COMPLICATIONS DURING DRILLING OPERATIONS. When complications arise during any activity, experience and common sense will usually solve the problem. Once the problem is identified, various solutions may be tried until it is solved. It is imperative to keep good records, Without records of what trend is developing or the sequence of events, many complications cannot be easily solved.


Shut-in pressures are not normally considered a complication. However, complications can result if the shut-in pressure values are essential to minimize potential problems during well kill activities. Once a well is shut-in, write down the time of kicks and record pressures every minute until they begin to stabilize. Factors such as formation characteristics, pressure, depth, fluid type and influx type all affect the time it takes for the wellbore to reach equilibrium and pressures to stabilize. This is why a set timeframe for pressures to stabilize is impossible to predict.

From the recorded pressures, kill weight fluid is calculated. Also, the annular pressure is held constant while bringing the pump up to the speed to kill the well. If the recorded pressures are too high, an excessively weighted kill fluid may be mixed, and while bringing pump online, excessive pressure could be held. These complications could result in lost circulation problems. If recorded pressures are toow low, the kill fluid may not be adequately weighted and insufficient


circulating pressures may be maintained, thus allowing additional influx. As mentioned earlier, the assumption is that shut-in pressures are correct. If proper shut-in procedures are used and recording begins immediately, determination of correct pressures is usually an easy task. however, if shut-in pressure is thought to be too high, a small amount of pressure should be bled from the choke, and the corresponding changes monitored closely. Several small bleed-offs may be required to confirm correct pressures. It should be remembered that if the original pressure were correct, additional influx could enter the well, resulting in a slightly higher casing pressure.

Shut-in drillpipe pressure (SIDPP) is generally lower than shut-in casing pressure (SICP) because the kick density is usually much lighter than the fluid in use. If the influx is liquid and has a higher density than the fluid in use, SIDPP will be higher than SICP. This is common in some remedial operations. Other causes include trapped pump pressure, blockages, quick setting gels and gas entering the string. If the fluid in the string is not uniform, such as when gas migrates into it, SIDPP will not be correct. By circulating slowly with the Driller’s Method and pumping several barrels (m³) to ensure the string is displaced with good fluid, the well may be shut in again and the SIDPP established.


Floats, check valves or BPVs are commonly used in the string. They are used for pressure work, directional drilling, MWD/LWD tools and preventing the annulus from U-tubing. Company policy and field experience will dictate the use of floats in different intervals of the hole. A float has the effect of either making the shut-in drillpipe pressure read zero or reading some unreliable intermediate value. To obtain a correct shut-in drillpipe pressure, the string must be pressured until the float opens. There are several ways to do this, depending on the pump drive system.

  • Pressure the pipe up in small increments, kicking or rocking pump in and out. Pressure in the string will increase with each increment. The pressure increases as pump is kicked in, then breaks back when pump is kicked out. Pressure to which it drops is SIDPP value.
  •  Slowly pressure up the string. It is best to use a high pressure/low volume type of pump, similar to a cementing pump. Closely monitor the pressure gauge indicator needle. A small dip may be noticed when the BPV opens. This point will be the SIDPP value. Pressure inside the string equalizes with well pressure outside.
  • Another method, if kill rate pressures were taken recently and are accurate, is to open the choke, bring the pump up to the desired speed, then adjust casing pressure back to the value it had before you started the pump. When standpipe or tubing pressure stabilizes, subtract the kill rate pressure value from it. This is the SIDPP. When using this technique, use the slowest rate to avoid adding extra circulating friction, which results in a SIDPP higher than what it should be.


If casing pressure reaches a point where it could exceed burst pressure, shutting down or slowing down the pumps may be required. If shut-in pressure continues to rise, take action immediately. Bleeding off pressure may not be enough and may be courting disaster. Analyze the situation by using all information available. Reach a conclusion based on facts, not guesswork, and take proper action. If circulation is being lost, the situation may call for lost circulation material. Has a new zone been penetrated or perforated which might have an abnormally high pressure? Could shallow sands up the hole have been charged up earlier in the life of the well and now be coming in through corroded or damaged casing? Analyze and eliminate false assumptions. Don’t rule out or overlook the unusual. Don’t hesitate to call for help. Slowly pumping heavier fluid, shutting down and bleeding off, and then pumping again may be the answer.

Maximum casing pressure can be based on the pressure required to break down the formation, casing burst or BOP stack pressure limitations. If a maximum allowable pressure is posted on the rig, the reason for the limitation should be posted also. In general:

  • Maximum allowable surface pressure may depend on casing burst.
  • Maximum allowable surface pressure may depend on BOP stack rating.
  • Lost circulation is usually the safety valve for for high  pressure and will occur before the mechanical limitations are reached.


A hole or washout developing during well control activities is rare. It may also be difficult to detect a small hole that develops in the string while circulating other than increases in fluid density out of the well earlier than planned or perhaps a quicker response time for the transit of pressure changes on the choke. If the string remains static (no pipe movement)it is


unlikely that a hole would develop at a lower pressure than typical circulating pressures. However, the hole may enlarge or the string fail from stresses created by movement of pipe and/or rotation. Generally, a hole in the string will cause a decrease in circulating pressure. During well control conditions the choke operator will typically respond by adjusting the choke to compensate for the decrease in pressure and create higher than required pressure in the annulus. This may lead to more complications. Chances of detecting a hole in the string increase if the hole is large and occurs suddenly.

Likewise, under normal circumstances, if a washout is suspected, a marker (paint, dye, etc.) is pumped and returns monitored. From strokes or volume pumped when the marker surfaces, estimations can be made as to its location. Caution should be used if additives such as nut plug or soft line are used to detect the washout. Under slower circulation rates they may plug the jet nozzles.

The position of the washout may dictate what actions will follow. Actions should be taken to prevent the washout from enlarging. In a well control activity, maintaining bottom hole pressure (BHP) is paramount. Maintaining circulating pressure according to plans may increase or decrease pressures in the annulus, depending on where the washout is located and its severity. Perhaps the best course of immediate action is to shut the well back in and monitor pressure. If the shut in pressures (on string and choke) are essentially the same, the washout is above the influx. When the shut in pressure on the string is lower than pressure on the choke, the washout is below the influx.

Circulating to kill the well is a judgement call. If washout is below influx, an attempt may be made to circulate and kill the well. Even so, periodically the well should be shut in and new pump pressures established if washout worsens, or existing pump pressure validated if it does not.


Casing is the main defense against undesired fluid migration from one zone to another. Casing protects the formation from well pressures and the wellbore from formation pressure. This allows us to drill deeper with higher mud weights. It supports the walls of the well and prevents contamination from other zones. Casing also serves as a barrier to protect fresh water zones from the wellbore.

Sometimes holes in the casing appear opposite formations bearing corrosive fluids.  Damage and wear in the casing can occur from extended pipe rotation and from running tools. Leaks can start where joints were improperly stabbed, doped or made up. Casing may collapse, or formation movement may shear it. Under well control conditions, a hole in the casing may be difficult to identify because the symptoms are similar to that of lost circulation. The solutions listed under lost circulation should be investigated while attempting to identify the complication.

Now, I’d like to tell you about pressure between two casing strings, there are many causes why pressure can exist between two casing strings.


Some of these reasons are the result of poor cement bonds, corrosion, wear, liner hanger packer failure and thermal effects on tubulars and packers fluids. These reasons why pressure exists between strings must be identified before proceeding with the planned activity. Regulations may require that the problem be rectified before continuing operations if the cause of pressure is communication between zones.

If pressure is trapped between strings, it may not be as much of a problem as communication between zones. However, it should be treated seriously if casing to casing annulus valve is opened prior to nippling down BOP’s or when setting a new string of casing. Always open this valve carefully. Always assume the pressure is trapped, even if a gauge is installed and is not registering pressure.


Often the first sign of lost returns during a kill is fluctuation of gauge pressure and/or a fluid level drop in the pits. If well will circulate, but pit level is dropping because of partial lost returns, several techniques may be tried.  No pressure safety margin should be held if lost returns are suspected.


If the fluid volume can be maintained by mixing, continue. Pressure on the thief zone is reduced after the kick is circulated above it, so the problem may solve itself. Choose a slower circulating rate and establish a new circulating pressure. The   slower pumping rate will reduce frictional ressure losses occurring in the annulus. With the well shut in, the procedure to establish a new circulating pressure is essentially the same as bringing the pump on line.

  1.  Open the choke.
  2. Bring pump up to the new slower rate.
  3. Adjust the choke until casing pressure is the same as when shut in. Pressure on the drillpipe or the tubing gauge is the new The calculating pressure.

If the well is still being circulated:

  •  Slow pump down to reduced rate.
  •  While pump rate is being reduced, maintain casing pressure at present value.
  •  When at desired rate while maintaining casing pressure, the pressure on the drillpipe or tubing gauge is the new circulating pressure.


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