DYNAMIC PRESSURE REGIME WHEN CIRCULATING 01. Circulation of Drilling Fluid

Whilst drilling the drilling fluid is continuously circulated to clean out the rock fragments (cuttings) from underneath the bit whilst removing them up to the surface where they are separated from the drilling fluid by the mud cleaning equipment.

To establish the circulation in the system it is required to have a dynamic fluid differential pressure between certain areas in the system. This pressure difference represents a certain energy that is used to overcome the resistance against fluid movement, resistance that is existing in the system.

This resistance against fluid flow or friction as it is generally called in a hydraulic system is largely dependent upon:

• The fluids' rheology (viscosity, density etc.)

• The fluids' velocity

• Type of flow regime ( laminar or turbulent)

If a fluid is pumped through an enclosed pipe system with a constant velocity the resistance in the system depends on the flow area. Where the fluid flow meets diameter reductions, a local increase in velocity is the result and therefore a greater friction. Conversely where the flow meets a larger diameter the velocity will decrease and the friction will consequently also decrease.

Fig 19

Fig.19 shows a circulating fluid system where the initial pressure at the pump is 1400 psi and the final pressure is 0 psi at the flow line. It is seen that the 1400 psi represents the energy required to overcome the friction that is present against the flow of the fluid in the system. Large obstructions to flow give large pressure losses. By means of pressure gauges placed in the system the pressure losses in the different parts of the system can be monitored.

Applying these considerations to the circulation of drilling fluid the Fig. 20 shows a pipe system in which the drilling fluid pump (mud pump) shall pump drilling fluid through. This simplified pipe system consists of drill pipe, drill collars, bit nozzles and annulus. The drilling

1400 1320 1280 1220 1170 800 0

80 40 60 50 370 800

Recorded Pressure (psi)

Pressure loss (psi)

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fluid enters the top of the drill string with a pressure of 2200 psi. On the way down through the string some of this pressure is lost depending on:

• The dimensions of the drill pipe (Internal diameter)

• The characteristics of the drilling fluid.

Fig 20

P¹ = Pressure as drilling fluids enters the drill pipe (2200 psi) P2 = Pressure as drilling fluid enters the drill collars (1900 psi) P³ = Pressure as drilling fluid enters the bit nozzles (1700 psi) P⁴ = Pressure as drilling fluids enters annulus (130 psi) P5 = Pressure as drilling fluid enters the flow line ( 0 psi)

The largest pressure loss in the well system takes place when fluid flows through the bit nozzles that have a relatively small flow-through area.

On the way towards the surface through the annulus, the pressure loss will be the lowest in the system, because the friction is not at all large on account of the large cross-sectional area of the annulus.

The pressure figures used in Fig. 20 are based on average calculations for a simple rotary assembly, and they show that 94% of the total pressure loss occurs in the drill string and bit nozzles.

The figures show that to circulate the drilling fluid from the bottom of the well up to the surface it is only necessary to use approximately 6% of the total pump pressure. This dynamic pressure will be transmitted to the bottom hole pressure.

When the pump is running and circulation takes place there will be a higher bottom hole pressure than when the pump is stopped.

With the pumps stopped only hydrostatic pressure is present in the well to balance the formation pressure.

NATIONAL DRILL PIPE

DRILL COLLARS

ANNULUS

BIT P1

P2

P3

P4

P5

PSI

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02.03 Dynamic pressure in the wellbore (Circulating Pressure) Dynamic Pressure (PC) is dependent on three factors:

• Components in the flow system

(Flow area, length of drill string, nozzles size etc)

• The fluid characteristics (Rheology)

• The flow rate

(SPM, liner size, pump efficiency etc)

Change in drilling fluid characteristics (such as viscosity and gel-strength) can change the friction against flow in a system.

A fluid's flow resistance is largely depending on the drilling fluid density. In well control calculations it is accepted that dynamic pressure loss is proportionally depending on drilling fluid density.

PC1 = Circulation pressure when drilling fluid density is MW1

PC2 = Circulation pressure when drilling fluid density is MW2

The expression for the relationship between circulation pressure and drilling fluid density has proved to be realistic in most practical cases. See fig. 21.

Example:

At 100 SPM the pump pressure is 1000 psi with a drilling fluid density of 10 ppg.

What would the pump pressure be at 100 SPM if the drilling fluid density was increased to 12 ppg?

New pump pressure:

To calculate the new pump pressure

[psi]

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it is required to know the original pump pressure, which is read just after the pump ( standpipe pressure ).

The third factor that affects the circulation pressure is the speed of the flow of drilling fluid.

This velocity of flow is directly related on the pump speed ( SPM = strokes per minute).

The relationship between pump speed and dynamic pressure can be expressed as:

Where SPM is the number of strokes per minute in the two cases.

Example:

Circulation pressure is 1200 psi with 40 SPM.

What will the circulation pressure be if the pump speed was increased to 80 SPM?

Answer:

It is realised that if the pump speed is increased to twice its original value the dynamic pressure will be increased almost fourfold. The graph in Fig. 22 illustrates this fact.

The power 1.86 is an experience figure, which is obtained from experiments. However in well control calculations it is generally accepted to use the power 2 in stead of 1.86.

For well control calculations use the formula below:

Fig 22

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Fig. 23 shows circulation pressures and pressure losses between the drill string and annulus with three different pump rates.

Fig 23

1000 2000 3000 4000

Pc

80 spm

60 spm

40 spm

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04 CONSIDERATIONS WITH A CLOSED-IN WELL