PTRT 1321 OilField Hydraulics Chapter 8 Shutin Procedures

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PTRT 1321 Oil-Field Hydraulics Chapter 8 Shut-in Procedures Oil and Gas Technology Program

PTRT 1321 Oil-Field Hydraulics Chapter 8 Shut-in Procedures Oil and Gas Technology Program

Introduction • Serve several purposes – Stop the influx of formation fluid into the

Introduction • Serve several purposes – Stop the influx of formation fluid into the well bore – Protect the crew and rig – Provide an opportunity to organize and plan the kill procedure – Allow shut-in work string and casing pressures to be determined • A few abbreviations – Shut-in drill pipe pressure – SIDPP – Shut-in tubing pressure – SITP – Shut-in work string pressure – SIWSP • In this book the term SITP is used for all three Oil and Gas Technology Program

Introduction (cont) • IF well casing is set and adequately cemented in competent formation,

Introduction (cont) • IF well casing is set and adequately cemented in competent formation, usually the well can be shut in safely when a kick occurs • Shut-in procedures differ whether or not the work string is near bottom • Off shore procedures are listed but we will not discuss them here Oil and Gas Technology Program

Shut-in Procedure - I • Surface BOP stack - Typical on land rigs •

Shut-in Procedure - I • Surface BOP stack - Typical on land rigs • Fluid is being circulated • Work string is at bottom – Several different procedures are possible – Important that everyone involved knows ahead of time which procedures will be used – Example procedure uses a soft shut-in • Flow line through choke open • Then shut in well Oil and Gas Technology Program

Shut-in Procedure - I • Stop rotating – sound alarm • Pick up work

Shut-in Procedure - I • Stop rotating – sound alarm • Pick up work string far enough to ensure a tool joint or coupling is not in a ram BOP (if lower kelly cock is present make sure it clears the rotary table) • Stop the pumps • Check for flow • If well flows open the choke-manifold valve to allow flow to pit • Close the BOP (usually the annular preventer) • Close the choke slowly while watching casing pressure. (What to do if MASP is exceeded should already have been discussed and decided. ) • When the choke is closed allow a few minutes then record the SITP. • Record SICP • Record the pit-level increase Oil and Gas Technology Program

Shut-in Procedure - II • Surface BOP stack - Typical on land rigs •

Shut-in Procedure - II • Surface BOP stack - Typical on land rigs • Fluid is NOT being circulated • Work string is OFF bottom – Several different procedures are possible – Important that everyone involved knows ahead of time which procedures will be used – Example procedure uses a soft shut-in • Flow line through choke open • Then shut in well Oil and Gas Technology Program

Shut-in Procedure - II • • • • Set the work string on slips

Shut-in Procedure - II • • • • Set the work string on slips – sound alarm Install and make up a full-opening safety valve in the work string (valve should be in the open position) Close the work string safety valve Open the choke-manifold valve to allow flow to pit Close the BOP (usually the annular preventer) Close the choke slowly while watching casing pressure. (What to do if MASP is exceeded should already have been discussed and decided. ) Install an inside BOP and release the valve on the work string safety valve Pick up and make up the kelly Open the work string safety valve Start the pump and open the inside BOP by increasing pressure slowly in ¼ bbl increments (pressure should be linear with volume) With the inside BOP open, record the SITP. Record SICP Record the pit-level increase Oil and Gas Technology Program

Hard and Soft Shut-in Procedures • Often depends on the preference of the operator

Hard and Soft Shut-in Procedures • Often depends on the preference of the operator • Hard shut in means closing the BOP without first opening the alternate flow path through the choke line – Hard shut in keeps the kick influx to a minimum and simplifies the procedures – Increases the likelihood of formation break down • Soft shut in is the reverse Oil and Gas Technology Program

Hard Shut-in • Choke and the remote choke-manifold (HCR), or failsafe, valves are set

Hard Shut-in • Choke and the remote choke-manifold (HCR), or failsafe, valves are set closed during normal operations • When a kick occurs – – Close the preventer (adjust closing pressure as needed) Open the HCR (or fail-safe valves) Allow pressure to stabilize and then record SITP and SICP Read and record the pit-level increase • Casing pressure cannot always be recorded because the choke-line valves are closed. May result in MASP being exceeded without operator knowledge • Hard shut in does NOT cause hydraulic hammer and damage to the well bore even if gas is in the kick fluids Oil and Gas Technology Program

Soft Shut-in • Choke is set full open during normal operations • When a

Soft Shut-in • Choke is set full open during normal operations • When a kick occurs – – – Open the HCR (or fail-safe valves) Close the annular preventer Close the drilling choke Adjust closing pressure on BOP Allow pressure to stabilize and then record SITP and SICP Read and record the pit-level increase • More steps and more time • Preferred to hard shut in by some due to inability to read SICP Oil and Gas Technology Program

Kick Fluid Density and SICP • Generally best to assume that the kick consists

Kick Fluid Density and SICP • Generally best to assume that the kick consists of gas – Gas = 1. 5 ppg to 3. 0 ppg – Oil = 5. 0 ppg to 7. 0 ppg – Saltwater = 8. 6 ppg to 10. 0 ppg • If the well is shut in on a gas kick SICP is generally greater that a saltwater kick of equal volume Where: SICP = FP = HP = Pf = shut-in casing pressure formation pressure hydrostatic pressure from top of kick to surface pressure of the kick fluid Oil and Gas Technology Program

Example: TVD = 13, 750 ft Circulating fluid weight of 12. 0 ppg Annular

Example: TVD = 13, 750 ft Circulating fluid weight of 12. 0 ppg Annular volume = 0. 0459 bbl/ft Formation pressure = 9, 180 psi A 30 bbl kick occurs with gas having weight of 2. 15 ppg Pressure gradient of circulating fluid Fluid rise from kick Hydrostatic pressure of remaining fluid Pressure gradient of kick fluid Hydrostatic pressure of kick fluid Oil and Gas Technology Program

Difference between gas and saltwater kicks • As gas rises to surface it must

Difference between gas and saltwater kicks • As gas rises to surface it must expand as pressure decreases – SICP increases – Pit level increases • Saltwater does not expand as it comes to the surface – No appreciable pit level or SICP increase Oil and Gas Technology Program

Density estimate for kick fluids Where: Di FW SICP SITP L Oil and Gas

Density estimate for kick fluids Where: Di FW SICP SITP L Oil and Gas Technology Program = = = density of influx, ppg original fluid weight, ppg shut-in casing pressure, psi shut-in tubing pressure, psi height of influx in the annulus, ft

Example: Circulating fluid weight = 9. 6 ppg SITP = 400 psi, SICP =

Example: Circulating fluid weight = 9. 6 ppg SITP = 400 psi, SICP = 700 psi Pit gain is 15 bbl (volume of the kick) Annular volume = 0. 0231 bbl/ft Fluid rise from kick Fluid weight after influx Density of kick fluid Oil and Gas Technology Program

SITP = 400 psi SICP = 700 psi 9. 6 ppg 8. 89 ppg

SITP = 400 psi SICP = 700 psi 9. 6 ppg 8. 89 ppg 649 ft Oil and Gas Technology Program 0. 71 ppg