spe 130319 onshorempdandcementing

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SPE/IADC 130319

Experience and Results with a New Automated MPD System while Drillingand Cementing Liner in an Onshore Depleted Gas FieldPaul Fredericks, Ossama Sehsah P. Eng., At Balance; Julio Montilva, Phil Vogelsberg, Shell Exploration &Production Company

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

In their development of onshore gas fields in South Texas Shell has encountered margins in which the difference between

dynamic ECD and static BHP is the difference between lost circulation and influx. Their solution to eliminate those problems

included liner drilling and automated MPD. Those complementary technologies allowed Shell to extend static underbalanced

drilling to extremely tight margins, eliminate losses and stuck pipe, and manage constant BHP during periods of high drill gas

and cementing operations.

An automated and modular MPD system was recently used in two wells to hold constant BHP in a very narrow window

without a back pressure pump. In the first well, Shell used the system to drill-in 740 ft of 7-5/8” liner in an 8-1/2” hole with

15.0 ppg mud statically underbalanced relative to wellbore stability. In the second, the system was used to drill -in 700’ of 3-

1/2” tubing in a 6-1/2” hole with a static mud of 15.7 and a dynamic ECD of 16.2 ppg. In that interval the upper limit was

estimated to be a 16.5 ppg fracture gradient and the lower limit, a 15.8 ppg pore pressure.

In the second well the level of drill gas rose to over 1400 units. However, even with such high levels of gas the new MPD

system was able to maintain the BHP between +/- 0.2 ppg while making connections and trapping gas in the annulus. Shell

was able to avoid the cost of a contingency 5-1/2” liner drilling operation and for the first time used an automated MPD

system to manage constant BHP while cementing a drilled-in production tubing string.

The small footprint and improved control capability of the new MPD system can provide onshore and offshore operators an

efficient solution to improve drilling and cementing operations in mature depleted fields.

Introduction

The McAllen and Pharr fields are located in Hidalgo County, situated in South Texas along the Rio Grande River (Figure 1).

Shell acquired those fields in 2006 and over the 7 decades since their discovery nearly 1.4 TCF of gas has been produced from

reservoirs in the Frio formations. Initial production was from shallow zones, many of which are now depleted by as much as5,000 psi. The fields have an extended history of comingled production and complex patterns of hard -to-map faults which

make pore pressure and depletion difficult to predict. Isolating the severely depleted zones with liners is impractical because

they are often found between over-pressured virgin sands.

Compared to nearby fields in the Vicksburg formations those in the Frio have higher permeability and require heavier mud

weight to avoid influx. Another limiting factor in the McAllen-Pharr field is the ease with which losses occur in many of the

reservoir sands due to the lower minimum horizontal stress caused by depletion. The resulting narrow pressure profile and the

inaccurate pore pressure predictions complicated early drilling efforts with excessive lost circulation and well control events.

In one early example, a well was drilled to its 7 5/8” liner point with 13.5 ppg oil base mud and substantial amounts of

background gas. Total losses occurred when the mud weight was raised to 14.7 ppg prior to tripping out of the hole. After

pumping cement and reducing the mud weight to 12.0 ppg the liner had to be drilled-in without returns then cemented in place.Another well drilled through a different profile using a 16.2 ppg mud suffered losses in the same way when the mud weight

was raised to 16.4 ppg before tripping out. Days were spent pumping LCM, trying to control losses and gas, running open-



2 SPE/IADC 130319

hole logs and reducing the mud weight to 15.9 ppg just to get ready to run the liner. The problems were compounded when

after stopping reaming operations to shut-in the well and circulate out the gas the liner became differentially stuck off bottom;

cement had to be squeezed and an isolation packer set in place. A lesson learned was that both of those wells suffered losses at

lower than anticipated mud weights and only after raising the mud weight to trip out of the hole.

To reduce those types of lost circulation events Shell first turned to liner drilling because it offered several benefits in a

depleted environment. One was eliminating the need to raise the mud weight for trips simply because there is no need to trip

which eliminated swab and surge effects. Shell derived another more selective benefit from liner drilling in low permeabilityreservoirs. By taking advantage of the fact that low permeability reservoirs will not easily flow when the BHP is below pore

pressure Shell was able to drill those zones with statically underbalanced mud (relative to pore pressure) with little risk of

influx when the mud pumps were turned off. That gave them the ability to reduce the ECD and the risk of lost circulation in

sands with low fracture gradients and it allowed them to eliminate extra casing strings.

Both of the previously discussed wells would have benefited from liner drilling because both were drilled problem free to their

liner points and only ran into trouble with lost circulation when the mud weight was raised to trip out of the hole.

However, Shell’s use of liner drilling was limited in the McAllen-Pharr field because of the uncertainty before drilling beginsabout the pressures and permeabilities they will encounter. Reservoirs sands with higher than expected permeability will deny

them the advantage of static underbalance when the rig pumps were shut down. Early on Shell discovered that the

permeability of some reservoir sands could be high enough to flow when the mud is statically underbalanced and produce

without being fractured. That limited the amount by which they could reduce the mud weight and the effectiveness of liner

drilling.In their interest to extend the benefits of drilling with casing Shell looked for a way to avoid losses in the shallow depletedsands while drilling with the higher ECD needed to avoid influx in the deeper permeable reservoirs. In fact, Shell had already

found a way to manage similar problems in mature offshore fields and decided to use the same type of system in South Texas.

It became a matter of adapting the technology to onshore conditions.

That was two years and 7 wells ago and what started out as a simple matter of technology migration evolved into a sustained

effort of technology development. That effort culminated in a more efficiently designed system for automated pressure control

which was used in the Bales #7 well to manage pressure while drilling and cementing.

System Description

The automated MPD system that Shell was using in their deepwater Gulf of Mexico fields included a self-contained, skid

mounted choke manifold and backpressure pump, a Coriolis flow meter, an automated pressure relief choke, and high pressure

rotating control device (Figure 2). The self-contained choke manifold though functionally suitable for land based MPDoperations is designed to conform more to offshore specifications. One of those is the protective DNV certified crash frame

which makes the manifold cumbersome on land because it requires heavy lifting equipment to load and place which can be

impractical for land based applications.

After the first MPD well was drilled in the Pharr field Shell and At Balance started looking for ways to improve the system for

land operations. They focused on ways to reduce the size and weight of the manifold, to make it easier to handle and transport

and faster to rig-up. In the design process At Balance reduced the number of chokes, valves, and bypass lines which drove

improvements in the hydraulic power system. Those were significant changes that led to a new manifold that is modular inform and efficiently scaled.

In early 2009, Shell and At Balance took the new system to the test facility at the Louisiana State University to evaluate its

ability to control pressure without a backpressure pump. The test objectives were to improve the pressure trapping process by

reducing the footprint and rig-up time and maximizing the performance of the system with the least amount of equipment on

location. After demonstrating its ability to automatically trap pressure under controlled conditions, Shell installed andsuccessfully operated the system on two wells – the Pharr Field Wide Unit (PFWU) #56 and the Bales #7 wells.

In addition to the improvements made to the manifold improvements were also made to the operating control process.

Reducing the amount of hardware in the manifold meant that the new operating system had to be written to preserve

redundancy through functional efficiency – that is, it had to do more with less. One way it accomplishes that is in the way it

manages the chokes. In its original design the choke manifold had three chokes, two of which were redundant for active

backpressure management and one which was for active pressure relief. In the new manifold there are only two chokes (Figure

3). With the new operating system one choke is always on line and dedicated for active backpressure management while theother is held in reserve as a backup to the primary choke in the event it becomes plugged. At the same time, the second choke

is also used for automated pressure relief.

In the pressure relief process a safety bias controls the amount by which the backpressure is allowed to increase before the

system automatically opens the choke to relieve pressure. The bias is a function of the set point so if the set point is changed

then the pressure relief bias changes with it. Once pressure is relieved the system will automatically begin closing the choke



SPE/IADC 130319 3

until the backpressure returns to the set point and normal control is resumed. Unlike a typical pressure relief valve which is a

purely mechanical device that has only two states – open or closed – the automated pressure relief choke operates continuously

and smoothly within the limits set by the control system. That protects the well against sudden spikes in backpressure above

or below the ECD set point.

The primary objective of the new system is to maintain a constant BHP in the annulus at a specified set point in the well. In

that process the controller and real-time hydraulics model take into account a number of drilling parameters including

wellhead pressure, hole geometry, mud properties, and rig pump stroke rate to calculate and respond to changes in the ECDand static BHP. Under dynamic conditions, continuous adjustments are made to the choke to ensure that the appropriate

amount of backpressure is always being applied to the annulus to keep the BHP in the specified margin.

Another important aspect of the constant BHP process is in avoiding pressure surges that can occur when a choke closes

rapidly and avoiding the loss of bottomhole pressure. One way to do that is to continuously circulate drilling fluid through the

choke manifold when the rig pumps are off which can be done with an automated backpressure pump or a manually operated

rig pump. One of the features of the new system is its ability to respond and trap pressure fast and not rely on a backpressure

pump. However, its control system is also capable of working with an automated backpressure pump or a rig pump.

The first job for the new system was on the PFWU 56 well. It included the modular manifold, a Coriolis flow meter, and a

backpressure pump (Figure 4). On second job, the Bales 7 well, the system was reduced to the manifold and meter (Figure 5).

Connections were made to the rig pump if additional flow was needed to boost the level of the trapped pressure. A principle

benefit of the modular system’s small footprint and easy handling is in the amount of time it takes to rig-up. On the Bales 7

well the MPD crew rigged up the modular system in 7 hours which was 60% faster than the time it took to rig up the systemon the PFWU 56 well and 85% faster than the 2 day average it took to rig-up the offshore system on earlier wells.

In the first well the new system was used to manage the BHP while drilling in with 7-5/8” liner and in the second it was used

to control the ECD in two separate hole sections – one conventionally drilled with jointed pipe and one with 3-1/2” casing. In

the first well the system managed the BHP during connections using the backpressure pump but in the second well it held the

BHP constant primarily by trapping backpressure.

It is a standard operating procedure to tune the system to the existing drilling parameters then perform a number of simulated

connections to provide the drilling crew with the necessary training and practice. One of the lessons learned with the systemduring these wells was that when tuned to manage pressure during drilling operations the chokes will close at a slower rate

during connections compared to when they are tuned for connections only. To compensate modifications were made to the

pressure trapping procedure during connections that allowed the system to maximize the amount of pressure that was trapped

and minimize usage of the backpressure or rig pumps.

MPD Liner Drilling –

PFWU 56

The area in which these wells are drilled is characterized by complex faulting and a lack of offset well data. That made it

difficult to predict the pore pressure and fracture gradient in several of the older reservoir sands that Shell was going to drill in

the production hole.

In the first well, PFWU 56, MPD was used to manage the ECD in the 8-1/2” hole section while drilling in with a 7-5/8” liner

assembly from 8770 ft MD to 10412 ft MD (Figure 6). The objective was to drill the severely depleted formations (Figure 7)

situated below the 9-7/8” casing shoe without losses by using MPD to manage the ECD and using the drill-in liner to eliminatethe need for heavy kill muds. The section was drilled with a static mud weight of 14.7 ppg during which the objective was to

manage the ECD on connections below the minimum fracture gradient (FG), 15.7 ppg and above the maximum pore pressure

(PP), 15.5 ppg. Part of the challenge was in the nature of the pressure prediction itself because both the FG and PP were

estimates which would be verified by actual drilling conditions. In addition, the use of liner drilling did not allow the use of a

pressure while drilling tool and so control was based on the hydraulics model integrated into the control system.

After the MPD / Liner operation in the 8-1/2” section a 6-1/2” production hole was drilled with MPD and conventional drill pipe. Twenty connections were made in the 8-1/2” hole and 6 in the 6-1/2” hole during which the system managed the ECD

transition during pumps on and off at times by injecting mud with the backpressure pump and at times purely by trapping

BHP. Figure 8 is a plot of the first connection made with this system using automated pressure trapping. It presents a good

picture of the challenges an MPD system must contend with when trying to maintain a constant BHP purely by synchronizing

the choke to the rig pump flow rate and without an automated backpressure pump. However, in spite of the many changes in

the pump rate at the beginning of the connection, the BHP was still held to 16.9 ppg, only 0.1 ppg below the set point.

Upon reaching TD in the PFWU 56 well an influx was detected by the system (Figure 9). As the flow out increased to 350

gpm the system was used to add BP to the wellbore by manually increasing the ECD SP in increments of 0.1 from 17.03 to

17.11. Flow was diverted to the rig choke because of the limitations of the RCD. Once it was determined that gains and losses

could be balanced at a flow rate of 94 gpm and a backpressure of 150 to 200 psi flow was re-diverted to the MPD system for

better control while circulating the kick. Losses were occurring at a rate of 5 bbl / 20 min. The MPD system was used to



4 SPE/IADC 130319

slowly decrease the ECD SP to reduce the losses while bleeding off gas pressure. The well was finally stabilized at a pump

rate of 148 gpm and an ECD SP of 17.03 with an average gas flow out of 1800 units and no losses (Figure 10).

MPD with Jointed Pipe – Bales 7

In the second well, Bales 7, the plan was to drill the 6 ½” hole with jointed pipe from the 7 5/8” casing shoe down to 10360 ft

MD (Figure 11). The plan included a 5 ½” drill-in liner contingency if the well were to lose circulation. The well was drilled

along an S-shaped trajectory with a 19 degree tangent section out to a departure of about 2100 ft until just above the 7 5/8”

casing shoe where it was dropped back to vertical (Figure 12).

Drilling with jointed pipe in the Bales 7 began with a mud weight of 13.2 ppg and as in the previous well almost immediately

below the shoe the well drilled through a pair of sands in which the pore pressure was estimated to be 4 to 6 ppg. That created

an over-balance condition of 3250 to 4150 psi. At the end of the section the mud weight was raised to 14.0 ppg while the

estimated pore pressure increased to almost 15 ppg which meant that a large part of the section was drilled statically

underbalanced relative to pore pressure.

The ECD set point was fixed at the 7 5/8” shoe which at the beginning of the section was 14.15 ppg and at the end had been

increased to 14.9 ppg. While drilling the 6 ½” hole the system controlled the ECD at the set point within +/- 0.12 ppg bycontinuously managing the backpressure between 100 to 200 psi (Figure 13). Fifteen connections were made with jointed pipe.

During the pump transitions at each connection the system controlled the BHP by trapping the backpressure as the pumps were

turned off and on. Piping was installed in the circulation system to allow one of the rig pumps to inject mud into the annulus

through the kill line as additional backpressure was needed for BHP control.

The set point for the BHP during connections was higher than the set point used for drilling in order to control the connection

gas while the rig pump was offline. On average during the transitions the new MPD system managed to control the BHP

fluctuations within +/- 0.25 to +/- 0.3 ppg (Figure 14).

While drilling this hole section a 20 bbl influx occurred when the sealing element in the RCD started to leak. The contingency

plan was immediately put in to action: flow was diverted through the choke line to the MPD manifold, the annular preventer

was closed, backpressure applied with the MPD system, and the pressure below the RCD bled off. Once it was confirmed that

there was no pressure below the RCD the sealing element was changed out. After circulating out the influx and replacing the

sealing element the section was drilled to 10360 ft MD where the bit penetrated the second depleted sand with no losses.

Upon reaching TD a wiper trip was made back to the 7 5/8” shoe, the drill pipe was laid down, and the 3 ½” casing drilling

string was picked up to finish drilling the production section to final TD.

Shell accomplished its primary objective in the 6 ½” hole section with the MPD system – drill through the two depleted

sections and avoid losing returns in both. Accomplishing that objective allowed them to avoid the significant cost related to

the contingency 5 ½” liner drilling operations that would have been required if they had experienced loss circulation in eitherzone.

MPD with Casing Drilling – Bales 7

The target sand was still 700 feet below the previously drilled 6 ½” hole section and its pore pressure was expected to be

greater than the maximum already drilled by 1.5 ppg or more. That and the fact that the depletion levels were determined to be

as low as expected meant that the risk of loses in the production section would be too great with a conventional assembly.

The objective for MPD in this final section was to minimize the ECD to avoid losses and mange the gas. As in the previous 6½” hole section the MPD system was used to manage the ECD while drilling the well and hold the BHP constant during

connections. For contingency purposes, a rig pump was hooked up to the kill line to help manage the BHP and preserve the

trapped backpressure by injecting mud into the annulus during connections.

The plan for the lower part of the Bales 7 well was to drill-in with casing from the bottom of the 6 ½” open hole section down

to 11065 ft MD and to keep the well vertical. The static mud weight for the entire section was 15.7 ppg and the ECD was a

constant 16.2 ppg. However, even before the first connection was made, up to 1220 units of gas was already flowing from the

well. The gas volume steadily increased throughout the section rising as high as 1550 units towards the end of the section

(Figure 15).

In all, 13 pump transitions were made in this section during which the ECD was replaced by trapped backpressure controlled

by the automated MPD system. Of those transitions, 9 were for connections, 3 for rig pump failures, and 1 for top drive

maintenance. In spite of the gas the system was still able to manage a constant BHP within an average window throughout the

section of +/- 0.18 ppg (Figure 16).

Shell accomplished its primary objective with the 3 ½” casing drill string and automated pressure drilling system by avoiding

losses, managing high levels of continuous gas flow, and maintaining a constant ECD in the transition from drilling to

connections even with the high levels of gas.



SPE/IADC 130319 5

Managed Pressure Cementing – Bales 7

The final task was to cement the production tubing in place while preventing losses with the heavy weight cement. Shell

turned to the new MPD system to accomplish that objective by maintaining a constant BHP in the annulus during cementingoperations.

The cement job was modeled using a constant pump rate of 3 bbl/min for the entire process. Before tying into to the cement

head the rig circulated bottoms up until gains and losses were balanced at 3 bbl/min and the gas was circulated out of the

annulus. During the reduced pump rate the choke was tuned and then programmed to hold 90 psi of backpressure during thiscirculation phase. Once steady returns from the well were established the rig pump was shut down to hook up the cementing

unit to the cement head. During that procedure the system held the backpressure between 200 to 210 psi.

After a 5 bbl spacer was pumped the cement lines were pressure tested to 7500 psi for 5 minutes. From that point on, cement

pump transitions were managed in 1 bbl/min increments to allow time for the choke to adjust and manage the ECD at 16.2

ppg.

A closely controlled procedure was followed to regulate the backpressure for a fixed volume of fluid displaced into the drill

pipe (Figure 17). That procedure carefully governed the effect that the 16.2 ppg cement had on the ECD as it filled theannulus. Careful regulation of the reduction in backpressure with the cement pump rate and close cooperation between the

MPD and cementing crew resulted in a successful cement job without losses.

Summary

The PFWU 56 and Bales 7 wells were drilled with a new, modular automated pressure trapping system designed to manage

constant BHP in narrow windows without the use of an automated backpressure pump during conventional and casing drilling

operations and while cementing.

The system continuously managed pressure in over 4000 ft of open hole drilled in 2 different sections with conventional, liner

drilling and casing drilling assemblies and during over 50 pump transitions without failure. During connections made with the

3 ½” casing drill string the system demonstrated its ability to limit BHP fluctuations to +/- 0.18 ppg of a 16.2 ppg set point in a

directional well over 11000 ft deep even with high levels of gas flow.

Rig-up took only 7 hours which represents a significant time savings – over 60% compared to offshore systems.

With this system Shell was able to extend their use of casing drilling to other fields in South Texas, prevent loses in severelydepleted sands, and avoid the need for costly liner drilling contingencies.

AcknowledgementsThe authors acknowledge and thank their respective companies, Shell Exploration and Production and At Balance, for their

permission to publish this paper.

References1. Vogelsberg, P., “Liner Drilling with Managed Pressure Reduces Trouble in Depleted Sand Environment”, AADE

2009NTCE-10-02, presented at the 2009 National Technical Conference & Exhibition, New Orleans, La, 31 Mar.-3

Apr. 2009

2. Montilva, J., Fredericks, P., Sehsah, O., “ New Automated Control System Manages Pressure and Return Flow WhileDrilling and Cementing Casing in Depleted Onshore Field”, SPE 128923-PP presented at the SPE Drilling

Conference and Exhibition, New Orleans, La, USA, 2 – 4 February 2010



6 SPE/IADC 130319-

Figure 1: Map of South Texas showing location of the McAllen-Pharr fields (images courtesy of Texas RR Commission and

Shell)

Figure 2: Photo of the type of offshore MPD system used by Shell in the GOM. The photo on the left shows the manifold,

backpressure pump, and Coriolis flow meter. On the right the photo shows the pressure relief choke installed at the wellhead.



SPE/IADC 130319 7

Figure 3: On left - close-up photo of a skid mounted choke manifold. The choke labeled AC 3 is the optional pressure relief

choke that can be installed in the 3rd

overhead leg which was removed from the new manifold to simplify the design. On right -

3D drawing of the new modular manifold showing the location of the redundant chokes and other components.

Figure 4: Photo of the new system rigged-up on the PFWU 56 well in South Texas. It includes a Coriolis flow meter, PLC,

HPU, and backpressure pump.

Figure 5: Photo of the new system without the backpressure pump rigged-up on the Bales 7 well. This photo highlights the

small footprint and simplified installation of the new system.



8 SPE/IADC 130319

Figure 6: Schematic of the liner drilling assembly used to drill the 8-1/2” hole in PFWU 56.

Figure 7: Pressure profile for PFWU 56 well.

Figure 8: Plot of pressures recorded during the first connection in which the system managed BHP with automated pressure

trapping control.

0

50

100

150

200

250

300

14.5

15.0

15.5

16.0

16.5

17.0

17.5

7 : 0 4

7 : 0 5

7 : 0 6

7 : 0 7

7 : 0 8

7 : 0 9

7 : 1 0

7 : 1 1

7 : 1 2

7 : 1 3

7 : 1 4

7 : 1 5

7 : 1 6

7 : 1 7

7 : 1 8

7 : 1 9

7 : 2 0

7 : 2 1

7 : 2 2

7 : 2 3

7 : 2 4

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 )

First Connection Made with Automated Pressure Trapping

ECD SP ECD Model Backpressure PV Backpressure SP Flow In



SPE/IADC 130319 9

Figure 9: Plot showing kick detected by the new system on PFWU 56 well.

Figure 10: Plot of gas influx being circulated through the MPD system and the well being stabilized at 148 gpm and 150 psi of

backpressure.

Figure 11: Casing and hole size plan for the Bales 7 well. The modular automated pressure trapping system was used to drill 6

½” open hole with no losses which allowed Shell to avoid the cost of the 5 ½” contingency liner drilling string. The new MPD



10 SPE/IADC 130319

system was also used with the 3 ½” casing string to drill the production section to TD with no losses.

Figure 12: Vertical section plot for the Bales 7 well highlighting the open hole sections below the 7 5/8” casing shoe in which

the pressure was managed by the MPD system.

Figure 13: Plot of ECD from one 24 hour period during which the MPD system continuously managed backpressure to controlthe ECD.



SPE/IADC 130319 11

Figure 14: Pressure plot highlighting the pump transitions at the start and end of a connection and the min and maxfluctuations that occur during pumps off and on. During this connection the ECD window was 0.4 ppg (+/- 0.2 ppg).

Figure 15: Increasing gas flow from the well from the start of drilling with 3 ½” casing.

Pump transition

Pump transition

Max ECD 14.5 ppg

Min ECD 14 .1 ppg

10400

10500

10600

10700

10800

10900

11000

11100900

1000

1100

1200

1300

1400

1500

1600

1 9 : 0 0

2 1 : 3 0

0 : 0 0

2 : 3 0

5 : 0 0

7 : 3 0

1 0 : 0 0

1 2 : 3 0

1 5 : 0 0

1 7 : 3 0

2 0 : 0 0

2 2 : 3 0

1 : 0 0

3 : 3 0

6 : 0 0

8 : 3 0

1 1 : 0 0

1 3 : 3 0

1 6 : 0 0

1 8 : 3 0

2 1 : 0 0

2 3 : 3 0

2 : 0 0

4 : 3 0

7 : 0 0

9 : 3 0

1 2 : 0 0

1 4 : 3 0

1 7 : 0 0

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

G a s

U n i t s

Time (hr:min)

Onshore So TX - Bales 7Plot of Drill Gas

Gas Units Bit Depth



12 SPE/IADC 130319

Figure 16: Connection plot from the 3 ½” casing drilling operation. It shows the min/max window for ECD during this

connection was 0.3 ppg (+/- 0.15 ppg). The slowly rising backpressure is due to the steady flow of gas from the well.

Figure 17: During cementing operations for the 3 ½” drilled-in casing the MPD system controlled the ECD between 16 ppg

and 15.85 ppg by regulating the backpressure with the rate at which the cement was displaced in the drill pipe.

0

50

100

150

200

250

300

350

400

14.5

15.0

15.5

16.0

16.5

0 : 4 1

0 : 4 2

0 : 4 3

0 : 4 4

0 : 4 5

0 : 4 6

0 : 4 7

0 : 4 8

0 : 4 9

0 : 5 0

0 : 5 1

0 : 5 2

0 : 5 3

0 : 5 4

0 : 5 5

0 : 5 6

0 : 5 7

0 : 5 8

0 : 5 9

1 : 0 0

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 )

Bales 7 - Connection 8

Drilling w/3.5" Csg, Constant BHP w/1400 units (28%) Gas

ECD Model (ppg) Backpressure SP (psi) Backpressure (psi) Flow In (gpm)

spe 130319 onshorempdandcementing

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