Casing Design Workshop Review of Loads Casing Design Workshop

Our Example Well Our Data so far:

Surface Casing Example: Burst and Collapse Loads

Our Example Well Our Data so far:

Surface Casing Data Size: 13-3/8 Depth: 3000 ft Mud Density: 9.2 ppg at 3000 ft Frac Pressure at shoe: 12.3 ppg equiv at 3000 ft Temperature at Surface and Shoe: 74 °F, 128 °F Maximum Mud Density and temperature before next casing string: 11.8 ppg, 263 °F Cementing Data: Displace with mud, cement to surface, 300 ft tail slurry at 15.4 ppg, 2700 ft lead slurry at 11.4 ppg, use 50% excess lead slurry, bump plug with 1000 psi above final displacement pressure.

Check Cement Hydrostatics Cement density is usually different from the drilling mud Check cement program to be sure that it does not allow formation nor cause formation fracture

Check Cement Hydrostatics First let us check to see if the well can support the cement design The fracture pressure will support the planned cement column but with only a small margin. In a real well we would want to reconsider this slurry design.

Surface Casing Collapse Installation – Post Plug Bump Inside: mud Outside: cement (lead slurry, tail slurry)

Surface Casing Collapse Drilling – Severe Lost Circulation Inside: air Outside: mud (mud density when casing was run)

Surface Casing Collapse Loads

Surface Casing Burst Installation: Plug Bump Inside mud + displacement differential + bump pressure (1000 psi) Outside: Cement (tail slurry, lead slurry)

Surface Casing Burst - Cmtg Float plugs or annulus packs off Mud outside, cement inside, pump pressure before shutoff Cement column length inside casing will differ from annular column length Determine inside column length of cement Column lengths do not transform as vertical depths (unless the inclination is constant over the interval) External column length must be transformed to internal column length and vertical depths of the top and bottom must be determined from directional data Assume our well is vertical for this example

Transform Column Lengths Use cross sectional areas to get ratio of internal length to external length: Note we had to assume a specific ID before selecting the casing. An average ID is sufficient

Cementing Excess cement may fill 3000 ft of casing (the 1.5 in the first equation is the 50% excess) Lead slurry with 50% excess will more than fill the 3000 ft of surface casing. This leads to two possibilities (next slide).

Two Possibilities Case A Case B Inside: lead slurry + pump pressure Outside: mud Case B Inside: tail and lead slurry + pump pressure Outside: lead slurry and mud The severest cases for burst due to float or annulus plugging occur before the 9.2 ppg displacement fluid enters the casing.

Cement Case A Calculate differential burst pressures Case A

Cement Case B Determine interfaces Determine differential burst pressures Case B

Surface Casing Burst Installation – pre-drill out test (1500 psi) Inside: mud Outside: assume mud Some operators test casing immediately after plug bump to avoid damaging cement sheath. While this is a good practice it is not equivalent to a test before drilling out since the unset cement is usually more dense than a mud channel. In many areas, regulations require the test after cement has set and before drill out.

Surface Casing Burst Drilling – Gas Kick Inside: gas, pressure governed by the lesser of formation pressure or fracture pressure Outside: mud or water (since this is surface casing we will assume fresh water gradient as worst case)

Surface Casing Burst Load Pressure Control Gas inside Pressure determined by injection into weak zone below shoe Fresh water on outside (common assumption with surface casing)

Surface Casing Drilling Burst Determine fracture pressure at shoe Determine maximum gas pressure at shoe, zone at 10500 ft has max pressure Determine if that zone pressure exceeds frac pressure It does by a considerable margin, hence the fracture pressure at the shoe is the governing pressure.

Surface Casing Drilling Burst Formation gas pressure will exceed frac pressure at shoe so the frac pressure will be the limiting pressure. Now calculate gas pressure at the surface. Use the frac pressure at the shoe as the maximum pressure in this calculation

Surface Casing Drilling Burst Calculate differential burst loads at surface and at shoe Now we may plot our surface casing burst loading

Surface Casing Burst Loads

Surface Casing Burst Loads Note: we might want to reconsider our test pressure since it is less than the maximum pressure we anticipate in the case of a gas kick (more on this when we make our casing selection)

Surface Casing Loads Example As already mentioned we cannot calculate the axial loading until we make a preliminary casing selection for collapse and burst Stop Here for Surface Casing Project

Intermediate Casing Example: Burst and Collapse Loads

Our Example Well Our Data so far:

Example: Intermediate Casing Depth: 10,500 ft, Pore pressure: 11.3 ppg Fracture pressure: 15.7 ppg (10,500 ft) Mud density: 11.8 10500 ft, 15.3 14,000 ft Temperature: 74°F at 0 ft, 263°F at 10500 ft, 326°F at 14,000 ft Cement: Cement to 500 ft inside surface casing, 1000 ft tail slurry at 15.9 ppg, 7000 ft lead slurry w/50% excess at 12.0 ppg, 1000 ft spacer at 12.0 ppg, displace plug w/11.8 ppg mud, bump plug with 1000 psi above final displacement pressure

Intermediate Casing Loads Collapse Load Essentially same as for surface casing Severe lost circulation with air inside entire string is not likely for most wells Severe lost circulation generally requires keeping the casing full with freshwater (or seawater) to prevent a blowout Burst load Similar to surface casing Full formation or shoe frac pressure to surface ‘Maximum load’ method ?

Intermediate – Collapse Installation – Running (no possibilities) Installation – Post Plug Bump Inside: 11.8 ppg mud displacement Outside: 1000 ft 15.9 ppg cmt, 7000 ft 12.0 ppg cmt w/50% excess, 1000 ft 12 ppg spacer, and 11.8 ppg mud Preliminary Calculations Excess cement column height Does cement column exceed frac pressure ?

Intermediate Collapse Installation – Running No possibilities Installation – Post Plug Bump Inside: 11.8 ppg mud displacement Outside: 1000 ft 15.9 ppg cmt, 7000 ft 12.0 cmt w/50% excess, 1000 ft 12 ppg spacer, and 11.8 ppg mud The picture does not show what is described to the left. What we will see in the next few slides is that the worst case cement will go to the surface.

Intermediate – Collapse (2) Preliminary Calculations Excess cement column height Does cement column exceed frac pressure ? Excess cement column With a gage hole the excess lead slurry will easily reach the surface Worst case then is 1000 ft 15.9 ppg and 9500 ft of 12.0 ppg cement We run excess cement to account for hole size uncertainty so that it will reach the desired height in the well. If the cement column is more dense than the displacement fluid (and it should be in good cementing practice) the worst case post plug bump (after the bump pressure is released) is if the excess cement is higher in the well than intended. The highest it can be (discounting channeling) occurs when the hole is gage size and that is what we use to determine the cement height for collapse and hydrostatic frac margin.

Check Cement Program 1000 ft 15.9 ppg tail, 7000 ft 12.0 ppg lead w/50% excess, 1000 ft 12.0 ppg spacer

Cement Program It is also a good idea to plot the cement hydrostatic pressures to be sure that fracture pressures in other parts of the hole are not exceeded

Intermediate – Collapse (4) Calculate post plug bump pressure differentials – maximum case

Intermediate – Collapse (5) Drilling – Lost circulation Inside: air or air/mud Outside: mud 11.8 ppg Severe lost circulation with casing empty is not possible if our data is correct Other possibilities are drilling induced fractures near the shoe Trip surge Annular bridge

Intermediate – Lost Circulation Collapse Assume our data is accurate: Induced fracture – 11.3 ppg fm pressure, 15.3 ppg mud (11.3 is lowest pore pressure in OH, 15.3 is heaviest mud weight in next OH interval) Drilling induced fractures (from pipe movement surges) can occur. After fracture the formation pressure at that point would be the limiting pressure value. The highest mud density used down hole would represent the worst collapse case.

Intermediate – Lost Circulation Collapse Calculate differential collapse pressures

Intermediate – Lost Circulation Collapse What if our fracture data is unreliable? We could consider two severe lost circulation possibilities Empty string Fill with water Data is usually spotty at best

Intermediate – Lost Circulation Collapse Calculate the two common possibilities just for comparison Severe lost circulation – empty string Severe lost circulation – fill with fresh water Common practice offshore to use sea water instead of fresh water

Example Collapse Load

Intermediate Casing Burst Installation – plugged float (uncommon) Inside: cement (tail slurry, lead slurry, spacer), displacement mud Outside: mud 11.8 ppg We must resolve the cement column lengths from annular lengths to internal lengths

Intermediate Casing Burst (2) The ratio of inside to annular volume/ft is Spacer = 0.762(1000) = 762 ft Lead slurry = 0.762(1.5)(7000) = 8001 ft Tail slurry = 0.762(1000) = 762 ft Mud = 10500 – 8001 – 2(762) = 975 ft Lead slurry is calculated with gage hole and 50% excess (1.5*7000=10500 ft)

Intermediate Casing Burst (3) Calculate cementing burst pressures

Intermediate Casing Burst (4) Installation – plug bump Inside: 11.8 ppg mud Outside: cement column (worst case)

Intermediate Casing Burst (5) Drilling – gas kick Inside: gas, lesser of fracture pressure at shoe or pressure from lower formation Outside: water channel

Intermediate Casing Burst (6) Determine limiting pressure at shoe Frac pressure at shoe is the lesser

Intermediate Casing Burst (7) Based on the frac pressure calculate the surface gas pressure

Intermediate Casing Burst (8) Calculate the differential burst pressures

What if no gas is present? In a number of fields in the world the possibility of a gas kick does not exist An example with oil instead of gas is in the textbook Calculations are straightforward Oil kick – similar to gas kick except oil Use same BHP as last, oil gravity 35 API The burst load line here is for oil

Intermediate Casing Burst – Oil See manual (pp 5 – 47,48) for details Exceeds shoe frac pressure so: Saudi Aramco requested this example in CAC because they have regions with no gas and never get to see a design with oil

Oil Kick

Intermediate Casing Burst Note the mud column on top of the gas is from the “maximum load” method with a 5000 psi BOP limitation at the surface. That the oil load line (green) intersects the 5000 psi value at the surface is purely coincidental in this example and has no relation to the max load method.

Intermediate Casing Load Example As already mentioned we cannot calculate the axial loading until we make a preliminary casing selection for collapse and burst Stop Here for Intermediate Casing Project

Production Casing Example: Burst and Collapse Loads

Our Example Well Our Data so far:

Example Well : Production Casing Depth: 14,000 ft Pore pressure: 14.8 ppg Fracture Pressure: 16.2 ppg Mud density: 15.3 Surface Temperature: 74°F Bottom hole temperature: 326°F

Production Casing Data Cementing Data: Cement to intermediate casing, 1000 ft tail slurry at 16.6 ppg, 3000 ft lead slurry at 15.6 ppg, 1000 ft spacer (15.3 ppg) and displace plug w/15.3 ppg mud, bump plug with 1200 psi above final displacement pressure. Use 25% excess on all cement. Production: gas and condensate

Production Casing “Philosophy” Production casing will be in service for the life of the well Future as well as initial conditions affect design equally Think ahead, plan ahead

Production Casing Collapse Installation – cementing, post plug bump Inside: displacement fluid, 15.3 ppg mud Outside: cement column, 1000 ft tail 16.6 ppg, 3000 ft lead 15.6 ppg, 1000 ft spacer 15.3 ppg, 25% excess on all cement

Production Casing Collapse Check cement pressures:

Production Casing Collapse Calculate the differential pressures at the annular interfaces

Production Casing Collapse Production – empty casing Inside: air Outside: formation pressure or mud We do not normally visualize this happening, but later in the life of many wells it does happen and not always intentionally

Production Casing Collapse Determine differential collapse pressures with empty casing using mud on the outside

Production Casing Collapse Loads

Production Casing Burst Installation – plug bump Inside: brine plus bump pressure Outside: cement and mud (use worst case)

Production Casing Burst (2) Calculate pressures

Production Casing Burst (3) Calculate differential burst pressures Calculated at points where outside and/or inside fluids change densities

Production Casing Burst (4) Production – tubing backup Inside: gas from formation Outside: mud or water Use actual formation pressure for gas pressure, not mud weight pressure. Outside: mud or water ? Generally mud, but over time will solids settle out of mud and leave fresh water as only backup near surface? We will use water in our example.

Production Casing Burst (5) Calculate gas pressures Calculate differential burst pressures Note: formation pressure is 14.8 ppg equivalent

Production Casing Burst (6) Production – surface tubing leak Inside: SITP on top of packer fluid Outside: mud or water Most tubing leaks from corrosion occur near the surface, often just below the hanger. Produced CO2 mixing with fresh water condensing from cooling gas forms carbonic acid and corrosion. Failure to design for this in gas wells can result in rupture and cross flow in the lower portion of the string or collapse tubing with loss of packer fluid. Both rupture and tubing collapse have occurred.

Production Casing Burst (7) Although a case could be made for mud or formation pressure outside the lower part of the string we will use water again

Production Casing Burst Loads