Bottom Hole Pressure Concept


Pressure Losses

When pumping the drilling fluids (Click here) through the circulating system, high level of pressure is lost. Actually, the pressure on the mud pump indicates the amount of the friction which has to be overcome to circulate the drilling fluids. A large amount of pressure losses is faced when passing into the drill string and through restrictions such as the bit nozzles. Pressure losses increase also when using the choke to generate a backup pressure when killing the well. When the fluids are circulated, the bottom hole pressure is increased by the amount of the frictions generated in the annulus and it is hold at the hydrostatic pressure when the mud pump are shut off. The equivalent circulating density is increased due the friction generated at the well bore. If the well is balanced by the ECD, it could flow when the mud pumps are off.

Bottom Hole Pressure

The bottom hole pressure is the pressure acting on the walls of the hole. In large diameters, this pressure has limited impacts on the wellbore, but in the case of smaller diameters, it can generate hole problems such total circulating loss. 

When the well is static, the bottom hole pressure can equal to the hydrostatic pressure generated by the column of the drilling fluids. During circulation, the bottom hole pressure equals to the sum of hydrostatic pressure and frictions generated through the circulating system. In the case of using a rotating head, such as when drilling with MPD system, the bottom hole pressure is the sum of the hydrostatic pressure, annulus pressure losses and the surface backup pressure. Similarly to the case of MPD, in the case of well control when using the choke, the bottom hole pressure is estimated to be equal to sum of hydrostatic pressure, annulus pressures losses and the backup pressure hold by the choke. 

Fig 01- Circulating System (Click Here)


Surge and Swab

The pressure acting on the wellbore is affected by the drill string movement upwards or downwards. The swab pressure is created when tripping out of the hole. It occurs when the fluids cannot drop below the string as fast as the pipe upward movement. This gap of fluid movement below the string generates a suction force leading to a bottom hole pressure decrease and allowing the formation fluids to flow into the well. When running the drill string in the hole too fast, surge pressure is created because of the limited compressibility of the drilling fluids. Excessive surge pressure can lead to partial or total circulation loss (Click Here).

The surge and swab pressures are affected by the pipe movement speed, clearness between drill string and hole and also fluid properties.

Fig 02- Swabbing and Surging

The trip margin is an increase in the drilling fluids density to compensate the bottom hole pressure decrease in the case of losing the circulating pressure or when the swab pressure is created when pulling the drill string. The trip margin has to be estimated accurately. Too large safety margin can cause loss of circulation and too small can allow the well to kick (Click Here).

The differential pressure between the bottom hole pressure and the formation pressure can take three situations, overbalance, underbalance and balanced. Overbalance when the bottom hole pressure is greater than the formation pressure, underbalance when the formation pressure is greater than the bottom hole pressure. At balanced is when the formation pressure and the bottom hole pressure are equals. 

Fig 03- Hole Pressure vs Formation Pressure


It should be mentioned that the bottom hole pressure can be converted to an equivalent mud weight EMW or Equivalent circulating density ECD, and it is calculated as follows:



Formation Tests

Testing the formation is very important which can give very valuable information for the current operations and the future planned projects. Casing depth, well control solutions and drilling fluids densities are based on the data recovered from these tests. In order to evaluate the strength of the formation, leak off test or formation integrity testes can be performed. There are some rules which have to be guaranteed before carrying these tests. The fluids in the well should be in homogeneous state and this can be reached by circulating the well for at least one cycle. The pumped rate should be at the lowest rate and the trend of the pressure should be closely monitored to avoid damaging the tested zone.

The leak off test is performed to determine the maximum pressure or drilling fluid density at which the formation can get to the fracturing point. The formation integrity test, the well is pressurized to a pre-determined pressure, and it is generally performed in developed fields. As a simple procedure, the test is performed as follows:

- Make sure that last casing column is not leaking
- Circulate and condition the drilling fluids in the well bore
- Pull out the drill bit to the last casing shoe
- Check and test the pumping lines
- Close the annular BOP
- Start the test by pumping through the drill string or the annulus with lowest pumping rate.
- Stop the test once the pressure starts to deviate. The point where the pressure deviates is considered as the leak off test pressure.

Fig 04- Simple Sketch for the Leak-Off Test


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