Oil-Field Hydraulics Chapter 8 Shut-in Procedures PTRT 1321 Oil-Field Hydraulics Chapter 8 Shut-in Procedures

Introduction Serve several purposes A few abbreviations 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

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

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

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

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

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

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

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

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

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 = shut-in casing pressure FP = formation pressure HP = hydrostatic pressure from top of kick to surface Pf = pressure of the kick fluid

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 Example: Pressure gradient of circulating fluid Fluid rise from kick Hydrostatic pressure of remaining fluid Pressure gradient of kick fluid Hydrostatic pressure of kick fluid

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

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

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 Example: Fluid rise from kick Fluid weight after influx Density of kick fluid

SITP = 400 psi SICP = 700 psi 9.6 ppg 8.89 ppg 649 ft 0.71 ppg