# HYDRAULIC CALCULATIONS Reference 1. Flow rates for cement displacement

In document Drilling and workover best practices (Page 108-118)

## Calculate casing string weight in air

### 4. HYDRAULIC CALCULATIONS Reference 1. Flow rates for cement displacement

4.1.1. Displace at maximum allowable flow-rate. Normally turbulent flow in the annulus is preferred, in any case always monitor return.

4.2. Estimated pressure profile

4.2.1. Plot versus time/volume the following parameters:

• Surface circulating pressure

• Bottom hole pressure

• Previous casing shoe pressure

• Any critical zone.

5. PLACEMENT TECHNIQUES Reference

5.1. Single or multistage cementing operation

5.1.1. Perform second stage operations as soon as cement setting time of first stage is expired (at least twice the time thickening time). Lab test is recommended.

P-1-M-6140 12.3.2-7

5.2. Inner string

5.2.1. All surface casing will be cemented through inner string.

5.3. Liner cementing operation.

5.3.1. Under normal conditions, the liner will be hung with a 100 to 150m overlap into the previous casing. If a smaller overlap is necessary due to a particular situation, it shall never be less than 50m

P-1-M-6140 12.7.1-3

5.3.2. If the rat hole exceeds the overlap length, set a cement plug at a distance from the liner shoe setting depth shorter than the overlap itself.

P-1-M-6140 12.7.1-3

5.4. Tie-back string cementing operation.

5.5. Casing cementing operation in sub-sea wells.

6. DOWN HOLE EQUIPMENT SELECTION Reference

6.1. Casing shoe 6.1.1. Guide shoe.

6.1.2. Float shoe.

6.2. Collar 6.2.1. Float collar.

6.2.2. Multistage collar.

6.3. Casing centralisation programme 6.3.1. Number & type of centralisers.

6.3.2. Number & type of scratchers.

6.3.3. In floating rig-drilling operations the number of centralisers must be limited. Avoid the use of scratchers.

6.4. Cementing plugs

6.4.1. Non rotating PDC drillable plugs are recommended. P-1-M-6140 12.3.1-8

7. SURFACE EQUIPMENT SELECTION Reference

7.1. Type & pressure rating of cementing head.

7.1.1. As alternative the circulating head can be requested with a bottom quick seal connection (without thread).

A-1-SS-1729 5.3.7

7.2. Number of cementing units.

7.2.1. It must be provided with twin triplex pumping units for pumping the cement slurry, for high pressure mixing and for general pumping operations

A-1-SS-1729 5.3.1-1

7.3. Number & volume of available tanks

7.3.1. It is recommended to mix slurry in advance using batch mixer.

7.4. Layout of surface cementing equipment.

8. OPERATING PROGRAMME Reference

8.1. Summary of operations

8.1.1. Testing pressure for surface lines: 5,000psi. P-1-M-6140 12.3.1-4 8.1.2. Stop displacement in advance only if pressure exceeds 70% of

casing burst pressure or 5,000psi, whichever is less.

P-1-M-6140 12.3.1-20

8.1.3. Prior to mix cement, water shall be checked. When mixing cement, samples of slurry shall be collected. Also take mixing water samples and dry cement samples from each tank used.

P-1-M-6140 12.3.1-11

8.1.4. In jack-ups and fixed platforms drilling operations, at end of surface casing cementing job, carefully wash the annulus between CP and surface casing to at least 5meters below the sea bottom, in order to allow well abandoning operations according to specifications11.

P-1-M-6140 12.3.1-28

8.2. Displacement

8.2.1. • The displacement volume (for 30” CP and surface casing) should be 1 bbls less than the theoretical volume.

• Max over displacement volume equal to 1/2 of shoe-collar volume.

P-1-M-6140 12.3.1-28

8.3. Surface pressure at bump plug

8.3.1. The bumping pressure values are always given in the Drilling Programme.

P-1-M-6140 12.3.1-23

8.4. Parameters recording

8.4.1. Record all mixing, displacing and bumping operations (pressure, flow rate, total volume versus time).

P-1-M-6140 12.3.1-29

8.5. Total Job time

8.5.1. Compare total job time (including mixing time), to pumpability time.

8.6. Time for W.O.C.

8.6.1. • According to laboratory tests results (if done) or 2-3 times thickening time (check the samples, for surface jobs).

• Check always annulus level.

• Whenever it is possible close BOP and pressurise up to 100-200psi according to weakest fracturing point.

Reference List:

‘Drilling Procedures Manual’ STAP-P-1-M-6140

‘Drilling Design Manual’ STAP-P-1-M-6100

‘Cementing and Pumping Service For Drilling Completion

and Workover Activity STAP-A-1-SS-1729

11 In order to have the sea bed free from any obstructions, it is recommended in well abandonment operations to recover at least 5 meters of casing strings below the seabed.

PL. 2.16. DRILL STRING DESIGN

1. DESIGN PARAMETERS Reference

1.1. Anticipated total depth.

1.1.1. The design of the drill string for static tensile loads requires sufficient strength in drill pipe to support the submerged weight of drill pipe and drill collar below.

Ldp = Length of drill pipe in feet Lc = Length of drill collar in feet Wdp = Weight per foot of drill pipe in air Wc = Weight per foot of drill collar in air Kb = Buoyancy factor

P-1-M-6100 10.11

1.2. Hole size.

1.2.1. Drill string acceptability (Refer to Table PL 2.9) P-1-M-6100 10.8 1.3. BHA Buckling

1.3.1. In the design of BHA, it is important to determine the critical values of weight on bit at which buckling occurs.

P-1-M-6100 10.9.

1.4. Formation type & dip.

1.4.1. Crooked hole drilling tendencies.

Standard packed hole assembly should be:

Bit + Near Bit Stab + Short DC (7ft =2.5m) + String Stab + K Monel DC + String Stab + 2 DC + String Stab

P-1-M-6100 10.12

1.4.1.1. Mild crooked hole. P-1-M-6140 8.5-a

1.4.1.2. Medium crooked hole. P-1-M-6140 8.5-a

1.4.1.3. Severe crooked hole. P-1-M-6140 8.5-a

1.4.2. Formation firmness.

Degree of drillability of the formations.

• Hard to medium hard formations - Abrasive

- Non abrasive

• Medium hard to soft formations

P-1-M-6140 8.5-b

1.5. Hole deviation 1.5.1. Hole angle control.

• Packed bottom hole assembly.

• Pendulum bottom hole assembly.

P-1-M-6140 8.3

1.5.2. BHA analysis in directional drilling PL.02.01-8.1

1.6. Concentrations in bending stresses

1.6.1. The (I/C) ratio 12 is assumed as criterion to evaluate the resistance at bending.

• Soft formation (I/C)ratio < 5,5

• Hard formation (I/C)ratio < 3,5

P-1-M-6100 10.8 P-1-M-6140 8.8

1.7. Margin of overpull (MOP)13.

1.7.1. The minimum recommended value of MOP is 6,0000lbs P-1-M-6100 10.11

P-1-M-6140 8.11

1.8. Torque & drag evaluation 1.8.1. Software applications.

1.9. Differential sticking.

1.10. Hydraulic requirements. PL.02.13

12 I, moment of inertia; I= 64π

OD4ID4

## )

2 C= OD

(I/C)ratio (I/C)large pipe/(I/C)small pipe

13 MOP=Pa-P

Pa,max allowable design tension load; Pa=90% Pt

1.11. Casing wear.

1.11.1. Software applications. PL.02.05 4.1

1.12. Drill stem corrosion & sulphide stress cracking. P-1-M-6110 9.2.1

Reference List:

‘Drilling Procedures Manual’ STAP-P-1-M-6140

‘Drilling Design Manual’ STAP-P-1-M-6100

‘Casing Design Manual’ STAP-P-1-M-6110

Hole Size (ins)

Drill Collar/Drill Pipe

(ins) I/C I/C Ratio Remarks

DC 91/2 x 3 83.8 1.5

DC 81/4 x 213/16 55.9 9.8

DP 5 x 19.5lbs/ft 5.7 - Not

DC 91/2 x 3 83.8 1.5 Recommended

DC 81/4 x 213/16 55.9 7.1 DP 51/2 x 19.5lbs/ft 7.8 1.4

DP 5x 19.5lbs/ft 5.7

-171/2 DC 91/2 x 3 83.8 1.5 OK for

DC 81/4” x 213/16 55.9 5.2 SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7

-DC 91/2 x 3 83.8 1.5

DC 81/4 213/16 55.9 2.5 OK For HARD DC 61/4 x 213/16” 22.7 1.9 Formations

DP 5” x 19.5lbs/ft 5.7

-Note: For every hard formations, add HWDP

DC 91/2” x 3” 83.8 1.5

121/4 DC 81/4 x 213/16” 55.9 2.5 OK For HARD DC 61/4 x 213/16 22.7 3.9 Formations

DP 5” x 19.5lbs/ft 5.7

-Note: For every hard formations, add HWDP

DC 91/2” x 3” 83.8 1.5

121/4 DC 81/4 x 213/16” 55.9 5.2 OK For SOFT

HWDP 5” x 42.6lbs/ft 10.7 1.9 Formations

DP 5” x 19.5 lbs/ft 5.7

-DC 61/4 x 213/16” 22.7 Not

DP 5” x 19.5lbs/ft 5.7 3.9 Recommended

85/8 DC 61/4 x 213/16” 22.7

HWDP 5” x 42.6lbs/ft 10.7 Recommended

DP 5” x 19.5lbs/ft 5.7

Table PL 2.9 - Drill String Acceptability

PL. 2.17. BIT SELECTION & DRILLING PARAMETERS

1. FACTORS AFFECTING BIT SELECTION Reference

1.1. Main factors to consider and evaluate 1.1.1. • Bit cost

• Method of drilling (turbine, rotary, air)

• Formation type and properties

• Mud system

• Rig cost

P-1-M-6100 11.1

1.2. To optimise the drilling operations.

1.2.1. Monitoring the drilling performance and conditions on the prospect well so that the performance is equal to or above the average in the area.

P-1-M-6100 11.1

1.2.2. Implementing a bit weight-rotary speed programme based on theoretical calculations that will improve the performance above the existing best performances in the area.

P-1-M-6100 11.1

1.3. Parameters involved in the selection of drill bits

1.3.1. In hard and abrasive formations roller bits in IADC code range 6-1-7 or higher are usually more successful.

P-1-M-6100 11.4.1

1.3.2. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness.

P-1-M-6100 11.4.2

1.4. Directional drilling considerations

1.4.1. Rotary drilling to right-hand walk is increased when using roller bits are used as cone offset from the bit centre increases.

P-1-M-6100 11.4.3

1.4.2. PDC bits with their relatively lower bit weights and no cones, hence cone offset problems are favoured.

P-1-M-6100 11.4.3

1.5. Rotating system

1.5.1. Rotary table / top drive system.

1.5.2. Down-hole motor

1.5.2.1. Using turbine, bits with long life expectancies should be used such as PDC, diamond and journal bearing insert bits.

P-1-M-6100 11.4.4

1.5.2.2. Turbine drilling may have a tendency to left-hand walk. This is controlled by the turbine used, bit gauge length, and BHA stabilisation

P-1-M-6100 11.4.3

1.6. Geological requirements 1.6.1. Minimum cutting size.

1.7. Mud type

1.7.1. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness.

P-1-M-6100 11.4.2

1.8. Available bit records analysis.

1.9. Drilling cost optimisation

1.9.1. Representative bit-cost curves. P-1-M-6100 11.6

Reference List:

‘Drilling Design Manual’ STAP-P-1-M-6100

PL. 2.18. EXPECTED DRILLING PROBLEMS & RECOMMENDATIONS

1. DRILLING DIFFICULTIES Reference

Describe the drilling difficulties encountered in reference wells, detailed by phases.

P-1-M-6001E

2. SUGGESTIONS Reference

Suggestions must be provided in order to prevent or manage at best all the expectable difficulties.

P-1-M-6001E

3. GENERALITIES Reference

3.1. In the operative sequence of the drilling programme, for each phase in a specific paragraph will be reported the drilling problems that will include a specific contingency plan to cover each of them.

P-1-N-6001E 6.2

4. LOSSES CIRCULATION Reference

4.1. Preventive measures 4.1.1. Mud characteristics

4.1.1.1. Particularly in surface holes, maintain high mud viscosity values. OP.02 12-9.1.2 4.1.1.2. Keep the mud weight as low as possible providing for adequate

overbalance.

P-1-M-6140 17.1-1

4.1.1.3. Maintain low yield point and gel strengths. P-1-M-6140 17.1-1 4.1.2. Drilling parameters

4.1.2.1. Avoid high circulation rates. P-1-M-6140 17.1-4

4.1.2.2. Always start pumping slowly.

4.1.3. Miscellaneous

4.1.3.1. Use bit nozzles larger than 14/32”. P-1-M-6140 17.1-9 4.1.3.2. While tripping: minimise surge pressure. P-1-M-6140 17.1-5 4.2. Remedial actions

4.2.1. Refer to Figure PL 2.4 P-1-M-6160 6.1

5. DIFFERENTIAL STICKING Reference

In document Drilling and workover best practices (Page 108-118)

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