Calculate casing string weight in air
4. TESTS FREQUENCY Reference 1. BOP-stack
4.1.1. • After installing stack on well head.
• Any time a new casing string is run and cemented.
• Once every 14 days.
• Prior to run a DST or production test assembly.
• Any time required by Company.
4.2. Kill/choke lines, choke manifold, rig floor and cementing manifold
4.2.1. Every time tests are carried out on the BOP stack, the associated equipment shall also be tested, with water (see point 4.1.1).:
4.3.1. Each casing shall be pressure tested at the following times:
• When cement plug bumps on bottom with a pressure stated in the drilling programme.
• When testing blind/shear rams of the BOP stack against the casing.
• After having drilled out a DV collar.
4.3.2. A cemented liner overlap will be positively tested applying a pressure greater than the lea-off pressure of the previous casing. If there is any doubt, an inflow test could be carried out, with a sufficient drawdown to test the liner top to the most severe negative differential pressure that will exist during the life of the well.
4.4. BOP operating equipment
4.4.1. Every time BOP stack is nippled up, and after repairing operations. P-1-M-6150 7.5 4.5. Function tests
4.5.1. 1. The pipe ram and BOP valves should be operated at least once every shift.
2. Blind/shear rams shall be operated every round trip in the hole.
3. The annular preventer shall be operated when the scheduled routine BOP tests are performed.
5. DURATION OF TESTS Reference 5.1. The BOP 300psi low-pressure tests will be performed first. They are
to be held for a min period of 5min
5.2. High-pressure tests are held for a minimum of 10mins. The maximum acceptable pressure drop over this 10mins period is 100psi.
6. WELL CONTROL DRILLS Reference
6.1. Familiarity drills
6.1.1. The purpose of these drills is to familiarise rig personnel with the various equipment and with the techniques that will be employed in the event of a kick.
6.1.2. These tests shall be carried out on an each shift basis, at the beginning of any new activity, any time experienced personnel are replaced with new recruits, especially when key position personnel are involved such as the Toolpusher, Driller and Assistant Driller.
Drills shall be repeated until every crew member gains the correct experience and training.
6.2. Emergency “On-the-rig” drills
6.2.1. Simulate potential blowout situation. Drilling Contractor’s crew should follow the close-in procedure according to the current operations (bit on bottom, tripping).
6.2.2. Potential fire on wellsite and rig location abandonment simulation. P-1-M-6150 8.2.1 6.2.3. Tests shall be executed on each shift basis every week. P-1-M-6150 8.6.1 6.3. Pit drills
6.3.1. Simulate changes in the pit level indicator. Drilling Contractor’s crew should follow the close-in procedure according to the current operations (bit on bottom, tripping).
6.3.2. Tests shall be carried out:
• Each shift basis every fortnight.
• When the well is nearing or entering high-pressure zones.
6.4. Choke Manipulation drill
6.4.1. The test shall be carried out before drill out the shoe track at intermediate casing string
6.5. Drills evaluation
6.5.1. Drills evaluation is mainly based on performing time. Correct timing should be defined in Drilling Contractor’s procedures according to the equipment.
6.5.2. Pit drills:
Not more than 2.5 minutes from a readable change in drilling fluid volume to the time the well is closed-in or drill pipe started running back in hole if during trip.
6.5.3. ‘On-the-rig’ drills :
One minute time from giving the alarm signal to have the preventer closed.
7. PRIMARY WELL CONTROL Reference
7.1. General remarks
7.1.1. Underbalance drilling operations, which are not admitted on wildcat wells, shall be approved by Company Operative Base Drilling Superintendent through a detailed drilling programme.
7.1.2. Primary well control is mainly based on prediction of formation pressure. It depends on correct mud weight evaluation and proper operating practices.
7.2. Trip margin & equivalent mud weight
7.2.1. If while tripping out a swabbing is noted (the well is not flowing):
• Stop the trip
• Run back to bottom
• Circulate bottom up
• Resume tripping carefully.
7.3. Mud volume control
7.3.1. A minimum kill mud volume of 70m3 at 1.4kg/ft shall be stocked while drilling surface hole without BOP-stack. Anyway, at least minimum mud volume must be equal to three times internal drillstring volume.
P-1-M-6140 6.5-n P-1-M-6150 9.3.1-g
7.4. Maximum Allowable Annular Surface Pressure (MAASP)
7.4.1. The MAASP is representative of a specific drilling section, it depends on the following factors:
• Last casing shoe depth
• mud weight
• Minimum formation fracture gradient below the casing shoe
• minimum last casing burst pressure resistance.
7.5. Circulating pressure at reduced pumping rate 7.5.1. Reduced pump stroke pressure (RPSP).
Normal circulation flowrate reduced to Q/3 in 121/4” hole and Q/2 in 81/2” hole.
RPSP must be taken at the following times as a minimum:
• Once per tour, or every 300m (1,000ft) intervals.
• When there is any significant changes in the mud weight or mud properties.
• Whenever changes occur in the dimension and characteristics of the string, i.e. change in BHA, jet size, jet plugged or jet lost, etc
7.5.2. On floater rigs, the RPSP shall be measured by circulating, first through the riser and then through the choke/kill line.
7.6. Drilling break
7.6.1. Any time a drilling break is noticed:
• Drilling shall be stopped immediately
• Static control shall be carried out.
8. SECONDARY WELL CONTROL Reference
8.1. Well control decision tree
8.2. Well shut-in procedures P-1-M-6150 3
8.3. Killing procedures P-1-M-6150 5
‘Well Control Policy Manual’ STAP-P-1-M-6150
‘Drilling Procedures Manual’ STAP-P-1-M-6140
‘Drilling Design Manual’ STAP-P-1-M-6100
‘Casing Design Manual’ STAP-P-1-M-6110
PL. 2.15. CEMENT PROGRAMME
1. PRELIMINARY INFORMATION Reference
1.1. In a cementing job the factors, that guide the selection of the additives for the control of the slurry, flow properties and thickening time are:
• The annular configuration
• Wellbore conditions
•••• The mud type and density
• Temperature gradient
2. SLURRY DESIGN Reference
2.1. Total slurry volume calculation (lead/tail slurry volumes)
2.1.1. Always a percentage increment in volume must be considered for the open hole section. In absence of relevant data, can be assumed:
• Surface casing: 100 %
• Intermediate casing: 50 %
• Production casing: 30 %.
2.1.2. If logs are available, assume a percentage increment in volume equal to 10%.
2.2. Slurry density evaluation.
2.2.1. Circulating bottom hole and static temperatures need to be considered as well as the temperature differential between the bottom and top of the cement column.
2.2.2. Circulating temperatures by calculation in accordance with temperature schedules published in API 10 Specification
2.2.3. One rule of thumb which should apply to the slurry design, is to ensure that the static temperature at the top of the cement exceeds the circulating bottom hole temperature
2.3. Type & amount of cement
2.3.1. The cement type selection is mainly based on estimated bottom hole temperature.
2.4. Amount & composition of mix water. P-1-M-6100 7.1.2
2.5. Amount & type of additives
2.5.1. Weighting/lightening agents (barite, hematite, diatom, bentonite). P-1-M-6100 7.2.3/4
2.5.2. Retarders. P-1-M-6100 7.2.2
2.5.3. Accelerators. P-1-M-6100 7.2.1
2.5.4. Fluid loss reducers.
2.5.5. Friction reducers.
2.6. Slurry rheology properties evaluation. P-1-M-6100 7.5
2.7. Slurry fluid loss evaluation. P-1-M-6100 7.5
2.8. Slurry thickening time. P-1-M-6100 7.8.4
2.9. Slurry settlement properties. P-1-M-6100 7.8.4
2.10. Slurry compressive strength. P-1-M-6100 7.5
2.11. Laboratory tests
2.11.1. Before start with job on rig site, laboratory tests shall be performed using samples of actual cement, water and additives.
3. SPACER DESIGN Reference
3.1. Spacer volume calculation
3.1.1. Unless an effective mud density is required to control the formation pressure, all cement jobs shall be flushed with a water spacer.
The spacer volume shall be equivalent to, more or less, tree minutes of contact time or 150m of annulus capacity.
P-1-M-6140 12.3.1-6 P-1-M-6100 7.4
3.2. Spacer density evaluation
3.2.1. The best spacer is a spacer that has a density higher than the mud but less than the cement slurry.
3.3. Chemical composition
3.3.1. The spacer fluid must be compatible with both the mud and the slurry system, laboratory test shall be carried out.
3.4 Spacer fluid rheology properties evaluation P-1-M-6100 7.4
4. HYDRAULIC CALCULATIONS Reference