The following procedures are regarded as noncirculating procedures because, even though a pump is used, there is not a full circulating path for the fluids—that is, fluid is not pumped completely down the tubing and back up the annulus or vice versa. These procedures include the bullheading method, the constant tubing pressure method, the volumetric method, and the two types of the lubricate-and- bleed method.
Bullheading
Bullheading is a means of killing a producing well in which produced fluids are
pumped back into the producing formation and the tubing is filled with kill fluid at the same time (Fig. 3-16). It is not a constant bottomhole pressure method; the crew intentionally exceeds the injectivity limits of the formation while making every effort not to exceed the fracture limits. It is the simplest of the well kills and probably the most common worldwide for workover procedures.
Prior to performing a bullheading operation, several factors should be considered: • Formation pressure. The best source for this information is a recent bottomhole
pressure (BHP) survey.
• Condition of the perforations (perfs).
• If the perfs are blocked and will not readily accept fluid, unacceptably high pressures can be created at the perfs, leading to possible formation or cement failure.
• The presence of sand or junk in the system may plug or block perfs, preventing the fluid from even reaching them.
• Nearby zones that have previously been cement “squeezed” may impose pressure limitations on the current operation. Every effort should be made to obtain formation fracture information, permeability data, and historical data from the well regarding previous workovers (see “Planning and
Preparation” on page 8-2).
• The condition of the tubulars, both tubing and casing. Tubing-to-annulus communication indicates leak paths. You should also review previous workover
data to identify any de-rating of the casing or tubing pressure limits due to wear or damage.
• The condition and working pressure of the wellhead.
• The presence or absence of in-situ annular fluid, called packer fluid, which reacts against applied internal tubing pressure. The hydrostatic pressure of the annular fluid (called “backup”) has a great impact on tubing burst. For more information on in-situ packer fluids, see “Types of Workover and Completion Fluids” on page 5-2.
• Formation compatibility with kill fluid (unless the zone is to be abandoned).
Figure 3-16 Bullheading
Pre-recorded Data Required for Bullheading
• Desired overbalance, provided by kill fluid • Perforation depth, measured and vertical
• Fracture pressure—estimate of the formation fracture strength
• Tubing specifics: ID, length, end of tubing (EOT), burst pressure rating, percent wear, tubing condition
• Annular fluid backup—the presence or absence of fluid in the annulus and its density
• Rathole: ID and measured length
• Pump size—liner, stroke, and efficiency data or actual output from test • Surface pressures: SITP, SICP, and pressure on casing strings (if any) • Wellhead working pressure
Bullheading Calculations
Complete the following calculations in preparation for the bullheading procedure (see “Bullheading Scenario” on page 3-32).
• Volume To Pump. This includes both the tubing volume and the annular space below the packer (if any exists).
• Kill Weight Fluid. The density is based on the formation pressure of the zone to be killed. Density is generally calculated to include a 100–300 psi overbalance safety margin (see Fig. 2-14.)
• Fracture Pressure. Formation fracture pressure is used to determine surface pressure limits throughout the operation.
• Working Tubing Burst. Standard practice is to downgrade to 80% of the
published tubing burst pressure. If corrosion or wear is known to be greater than 20% of the tubing wall thickness, use a lower number. A caliper survey is used to determine this.
• Maximum Tubing Pressure (mechanical limits). These calculations consider the tubing burst rating and total hydrostatic pressure in the tubing prior to the operation and when the operation is completed, both with and without the presence of backup fluid in the annulus. The equations to calculate these limits are shown below.
• Maximum Tubing Pressure (formation limits). Limiting this parameter protects the formation, initially with light fluid in the string and finally with kill fluid in the string. The equations to calculate these limits are shown below.
The calculations for either maximum tubing pressure (mechanical limits) or maximum tubing pressure (formation limits) can be the limiting factor on bullheading pressure. The pressure schedule in Fig. 3-17 illustrates both the
Maximum Initial Tubing Pressure (no backup)
= Working Burst Pressure - (Tubing Hydrostatic Pressure) = Working Burst Pressure - (Formation Pressure - SITP) Maximum Final Tubing Pressure (no backup)
= Working Burst Pressure - Kill Fluid Hydrostatic Pressure Maximum Initial Tubing Pressure (with backup)
= (Working Burst Pressure - Formation Pressure) + Backup Hydrostatic Pressure
Maximum Final Tubing Pressure (with backup)
= (Working Burst Pressure - Kill fluid Hydrostatic Pressure) + Backup Hydrostatic Pressure
Maximum Tubing Pressure (Formation Limits)
= [Formation Fracture Strength (ppg) - Initial Fluid Weight in Tubing*] × Formation TVD × 0.052
= [Formation Fracture Strength (ppg) - Final Fluid Weight in Tubing **] × Formation TVD × 0.052
* before bullheading; formation fluid in tubing ** after bullheading; kill fluid in tubing
mechanical and fracture limits on tubing pressure plotted against strokes or barrels as the tubing is displaced with kill fluid. Carefully review the bullheading scenario in the following section to enhance your understanding.
Figure 3-17 Bullheading pressure profile
Bullheading Scenario
This scenario uses actual well data to illustrate the required calculations and graph plotting required in preparation for bullheading.
Well Information
• Depth of formation/perfs: 10,170 ft • Formation pressure equiv.: 8.8 ppg • Formation frac equivalent: 13.8 ppg
• Tubing 4 1/2", N80 Vam: 0.01521 bbl/ft to 10,170 ft • Rathole: 6.538" ID, Length = 80 ft
• Shut-in tubing pressure: 3,640 psi • Gas gradient: 0.1 psi/ft (1.9 ppg) • Kill fluid overbalance: 150 psi
• Measured pump output = 0.058 bbl/stk • Fluid backup: assume none
Calculations for Bullheading Pressure Schedule
1 Calculate kill weight fluid.
Kill Weight Fluid = 8.8 + (150 ÷ 10170 ÷ 0.052) = 9.1 ppg
2 Calculate the maximum tubing pressure (formation limits).
Initial limit (tubing full of gas) = (13.8 - 1.9) × 10,170 × 0.052 = 6,293 psi Final limit (tubing full of kill fluid) = (13.8 - 9.1) × 10,170 × 0.052 = 2,486 psi
3 Calculate the working tubing burst limit. Working limit = 0.8 × 8,430 = 6,744 psi
4 Calculate Maximum Initial and Final Tubing Pressure (mechanical limits, no backup).
Maximum Initial Tubing Pressure =
[6744 - (8.8 × 10,170 × 0.052)] + 3,640 = 5,730 psi Maximum Final Tubing Pressure =
6,744 - (9.1 × 10,170 × 0.052) = 1,932 psi
5 Calculate bullhead volume/pump strokes. Tubing: 10,170 × 0.01521 bbl/ft = 154.69 bbl Rathole: 80 × (6.5382 ÷ 1029.4) = 3.32 bbl Total bbl = 158.01 = 158 bbl
Total strokes = 158 ÷ 0.058 = 2,724 strokes
6 Plot SITP, Maximum Tubing Pressure Formation Limits (called the frac line), Maximum Tubing Pressure Mechanical Limits on Y axis against strokes on X axis (Fig. 3-18).
Figure 3-18 Bullheading pressure schedule
Note that in this example, the upper limit on tubing, or pump, pressure is controlled by tubing burst (the line between 5,730 and 1,932 psi). The frac line is not the limiting case. Remember, the conservative assumption was made that there is no hydrostatic backup fluid behind the tubing. In an older well or a well with no available information, this would be an appropriate assumption. It has the effect of lowering the maximum pump pressure allowed. If it is known that backup fluid does exist and its density is known, the calculations change and the graph will take on a different shape, with the upper limit being the frac line.
Bullheading Procedure for Scenario
After the schedule is constructed, it is used as a tool to monitor and limit the pumping pressure. One important note: bullheading does not have a return fluid path. Therefore there is no place to put a choke, so a choke cannot be used to control pressure. The one tool available is pump speed. Pump speed is adjusted to stay inside the safe pumping range on the graph.
It is helpful to plot observed pump pressure directly on the graph as the kill fluid is being pumped (see the green line in Fig. 3-19). The plotted points show a visual
trend line that indicates when the limit line is being approached. The pump speed can be reduced before the plotted pump pressure line reaches the limit line, thus avoiding exceeding the pressure limit.
Figure 3-19 Plotted bullheading pressure schedule
Bullheading Considerations
When using bullheading to kill a well, make sure you consider the following: • Hold a pre-job meeting to discuss operational and safety concerns. Conduct risk
analysis and hazards analysis.
• Install a tested safety valve in the work string and connect the pump in line to the safety valve.
• Protect all pressurized parts of the system by relief valves that have been tested before the job begins.
• Make sure that the fluid to be used to bullhead is compatible with the formation and as solids free as possible to prevent pore throat blockage.
• Clearly mark pressurized lines and properly secure them. Brief personnel on the location of these lines and instruct them to stay clear while bullheading is in progress.
• Be prepared for the well kill to require several attempts. Pressure may not remain at zero even though a precalculated amount has been pumped. Additional fluid volume should be available on location.
• Measure and record the amount of fluid pumped.
• If using brines as kill fluid, use the agitators in the rig tanks to stir the fluid often. This mixing assists in keeping the salt in solution, thus maintaining density. The same would be true if using mud (e.g., for a zone to be abandoned). Agitation keeps the barite in suspension.
• If initial casing pressure is extremely high, it may be wise to bullhead the annulus first or consider simultaneously bullheading the tubing and the annulus.
Casing Pressure Increase
Whenever bullheading is performed in a completion with a packer in place, the WSS must pay attention to the casing pressure reading and must ensure that the crew fully understands the importance of reporting this immediately. Increases in casing pressure could be due to thermal expansion caused by pumping liquids down the tubing or by holes in tubing, leaking tools, sliding sleeves, gas-lift valves, safety valves, and packer seals. The presence of, or an increase in, casing pressure can have dire consequences. Excess pressure applied to the top cross-sectional area of the packer creates a great deal of force—enough to force the packer down the hole and part the tubing (see Fig. 3-20). Additionally, the excess pressure in the annulus creates a situation in which the casing burst pressure limit can be reached or exceeded, not necessarily at the surface but downhole. Should casing pressure appear or increase, try to bleed the pressure to its previous value and monitor it closely. Casing pressure that continues to increase and will not bleed down is cause for concern, and the operation should be halted until the source of the increase is determined and the situation remedied. For more information, see “Unexpected Changes in Gauge Readings” on page 7-22.
Figure 3-20 Casing pressure increase during bullheading
Gas Channeling
Gas channeling can occur during a bullheading operation in gas wells or oil wells with a high gas-oil ratio (GOR), especially if the kill fluid lacks sufficient viscosity and the pump rate is slow. In that case, gas may channel up the tubing faster than it is being forced down the tubing through pumping (Fig. 3-21). Generally, after pumping the calculated volume and shutting down the pumps, the tubing pressure is 0 psi and the well is dead. There are times, however, when SITP drops to 0 psi and the well appears to be dead, but after 30 minutes or so, the SITP starts to increase. This increase often indicates gas channeling. It is particularly troublesome in highly deviated wells. One known remedy to this situation is to pump a viscous pill such as XC polymer ahead of the kill fluid to minimize the gas channeling. As always when
considering the use of any fluid, take into account the fluid’s compatibility with the production zone.
Figure 3-21 Gas channeling
Cold Bullheading
“Cold bullheading” is a term used to describe bullheading when the kill fluid is at a lower temperature than the wellbore. The temperature difference generates thermal stresses that would normally result in shortening the tubing. But since the tubing is locked into the completion and its length cannot change, an upward tensile force is created in the tubing, which pulls upward on the packer and creates a force that may unseat it. Using computer software, you can determine the magnitude of this force and apply a balancing force downward on the packer by pressuring the annulus to the amount calculated by the computer program.