) H2S and/or CO2 including potential reservoir souring during life of well;

h) fluids compatibility and corrosion; i) well life expectancy;

j) material selection; k) sand control requirements; l) artificial lift requirements;

m) potential hydrate, scale and asphaltene deposits and chemical injection requirements; n) loads induced by well services and operations including well interventions, scale squeeze,

fracturing and/or other chemical treatments; o) geo-tectonic forces;

p) well suspension and abandonment requirements;

7.6.3 Load cases

When designing for burst, collapse and axial loads, cases applicable for the planned activity shall be applied. Every well type shall have a tubing stress analysis performed. The following load cases shall be considered. This list is not comprehensive and actual cases based on the planned activity shall be performed:

Table 20 – Load cases

Item Description Comments

1. Pressure testing of the completion string

2. Pressure testing A-annulus Testing of tubing hanger seals from below and production _{packer from above (as a minimum to MAASP)}

3. Shut-in of well

4. Dynamic flowing and injection conditions Special focus on temperature effects for production and _{injection wells (water, gas, WAG and simultaneous WAG)}

5. Injection Maximum injection system pressure (WDP)

6. Production

Should check tubing collapse as a function of minimum tubing pressure (plugged perforations/ low test separator pressure/ depleted reservoir pressure) combined with a high operating annulus pressure (minimum to MAASP)

Consider effects due to erosion/ corrosion

7. Bullheading/ pumping Well killing, stimulation, fracturing

8. Overpull Stuck string, shear rating of pins/ rings. Tensile strength of all _{completion components, including equipment connections.} 9. Firing of TCP guns

10. Temperature effects All closed volumes with special attention to start-up and shut-_{in of well}

11. Artificial lift

Shut-in of annulus by closing ASV and evacuated annulus above gas lift valve

Maximum injection system pressure

7.6.4 Minimum design factors

Tubing shall be designed to withstand all planned and/or expected loads and stresses including those induced during potential well control situations. The minimum design factors shall be as described in section 4.3.6.

7.6.5 Completion equipment – emergency shut-down system

The following completion string equipment shall be classified as part of the installation’s emergency shutdown system:

a) DHSV;

b) ASV or other fail-safe closed devices, if installed; c) tree valves - master and wing valves;

d) tree/wellhead valves serving chemical injection lines; e) tree/wellhead valves serving annulus gas lift valve.

7.7 Other topics