SPE 130316 ECDmanagementGulfofThailand

8/10/2019 SPE 130316 ECDmanagementGulfofThailand

http://slidepdf.com/reader/full/spe-130316-ecdmanagementgulfofthailand 1/18

SPE/IADC 130316

Managed Pressure Drilling Avoids Losses while Improving Drilling and ECDManagement in the Gulf of ThailandPaul Fredericks, Greg Garcia, Ossama Sehsah P. Eng., At Balance

Copyright 2010, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition

This paper was prepared for presentation at the 2010 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition held in Kuala Lumpur, Malaysia, 24 –25February2010.

This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed bythe Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society ofPetroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of theSociety of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not becopied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright.

Abstract

A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale.

Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high

equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability.

Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant

hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably

reduced by those same conventional practices.

Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still

avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when

the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the

fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways thatcontributed to improved hole cleaning.

Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in

2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9-5/8” casing with an 8-1/2” bit

down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through

the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD

was used to drill the entire 8-1/2” section.

For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-timehydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the

trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and

drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type.

Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices.Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency andECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP

control.

Introduction

Oil reservoirs in some areas of the Gulf of Thailand are overlain by sedimentary strata well known for their troublesome

drilling characteristics. Alternating layers of shale, depleted gas sands and thin inter-bedded coal seams present alternating

zones of instability and lost circulation. To be successful in those areas with conventional drilling, operators have to followcarefully prescribed ECD management practices and be willing to sacrifice drilling optimization.

In those areas, losses have been known to occur while drilling 8-1/2” holes with 10.5 ppg mud which is required for wellbore

stability. However, with 10.5 ppg mud the ECD can be as high as 11.9 ppg and greater the fracture gradient (Figure 1).

In the drilling campaign that preceded the use of MPD in the Gulf of Thailand three wells were drilled to TD without losses.



2 SPE/IADC 130316

To do so the operator had to manage the ECD below 11.3 ppg which he accomplished by:

Cutting back on ROP and flow rate

Restricting string rotation speeds

Back reaming frequently

Using mud with higher plastic viscosity and solids concentrations

Though successful, those ECD management practices made it difficult and more expensive to drill high angle and longer hole

sections. In the search for an alternative solution to manage ECD, avoid losses, reduce cost, and increase drilling efficiency the

operator turned to Managed Pressure Drilling and selected the Dynamic Annular Pressure Control* (DAPC*) system.

MPD Overview

In conventional drilling, the annulus of a well and the returning drilling fluid are open to atmospheric pressure. In managed

pressure drilling they are not. The annulus is sealed by a rotating control device (RCD) mounted on the BOP from which the

mud flows through a choke manifold. As the mud circulates through the manifold, backpressure is added or released by

closing or opening the choke and therein lies the benefit of MPD to ECD management and drilling efficiency (Figure 2).

The MPD system that was used in these wells included an automated control and data acquisition system that monitored and

controlled the pressure in the annulus. The primary objective of that process was to control the BHP at a fixed point in the

well, between limits that if crossed could lead to influx, instability, and mud loss.

To accomplish that objective the pressure control process starts with an analysis of the hydraulics relative to the specific pressure limits. Multiple hydraulics scenarios were modeled for the operator and the conclusion was that the optimum mud

was one statically underbalanced relative to wellbore stability. Wellbore stability was maintained with the DAPC system by

adding and controlling backpressure whenever a pump transition occurred, that is when the rig pumps were shut down orstarted. During a transition the control system automatically synchronizes choke closure with rig pump stoppage to add

backpressure at the same rate at which ECD is lost to ensure the BHP stays above wellbore stability.

Conventional and MPD scenarios were modeled and are compared in Figure 3. The pressure boundary conditions for both

scenarios were wellbore stability at 10.5 ppg EMW and fracture gradient at 11.5 ppg EMW. To maintain wellbore stability

under static pumps-off conditions the mud weight in the conventional scenario had to be 10.5 ppg. The model of the

conventional scenario predicted that with a 10.5 ppg mud the dynamic ECD would be 12.8 ppg which would exceed the

fracture gradient in the depleted sands.

However, an alternate model of the dynamic pumps-on conditions in the MPD scenario predicted that by dropping the mud

weight to 9.0 ppg EMW an ECD of 10.5 ppg could be achieved which would put the BHP above wellbore stability and belowthe fracture gradient. However, in order to ensure wellbore stability during static pumps-off conditions the DAPC system

would have to maintain the static BHP at 10.5 ppg by creating and managing surface backpressure between 450 and 650 psi,depending on well depth, geometry, and hydraulics.

In practice, the mud weight that was used during MPD operations on each of the nine wells drilled was 9.0 ppg and the actual

amount of backpressure varied between 265 and 790 psi.

The DAPC system included an automated control system, a choke manifold, a backpressure pump, a Coriolis flow meter, a

control cabin, generator, and all the necessary surface piping and isolation valves to connect it to the rig equipment (Figure 4).

Operational Reviews

Nine wells were drilled with inclinations that varied between 40 and 90 degrees. In total, over 14,500 meters of 8-1/2” hole

were drilled with MPD during which the BHP was managed in over 450 connections, a connection represents a pressure

transition from pumps-on to pumps-off and back. However, other transitions were also managed by the MPD system, e.g.during MWD surveys and down linking, rig repairs, RCD element change out, and trips.

The operator’s objectives in this well were the same as every previous and subsequent well – manage the ECD to avoid lossesin the high risk 8-1/2” hole section and minimize the ECD with good hole cleaning practices. Managed pressure drilling was

used to achieve those objectives by reducing the static mud weight below wellbore stability and maintaining a constant BHP

whenever the rig pumps were shut down.

In general, the plan that was implemented for MPD in the initial drilling program became the blueprint for most of the wells

that followed. Drill a conventional 8-1/2” hole with 10.2 to 10.5 ppg mud just above the depleted sands, switch over to 9.0 ppg

mud, install the rotating control device (RCD), and rig-up and operationally certify the MPD system. If required, final training

would take place on the rig during which the crew would practice implementing the appropriate procedures for various

contingency scenarios. Once training was completed and the equipment certified as ready drilling would proceed.

However, after the fifth well, the drilling procedure was changed and MPD was used to drill the entire 8-1/2” section. The

reason for that decision was due to the time it was taking to rig up the RCD and the secondary trip tank and make final



SPE/IADC 130316 3

connections to the MPD system. It was felt that leaving the hole open for that length of time posed a risk to well stability.

In adopting MPD the operator was able to use a lighter mud, reduce the yield point, plastic viscosity, and the solids content,

and increase the flow rate through most of the MPD intervals (Figure 5). With the implementation of these and other changesthe operator was able to avoid losses and improve his drilling efficiency.

Drilling Performance

A comparison was made of depth versus time achieved with conventional and managed pressure drilling. All of the drill timedata is from the high risk 8-1/2” hole sections some of which were directional, some horizontal. In an effort to establish a

benchmark for drill rate, depth versus time data from an offset horizontal well was plotted and presented in Figure 6. In that

offset well it took a couple of days to reach the depleted sands ( 2226 m MD) at an average drill rate of 372 m/day. Afterencountering the sand the drill rate was slowed down to an average 234 m/day. Overall the section was drilled at an averagerate of 279 m/day. Over 80 connections were made during both sections and in accordance with established procedures for

managing high ECD the pipe was back reamed before each connection which amounted to over 2 days of rig time.

Drill time data from the first well is plotted in Figure 7. That well was drilled conventionally to 2655 m, just above the

depleted sand, from which point MPD was used to manage the BHP down to the heel. The average drill rate in the MPD

section was 378 m/day which represented an improvement of over 60% compared to the 234 m/day average that was achieved

in the offset well in the section the depleted sand. As part of the ECD management practices, back reaming was being done

with the same frequency as before.

The third well was a 40 degree directional sidetrack of the second well. The sidetrack was drilled with MPD down to 2745m atwhich point a trip was made to make repairs. Down to that point the average drill rate was 525 m/day which was a further

improvement in the drill rate (Figure 8). Its moderate inclination might have contributed to its higher drill rate and better hole

cleaning compared to the previous horizontal wells. But a point to make is that the MPD section below the depleted sand was

drilled at over 500 m/day which was not the case in previous wells below the depleted interval.

The fifth well was another horizontal well which was drilled in three sections. Originally, the intention was to drill this well in

the same way as the previous wells – conventional down to the depleted zone and MPD to section TD. Everything went

according to plan until two days into the MPD section (Figure 9) when RCD malfunctions prompted the operator to drill the

rest of the horizontal section conventionally (Figure 10). In going from MPD to conventional drilling there was a significant

reduction in the drill rate from 400 m/day with MPD to 87 m/day with conventional drilling. It was unfortunate to obtain such

a comparison in this way but it highlights the difference in drilling efficiency between MPD and conventional practices.

In all the subsequent wells the operator changed their procedures to protect the well and improve efficiency. Their standard

practice was to drill conventionally down to the depleted sands then change over to MPD. However, that meant leaving thehole open during the time it took to roll-over the mud system, complete the installation of the RCD, and make final

connections to the MPD system. To reduce the risk of unnecessary instability in the wells it was decided to drill the entire 8-

1/2” hole section with MPD.

That practice was implemented in the next horizontal well in which both the pilot hole and the lateral were drilled with MPD

from start to finish (Figure 11 & 12). Throughout the pilot hole, above and below the depleted sands, the drill rate averaged of

674 m/day, a considerable improvement compared to the average achieved in earlier wells drilled with conventional and MPD.

In the horizontal section drilling averaged 330 m/day which was greater than what could be achieved under conventional

conditions.

ECD Management

Data from the annular pressure while drilling (PWD) tool was used to compare the effectiveness of ECD management in

conventional and MPD hole sections. Figure 13 contains the PWD log from the same offset well from which depth versus timewas plotted in Figure 7. It shows the nature of the ECD management problem in the high angle wells in this field. The ECD

varied widely throughout the well and in the section between 1500m and 3000m the ECD is greater than the fracture gradient

of the depleted sand.

The PWD data from the first well is plotted in two separate charts, one for the conventional section drilled above the depleted

zone (Figure 14) and one for the MPD section drilled through the zone (Figure 15). The ECD in the conventionally drilled

section is similar to the offset well in the manner in which it varies across the section and the magnitude it reaches towards the

end of the section. The BHP in the MPD section was lower and nearly constant for the entire interval which made the ECD

easier to manage.

Pressure data from the third well (Figure 16 & 17) and fifth well (Figure 18 & 19) were plotted in the same manner as the first

– the upper section above the depleted sand was drilled conventionally and lower section below the sand was drilled with

MPD. The conventional and MPD sections of both wells are similar to the first and the ECD varied significantly more in the

conventional section than in the MPD section. In the third well the ECD was managed particularly well and stayed below 11



SPE/IADC 130316 5

Figure 1. Sample profile of the pressures typically encountered in the target field in the Gulf of Thailand.

Figure 2. Illustration of the MPD process flow diagram.



6 SPE/IADC 130316

Parameter Conventional Scenario MPD Scenario

Density at 104°F 10.5 ppg OBM 9.0 ppg OBM

Viscosity Law Power Law Power Law

PV 25 cp 18 cp

YP 28 lb/100 ft^2 15 lb/100 ft ^2R6 15 deg 12 deg

Flow Rate 600 gpm 600 gpm

ROP 60 m/hr 60 m/hr

Rotary Speed 120 rpm 120 rpm

ECD - model 12.5 ppg 10.59 ppg

Fracture Gradient 11.5-11.7 ppg 11.5-11.7 ppg

Figure 3. The above table reflects the results of one of the hydraulics scenarios that were modeled to quantify the ECD

reduction with MPD.

Figure 4. Photo of MPD system installed on the jack-up that was used during the second drilling program in 2009.



SPE/IADC 130316 7

Conventional Drilling 8-1/2" Hole - Summary of Mud Properties

Well Type MW (ppg) PV (cP) YP (lb/100ft2) Flow (gpm)

#1 Horizontal 10.2 22.3 15.7 594.8

#2 Directional 10.2 16.7 16.8 632.8

#3(#2 ST) Directional 10.2 19.7 16.2 626.2

#4 Directional 10.2 34.7 16.0 633.3

#5 Directional 10.5 33.8 16.2 650.0Total Hole Interval

Managed Pressure Drilling 8-1/2" Hole - Summary of Mud Properties

Well Type MW (ppg) PV (cP) YP (lb/100ft2) Flow (gpm)

#1 Horizontal 9 18 16 647

#2 Directional 9 14 14 649

#3 (#2 ST) Directional 9 17 13 641



#6 Hor. Pilot 9 22 10 627

Hor. Lateral 9 22 10 627#7 Hor. Pilot 9 22 12 672

Hor. Lateral 9 22 11 624


#9 Directional N/A N/A N/A N/A

Total Hole Interval

Figure 5.Tables comparing mud properties used during conventional and MPD phases of drilling.

Figure 6. Plot of depth versus time from a conventionally drilled offset well. In this and each of the subsequent drill time plotsthe depth data is plotted versus time on a 24 hour scale. That allows each day of drilling to be plotted as a separate line across

the graph which makes it easier to see differences in drill rate. In this well, during the first two days of drilling the average drill

rate was 372 m/day. The depleted sand was encountered after the 2nd

day of drilling at which point the drill rate was slowed

down. The average drill rate for the section was 281 m/day.



8 SPE/IADC 130316

Figure 7. Plot of depth versus time in the first well. The blue curve represents conventional depth versus time data and the

green curve, MPD. This was a horizontal well which was drilled to just above the depleted sand at which point the MPD

system was connected and the mud switched over to 9.0 ppg. MPD was used to manage the ECD to the heel of the well.

Figure 8. Plot of depth versus time in third well drilled conventionally above the depleted zone and MPD below.

1600

1800

2000

2200

2400

2600

2800

3000

3200

3400

3600

3800

4000

4200

4400

0: 00 1:00 2:00 3:00 4:00 5:00 6:00 7:0 0 8: 00 9:00 10:00 1 1:00 12:00 13:0 0 14:00 15:00 16 :00 17:00 18:0 0 1 9:00 20:00 21:0 0 22:00 23:00 0: 00

M e a s u r e d D e p t h ( m )

Time in 24 hr scale

First Well - Depth vs Time

Start convent ional: 1655m

End Conv entional: 2655m

Start MPD: 2655m

End MPD: 4243mMPD Section 1588 m in 4.2 days = 378 m/day

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:0011:0012:0013:0014:0015:0016:0017:0018:0019:0020:0021:0022:0023:00 0:00


Time - 24 hour scale

Third Well - Depth vs Time

MPD Start = 1930m

MPD End = 2950m1020 / 2 day = 510 m/day, MPD effective drill time

Conventional Start = 1240m

TOOH @ 2745 m

Back Ream



SPE/IADC 130316 9

Figure 9. Plot of drill time from the MPD section of the fifth well drilled through and below the depleted sand. MPD

operations were suspended and the remainder of the well was drilled conventionally (see Figure 10, below).

Figure 10. Plot of drill rate in the conventionally drilled 8-1/2” section of the fifth well – drilled after and below the MPD

section. It shows the significant reduction in drill rate that occurred after switching back to the higher mud weight and

conventional practices.

2700

2800

2900

3000

3100

3200

3300

3400

3500

3600

3700

0 : 0 0

1 : 0 0

2 : 0 0

3 : 0 0

4 : 0 0

5 : 0 0

6 : 0 0

7 : 0 0

8 : 0 0

9 : 0 0

1 0 : 0 0

1 1 : 0 0

1 2 : 0 0

1 3 : 0 0

1 4 : 0 0

1 5 : 0 0

1 6 : 0 0

1 7 : 0 0

1 8 : 0 0

1 9 : 0 0

2 0 : 0 0

2 1 : 0 0

2 2 : 0 0

2 3 : 0 0



Fifth Well - MPD Depth vs Time

Day 1

Start MPD 2870m

Day 2

End MPD 3670m MPD interval 800 m in 2 days = 400 m/day

3500

3600

3700

3800

3900

4000

4100

4200

4300

4400

4500

0 : 0 0

1 : 0 0

2 : 0 0

3 : 0 0

4 : 0 0

5 : 0 0

6 : 0 0

7 : 0 0

8 : 0 0

9 : 0 0

1 0 : 0 0

1 1 : 0 0

1 2 : 0 0

1 3 : 0 0

1 4 : 0 0

1 5 : 0 0

1 6 : 0 0

1 7 : 0 0

1 8 : 0 0

1 9 : 0 0

2 0 : 0 0

2 1 : 0 0

2 2 : 0 0

2 3 : 0 0



Fifth Well - Conventional Drilling Depth vs Time

Day 5

TOOH Day 14

TIHDay 12 TOOH Day 9

Day 6

Day 7

Day 8

Day 9

Day 13

Day 14

Start conventional @ 3690m

End conventional @ 4345m

Conventional interval 655m in 7.5 day = 87 m/day

(only on bottom time counted)



10 SPE/IADC 130316

Figure 11. Plot of drill time in the seventh well. The entire 8-1/2” pilot hole was drilled with MPD above, through, and below

the depleted zone. The operator achieved a higher average drill rate through zones that under conventional conditions would be

drilled slower to achieve the same level of ECD management.

Figure 12. Plot of drill time for the horizontal kick-off section of the seventh well drilled entirely with MPD.

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

0 : 0 0

1 : 0 0

2 : 0 0

3 : 0 0

4 : 0 0

5 : 0 0

6 : 0 0

7 : 0 0

8 : 0 0

9 : 0 0

1 0 : 0 0

1 1 : 0 0

1 2 : 0 0

1 3 : 0 0

1 4 : 0 0

1 5 : 0 0

1 6 : 0 0

1 7 : 0 0

1 8 : 0 0

1 9 : 0 0

2 0 : 0 0

2 1 : 0 0

2 2 : 0 0

2 3 : 0 0



Seventh Well - Pilot Hole - MPD Depth vs Time

MPD Start1302m

MPD End 2818m

MPD interval 1516m drilled in 2.25 days 674 m/day

9-5/8" Csg

1800

2000

2200

2400

2600

2800

3000

3200

0 : 0 0

1 : 0 0

2 : 0 0

3 : 0 0

4 : 0 0

5 : 0 0

6 : 0 0

7 : 0 0

8 : 0 0

9 : 0 0

1 0 : 0 0

1 1 : 0 0

1 2 : 0 0

1 3 : 0 0

1 4 : 0 0

1 5 : 0 0

1 6 : 0 0

1 7 : 0 0

1 8 : 0 0

1 9 : 0 0

2 0 : 0 0

2 1 : 0 0

2 2 : 0 0

2 3 : 0 0



Seventh Well - Horizontal Kick-off - MPD Depth vs Time

MPD Start 1909m

MPD End 2996m

MPD interval 1087m in 3.3 days = 330 m/day

Horizontal KOP



SPE/IADC 130316 11

Figure 13. Plot of annular pressure from an offset well showing the difficult nature of managing the ECD while drilling high

angle wells in this Gulf of Thailand field.

Figure 14. Plot of ECD versus time from the conventionally drilled section of the first well. In each of the pressure graphs the

red curve is depth data and the blue curve is ECD data from the PWD tool. The spikes on the depth curve represent off-bottom bit movement, typically back reaming before each connection. This section was drilled above the depleted sand. Note the

pressure scale from 10 ppg to 13 ppg.



12 SPE/IADC 130316

Figure 15. Plot of ECD versus time from the MPD section of the first well. The red curve is depth data and the green curve is

ECD data from the PWD tool. This section was drilled below the depleted interval. Note the scale for the pressure data scale in

this graph is 10 ppg to 13 ppg which is the same as Figure 14 above.

Figure 16. Plot of ECD versus time from the conventionally drilled section of the third well. The red curve is depth data and

the blue curve is the ECD data from the PWD tool. The spikes in the depth curve represent off-bottom time (back reaming).

This section was drilled above the depleted zone. Note the pressure scale from 10 ppg to 13 ppg.

1200

1300

1400

1500

1600

1700

1800

1900

200010

10.5

11

11.5

12

12.5

13

1 9 : 2 5

2 1 : 2 5

2 3 : 2 5

1 : 2 5

3 : 2 5

5 : 2 5

7 : 2 5

9 : 2 5

1 1 : 2 5

1 3 : 2 5

1 5 : 2 5

1 7 : 2 5

1 9 : 2 5

2 1 : 2 5

2 3 : 2 5


A n n u l a r P r e s s u r e ( p

p g )

Time (hours)

Third Well - Upper 8-1/2" Section - Conventional ECD



SPE/IADC 130316 13

Figure 17. Plot of ECD versus time from the MPD section of the third well. The red curve is depth data and the green curve is

ECD data from the PWD tool. This section was drilled below the depleted zone. Note the scale is from 10 ppg to 13 ppg which

was kept the same as in Figure 16, above for easier comparison.

Figure 18. Plot of ECD versus time from the conventionally drilled upper 8-1/2” section of the fifth well. The red curve is

depth data and the blue curve is ECD data from the PWD tool. This section was drilled above the depleted sand and prior to

the start of MPD drilling (Figure 19, below). Note the pressure scale from 10 ppg to 15 ppg.

1800

1900

2000

2100

2200

2300

2400

2500

2600

2700

280010

10.5

11

11.5

12

12.5

13

0 : 0 0

2 : 0 0

4 : 0 0

6 : 0 0

8 : 0 0

1 0 : 0 0

1 2 : 0 0

1 4 : 0 0

1 6 : 0 0

1 8 : 0 0

2 0 : 0 0

2 2 : 0 0

0 : 0 0

2 : 0 0

4 : 0 0

6 : 0 0

8 : 0 0

1 0 : 0 0

1 2 : 0 0

1 4 : 0 0

1 6 : 0 0


A n n u l a r P r e s s u r e ( p p g

)

Time (hours)

Third Well - Lower 8-1/2" Section - MPD ECD

1500

2000

2500

300010

10.5

11

11.5

12

12.5

13

13.5

14

14.5

15

0 : 0 0

2 : 0 0

4 : 0 0

6 : 0 0

8 : 0 0

1 0 : 0 0

1 2 : 0 0

1 4 : 0 0

1 6 : 0 0

1 8 : 0 0

2 0 : 0 0

2 2 : 0 0

0 : 0 0

2 : 0 0

4 : 0 0

6 : 0 0

8 : 0 0

1 0 : 0 0

1 2 : 0 0

1 4 : 0 0

1 6 : 0 0

1 8 : 0 0


A n n u l a r P r e s s u r e ( p p g

)

Time (hours)

Fifth Well - Upper 8.5" Section - Conventional ECD

ECD (ppg)

Depth



SPE/IADC 130316 15

Figure 21. Plot of ECD versus time from the 8-1/2” horizontal kick -off drilled with MPD in the seventh well. The red curve is

depth data and the green curve is ECD data from the PWD tool. This section was kicked-off below the depleted sand. Note the

pressure scale: 10 – 13 ppg.

Figure 22. Plot of four consecutive connections from the first well made with MPD in control of the pressure. The maximum

and minimum lines define the window within which the pressure was allowed to fluctuate by the MPD system during the

connections, specifically during the pressure transition caused by the pumps being turned off and on. The max / min peaks are

a measure of the ability of the system to manage the ECD during sudden changes in pressure and flow. Max/min peaks are

applicable only when the system is actively controlling pressure. If the system was not actively controlling pressure while

drilling then it will have no control over the fluctuations.

1800

2000

2200

2400

2600

2800

3000

320010

10.5

11

11.5

12

12.5

13

7 : 0

0

9 : 0

0

1 1 : 0

0

1 3 : 0

0

1 5 : 0

0

1 7 : 0

0

1 9 : 0

0

2 1 : 0

0

2 3 : 0

0

1 : 0

0

3 : 0

0

5 : 0

0

7 : 0

0

9 : 0

0

1 1 : 0

0

1 3 : 0

0

1 5 : 0

0

1 7 : 0

0

1 9 : 0

0

2 1 : 0

0

2 3 : 0

0

1 : 0

0

3 : 0

0

5 : 0

0

7 : 0

0

9 : 0

0

1 1 : 0

0

1 3 : 0

0

1 5 : 0

0

1 7 : 0

0

1 9 : 0

0

2 1 : 0

0

2 3 : 0

0

1 : 0

0

3 : 0

0

5 : 0

0

7 : 0

0

9 : 0

0

1 1 : 0

0


A n n u l a r P r e s s u r e ( p p g )

Time (hours)

Seventh Well - Horizontal Kick-off - MPD ECD

0

100

200

300

400

500

600

700

800

900

1000

6.5

7

7.5

8

8.5

9

9.5

10

10.5

11

11.5

1 2 : 2 3

1 2 : 3 3

1 2 : 4 3

1 2 : 5 3

1 3 : 0 3

1 3 : 1 3

1 3 : 2 3

1 3 : 3 3

1 3 : 4 3

1 3 : 5 3

1 4 : 0 3

1 4 : 1 3

1 4 : 2 3

1 4 : 3 3

1 4 : 4 3

1 4 : 5 3

1 5 : 0 3

1 5 : 1 3

1 5 : 2 3

1 5 : 3 3

1 5 : 4 3

1 5 : 5 3

1 6 : 0 3

1 6 : 1 3

1 6 : 2 3

1 6 : 3 3

1 6 : 4 3

1 6 : 5 3

1 7 : 0 3

P r e s s u r e ( p s i ) , F l o w

( g m p )

E C D ( p p g )

Time (hours)

Plot of Four Conn ections from First Well

ECD PWD ECD Model Backpressure Pump Backpressure Flow-in

Maximum

Minimum



16 SPE/IADC 130316

Figure 23. Detail plot of a connection from Figure 22, above. Pump transitions are marked at the start of the connection when

the rig pumps are being turned off and at the end when the pumps are being turned on. This was one of the early connections

made while the rig crew was still becoming accustomed to working the pumps for managed pressure drilling. After the

connection the driller brought the pumps on quickly which caused the modeled pressure to fluctuate; the rate was adjusted to

avoid further spikes. PWD data was not transmitted and memory data was not provided.

Figure 24. Plot of pressure during multiple rapid transitions in seventh well caused by rig pump failure. The system was

actively controlling pressure at the time of the pump failure and was able to immediately respond when the flow rate dropped.

This highlights how MPD response time contributes to ECD management during unexpected pressure changes.

0

100

200

300

400

500

600

700

800

900

1000

6.5

7

7.5

8

8.5

9

9.5

10

10.5

11

11.5

1 2 : 2 9

1 2 : 3 0

1 2 : 3 1

1 2 : 3 2

1 2 : 3 3

1 2 : 3 4

1 2 : 3 5

1 2 : 3 6

1 2 : 3 7

1 2 : 3 8

1 2 : 3 9

1 2 : 4 0

1 2 : 4 1

P r e s s u r e ( p s i ) , F l o w

( g p

m )

E C D ( p p g )

Time (hours)

Connection Plot from First MPD Well

ECD Model ECD PWD Backpressure Pump Backpressure SP Backpressure Flow-in

Pump

Transition120 sec

Pump

Transition90 sec

Pressure spike caused

by sudden pump increase

after connection made

0

100

200

300

400

500

600

700

800

900

1000

9

9.5

10

10.5

11

11.5

2 1 : 4 3

2 1 : 4 4

2 1 : 4 5

2 1 : 4 6

2 1 : 4 7

2 1 : 4 8

2 1 : 4 9

2 1 : 5 0

2 1 : 5 1

2 1 : 5 2

2 1 : 5 3

2 1 : 5 4

2 1 : 5 5

2 1 : 5 6

2 1 : 5 7

2 1 : 5 8

2 1 : 5 9

2 2 : 0 0

2 2 : 0 1

2 2 : 0 2

2 2 : 0 3

2 2 : 0 4

2 2 : 0 5

2 2 : 0 6

2 2 : 0 7

2 2 : 0 8

2 2 : 0 9

2 2 : 1 0

2 2 : 1 1

P r e s s u r e ( p s i ) a n d F l o w

( g p m

)

E C D ( p p g )

Seventh Well - MPD Control During Rig Pump Failure

ECD Model ECD PWD ECD SP Backpressure Backressure SP Flow In

45 sec

Transition

30 sec

Transition

Pump rate drops by over 250 gpm

System increases backpressure by 200 psi

ECD drops below 10.5 ppg for < 5 sec

ECD constant at set point of 10.7 ppg



SPE/IADC 130316 7

Figure 25. Minimum and maximum fluctuations that occurred while MPD controlled the BHP during connections made in the

first three wells. The window is defined by the upper fracture gradient limit (11.5 ppg) and the lower wellbore stability limit

(10.2 ppg).

Figure 26. Partial plot of the minimum and maximum fluctuations that occurred while MPD controlled the BHP during

connections made in the second drilling program in 2009. The window is defined by the upper fracture gradient limit (11.5

ppg) and the lower wellbore stability limit (10.2 ppg).

0

0.25

0.5

0.75

1

1.25

1.5

1.75

2

8.0

8.5

9.0

9.5

10.0

10.5

11.0

11.5

12.0

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105

E C D W i n d o w ( + / - p p

g )

E C D E M W ( p

p g )

Connections

Min/Max ECD during 2007 MPD Connections - Partial Summary

Max ECD (ppg) Min ECD (ppg) ECD Min/Max Window (+/- ppg) Window Trend

Upper limit - fracture gradient

Lower limit - wellbore stability

Mud weight - 9.0 ppg

0

0.25

0.5

0.75

1

1.25

1.5

1.75

2

8.0

8.5

9.0

9.5

10.0

10.5

11.0

11.5

12.0

0 10 20 30 40 50 60 70 80 90 100 1 10 1 20 1 30 1 40 1 50 1 60 1 70 1 80 1 90 2 00 2 10 2 20 2 30 2 40 2 50

E C D W i n d o w ( + / - p p g )

E C D E M W ( p

p g

)

Connections

Min/Max ECD during 2009 MPD Connections - Partial Summary

Max ECD (ppg) Min ECD (ppg) ECD Min/Max Window (+/- ppg) Window Trend

Upper limit - fracture gradient

Lower limit - wellbore stability

Mud weight - 9.0 ppg



18 SPE/IADC 130316

Figure 27. Plot of connection times during 8 of the 9 wells. For the purpose of this plot the connection time is defined as the

moment the driller starts to turn off the rig pump and after the rig pump was brought back up to speed for drilling or slow

pump rate flow checks. This plot highlights the continuous improvement that was made by the rig and MPD crew to reduce

connection time while minimizing fluctuations in ECD during the pump transitions.

0

5

10

15

20

25

30

35

0 50 100 150 200 250 300 350 400 450 500

T i m e ( m i n u t e s )

Connection

All Connection Times Pump-on to Pump-on

Connection Data

Unavailable

SPE 130316 ECDmanagementGulfofThailand

Documents

Transcript of SPE 130316 ECDmanagementGulfofThailand