Sector Pecuario

Figure 1.19

In subsea situations, a pressure loss exists when

circulating through the choke due to the friction losses in the extended choke line running up from the BOP. This pressure loss is not accounted for in normal Slow Circulating Rate (SCR) measurements, which are taken while circulating up the marine riser (see Fig 1.19). If the normal method of bringing pumps to kill speed is followed (that is, choke manifold pressure maintained equal to SICP until kill rate is achieved), bottom hole pressure will be increased by an amount equal to this choke line friction loss (CLFL). This excess pressure can result in serious lost circulation problems during the kill operations.

Since fracture gradients generally decrease with increased water depth, correct handling of the CLFL becomes more critical as water depth increases. Beyond approximately 500 feet water depth, it should always be considered while planning well control operations.

Figure 1.20

It is possible to measure CLFL while taking SCR’s. One simple way to do this is to pump down the choke line at reduced pump rates (taking returns up the open marine riser as is shown in Figure 1.20) and record the pressure reading on the choke manifold gauge.

It is fundamental to all standard methods of well control to maintain constant bottom hole pressure (BHP) throughout kill operations. To accomplish this a method must be used to keep total applied casing pressures relatively constant while

bringing the mud pump to kill rate.

In the absence of significant CLFL (surface stacks or shallow water), the method used is to merely keep choke manifold pressure equal to SICP until the pump is up to speed.

But when CLFL exists, total applied casing pressure varies from SICP at pump start-up to SICP + CLFL with the pump at kill rate, if the above method were used. This would cause bottom hole pressure to increase by an amount equal to CLFL, as shown in Figures 1.21 and 1.22

Figure 1.21 Figure 1.22

800 PSI

Pf = 6000 psi

Ph = 5200 psi (in annulus) PUMPS OFF (kick shut in) 1000

PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 0 PSI (STATIC) APL 0 PSI BHP 6000 PSI 1500 PSI Pf = 6000 psi

Ph = 5200 psi (in annulus)

PUMP AT KILL RATE HOLDING CONSTANT CHOKE MANIFOLD PRESSURE

CHANGE IN BHP = 200 psi increase 1000

PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 200 PSI (DYNAMIC) APL NEGLIGIBLE BHP 6200 PSI RETURNS

Figure 1.23

To eliminate this problem, two methods exist. First, by reducing choke manifold pressure by an amount equal to a known CLFL (adjusting choke manifold pressure to SICP -CLFL), the effect of the CLFL is negated. This is accomplished by reducing the original SICP by the amount of CLFL while bringing the pumps to speed (see Figure 1.23). Once kill rate pressure has been established, the choke operator switches over to the drill pipe gauge and follows the drill pipe pressure graph in the usual way.

Or secondly, given a choke manifold configuration with separate pressure gauges for choke and kill lines, it is possible to utilise the kill line (shut off down-stream of the gauge outlet to prevent flow, thus eliminating friction) as a pressure connection to a point upstream of any potential CLFL (known or unknown). This is shown in Figure 1.24. If the kill line gauge in this instance is kept constant while bringing the pump to speed, the effect of CLFL is eliminated.

Figure 1.24

Note the advantages of the second method: 1. The gauge reading choke manifold

pressure will show a decrease after pump is up to speed. The amount of this

decrease is equal to the CLFL.

2. No precalculated or pre-measured CLFL information is required.

3. The kill line gauge can be subsequently used like the choke manifold pressure gauge on a surface stack for the purposes of altering pump rates or problem

analysis.

NOTE: If the second method of handling the CLFL situation is preferred, it would be advisable to rig a remote kill line pressure gauge which could be seen by the choke operator.

Well shut in

1300 PSI

Pf = 6000 psi

Ph = 5200 psi (in annulus)

PUMP AT KILL RATE WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

800 PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 200 PSI (DYNAMIC) APL NEGLIGIBLE BHP 6000 PSI RETURNS 1300 PSI Pf = 6000 psi

Ph = 5200 psi (in annulus)

PUMP AT KILL RATE HOLDING CONSTANT KILL LINE PRESSURE READING CHANGE IN BHP = 0 psi increase

800 PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 200 PSI (DYNAMIC) APL NEGLIGIBLE BHP 6000 PSI RETURNS KLFL 0 PSI (STATIC) 1000 PSI

575 PSI

Pf = 5200 psi

Ph = 5100 psi (in annulus) PUMP AT 4 BBL/MIN HOLDING 0 PSI CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 100 psi increase

0 PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 200 PSI (DYNAMIC) APL NEGLIGIBLE BHP 5300 PSI RETURNS

It is extremely important to note that regardless of which Figure 1.25 method is used, they both accomplish the goal of

maintaining constant bottom hole pressure equal to formation pressure, just as would be the case were CLFL absent. This is done without the need to alter any

calculations on the kick sheet. Thus initial and final

circulating pressures, which are read on the drill pipe gauge, are unaffected by CLFL. CLFL is recorded on the Kick Sheet for convenience only – it is not used in kick sheet

calculations.

Several additional points should be made about CLFL. It should be noted that it will only be possible to use the above recommended methods when SICP is greater than CLFL. If this is not true, it will be unavoidable to apply excess pressure to the bottom of the hole using standard well control procedures. Also, as kill mud comes up the annulus, total applied casing pressure needed to maintain constant bottom hole pressure will eventually drop below CLFL. After this point, drill pipe pressures will exceed planned Final Circulating Pressure in spite of having the choke wide open with no choke manifold back pressure.

Figure 1.26

These situations can be mitigated by use of unusually slow pumping rates or by taking returns up choke and kill lines simultaneously. Figures 1.25 - 1.28 illustrate this problem and methods of dealing with it. They show an example in

which a static SICP of 100 psi is reduced while pumping as a

result of the increase in back pressure created in circulating up the choke line, by itself or choke and kill lines together.

Fig 24: Pumping 4 bbl/min with choke wide open. Note increase in BHP due to excess CL friction.

75 PSI

Pf = 5200 psi

Ph = 5100 psi (in annulus) PUMPS OFF (kick shut in) FCP @ 4 bbl/min = 400 psi FCP @ 2 bbl/min = 200 psi CLFL @ 4 bbl/min = 200 psi CLFL @ 2 bbl/min = 60 psi 100 PSI CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 0 PSI (STATIC) APL 0 PSI BHP 5200 PSI

Fig 1.27: Pump rate reduced to Fig 1.28: By taking flow up choke and bbl/min. BHP is held constant kill lines simultaneously, the same effect at SICP - CLFL is achieved as in fig 1.27, but at a

pumping rate of 4 bbl/min.

Figure 1.27 Figure 1.28

475 PSI

Pf = 5200 psi

Ph = 5100 psi (in annulus)

PUMP AT 4 BBL/MIN USING CHOKE AND KILL LINES FOR RETURN FLOW CHANGE IN BHP = 0 psi

40 PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 60 PSI (DYNAMIC) APL NEGLIGIBLE BHP 5200 PSI RETURNS KLFL 60 PSI (DYNAMIC) 40 PSI CHOKE RETURNS 2 BBL/MIN 2 BBL/MIN 4 BBL/MIN 275 PSI Pf = 5200 psi

Ph = 5100 psi (in annulus)

PUMP AT 2 BBL/MIN WITH REDUCED CHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

40 PSI

CHOKE DRILL PIPE CHOKE MANIFOLD

SUBSEA BOP CLFL 60 PSI (DYNAMIC) APL NEGLIGIBLE BHP 5200 PSI RETURNS

1.12 - WORKSHOP 1

SCORE

1. Convert the following mud densities into pressure gradients.

a. 13.5 ppg _____________ psi/ft

b. 16 ppg _____________ psi/ft

c. 12 ppg _____________ psi/ft 2

2. Convert the following gradients into mud densities.

a. 0.806 psi/ft _____________ ppg

b. 0.598 psi/ft _____________ ppg

c. 0.494 psi/ft _____________ ppg 2

3. Calculate the hydrostatic pressure for the following.

a. 9.5 ppg mud at 9000ft MD/8000 ft TVD =_____________ b. 15.5 ppg mud at 18000ft TVD/21000ft MD =_____________ c. 0.889 psi/ft mud at 11000ft MD/9000ft TVD =_____________ 2 4. Convert the following pressures into equivalent mud weights in PPG.

a. 3495 psi at 7000ft =_____________

b. at 4000ft with 2787 psi =_____________

c. 12000ft MD/10500ft TVD with 9000 psi =_____________ 2 5. High bottom hole temperatures could affect the hydrostatic pressure

gradients resulting in:

a. An increase in the hydrostatic gradient b. A decrease in the hydrostatic gradient

SCORE

6. Assuming a 10 ppg mud is being circulated at 700 GPM at a depth of 10000ft TVD/MD the circulating pump pressure is 3000 psi. If the circulating friction losses in the system are as follows:

Pressure losses through pipe/collars 1200 psi

Pressure loss across the bit jets 1600 psi

Pressure loss in the annulus 200 psi

a. When circulating what is the dynamic bottom hole pressure?

Answer... 2 b. What is the static bottom hole pressure?

Answer... 2 c. What is the equivalent circulating density ECD?

Answer... 2 d. If the pump speed is increased to give 800 GPM, what will

the pump pressure be?

Answer... 2 e. Will this increase in the pump speed have any effect on

bottom hole pressure?

Answer YES/NO 2

f. Referring to the data given above, if the mud weight being circulated at 700 GPM was 12 ppg rather than 10 ppg, what would pump pressure be?

Answer... 2 7. When circulating a 12 ppg mud at 10000ft ECD is 12.3 ppg. What

is the annular pressure loss?

SCORE

8. Calculate the pressure that one barrel of 12 ppg mud Wt exerts. a. Around the drill collars if the annular capacity is 0.03 bbls/ft.

Answer... 2 b. Around the drill pipe if the annular capacity is 0.05 bbls/ft.

Answer... 2 9. If the fluid level in a well bore fell by 480ft, what is the reduction

in bottom hole pressure if the mud weight is 12 ppg?

Answer... 2 10. If a 12 ppg mud over-balances the formation pressure by 240 psi

theoretically how far could the mud level fall before going under-balance?

Answer... 2 11. Drilling at 12700ft with an 8 1/2" bit, the drill pipe is 5" with 700ft

of 6 1/2" collars. The mud weight = 12 ppg. The yield point of the mud is 12lbs/100ft2. Use the equation given below to determine ECD.

Answer... 4 Annular-pressure loss = YP x L

————— 200(DH-DP)

where YP = Yield point of mud in lbs/100ft2 L = Length of annulus, collar or pipe DH = Hole diameter

DP = Collar or pipe diameter

12. If a formation pore pressure gradient at 8500ft is 0.486 psi/ft, what mud weight is required to give an over-balance of 200 psi?

Answer... 2

WORKSHOP 1 - Answers