SPE 112651 WiredDrillPipeandMPD

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IADC/SPE 112651

Successful Implementation of First Closed Loop, Multiservice ControlSystem for Automated Pressure Management in a Shallow Gas WellOffshore MyanmarPaul Fredericks and Don Reitsma, SPE, At Balance; Tom Runggai and Neil Hudson, SPE, PETRONAS; RalfZaeper and Oliver Backhaus, SPE, Baker Hughes INTEQ; and Maximo Hernandez, SPE, IntelliServ Inc.

Copyright 2008, IADC/SPE Drilling Conference

This paper was prepared for presentation at the 2008 IADC/SPE Drilling Conference held in Orlando, Florida, U.S.A., 4–6March2008. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have notbeen reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily

reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of anypart of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print isrestricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright.

AbstractIn plans to explore the shallow gas potential of the Nagar prospect offshore the southern coast of Myanmar, PETRONAS had

to contend with a number of potentially high risk issues. The shallow nature of the hazardous prospect made kick detectionspeed and pressure control accuracy essential to avoid losing returns. Concerns about a weak casing shoe, a narrow drilling

margin, the inability to control bottom hole pressure (BHP) while circulating out gas, and the short response time needed,

demanded a solution before the shallow gas-bearing sands could be drilled safely from the available moored drill ship with its

conventional subsea equipment.

From flow modeling it was estimated that within 3 minutes the system and procedures would have to detect and shut-in agas influx, then commence circulating it out, all while controlling the BHP of a flowing, multiphase fluid within extremely

narrow safe limits. It was concluded that the Nagar well could only be safely drilled with a pressure management system that

could maintain BHP within +/- 15 psi while drilling and +/- 45 psi during connections and well control.In an industry search, PETRONAS learned that no system existed with the functionality needed, but by electing to

combine new and existing technologies from three separate providers they were the first to develop one that did.

This industry-first solution involved integrating elements of the technology developed for automated pressure control,

pressure while drilling (PWD), and high speed, drill string telemetry. Modifications had to be made to a number of elements,including the pressure control and PWD systems, to obtain the necessary functionality. Given the safety critical nature of the

drilling hazards, the modifications and system integration were first tested during simulated kicks with downhole nitrogen

injection, before drilling out the casing shoe. During testing on the rig and subsequent drilling operations, the integrated

system proved its ability to maintain a near constant BHP, with the accuracy and speed needed to safely and successfully drill

the Nagar prospect.

IntroductionThe Nagar-1 well is an exploration well located in block M16 in the Andaman Sea under more than 400 meters of water. A

map of the area and the location of the well are shown in Figure 1. PETRONAS identified this prospect from seismicsurveys as a possible source of gas production from several shallow gas bearing sands lying between 260 and 400 m below

the sea floor. As a wildcat well the drilling objective was to confirm the presence of hydrocarbons in the target zones and

like other wildcat areas there are no offset wells in close proximity to the proposed well location. The closest offset wells

were over 100 km away in less than 200 m of water.

Given the shallow depth of the relatively high pressured gas sands, geopressure control was a significant part of the riskassessment. The best estimates of pore pressure and fracture gradient were extrapolations from distant and widely scattered

offset data corrected for water depth, which established an uncertain foundation. The scattered nature of the data can be seen

in the fracture gradient plot in Figure 2. This uncertainty convinced PETRONAS to step the well away from the crest of thegas cap in an effort to find larger margins. Figure 3 shows a generalized cross section through the gas cap and the three



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locations that were being evaluated. A location was selected that would allow them to set the shoe in a part of the cap 100 m

below the crest where, based on their estimated pressure data illustrated in Figure 4, the margin would be about 200 psi.

In addition to the lack of geopressure data, the shallow depth of the target gas sands presented a well control problem thatis widely known in the industry. At such shallow depths there would be little time to conventionally detect a gas kick, let

alone respond to and contain it before entering the riser. It was estimated that within just minutes of a kick, the gas would

migrate the short distance to the mud line and enter the marine riser, forcing the well to be shut-in. The accumulation of gas

would likely break down the shoe before circulation commenced.

It was determined that once shut-in, the rig’s manually operated system would not be precise enough to control the pressure in the well based on calculated fluctuations between 150 - 200 psi from the desired value. With a margin of only

200 psi the pressure fluctuations would most certainly break down the shoe. Ideally the pressure could not fluctuate morethan +/- 50 psi while drilling.

In the worst case scenario, if the shoe broke down then potentially large volumes of gas would escape up around the

surface pipe and into the water column. This would endanger not only the well, the environment, and the rig, but could risk

loss of the entire reserves, since remedial operations to regain well control in such a shallow and extensive sand, in over 400m water depth, would certainly be problematic.

Several scenarios were modeled to evaluate the risk of a gas plume. This was particularly important because a moored

drill ship was going to be used which would not be capable of moving off location in a timely manner in the event a plume

occurred. In the worst case it was determined that a gas plume would not broach the surface in close proximity to the rig due

to currents and water temperature. However, being a moored drill ship and immobile, the rig was an ever centralconsideration in the risk assessment.

Even though the off-crest location of the proposed well improved the drillability of Nagar-1, shoe strength limitations still prevented any casing design from achieving what could be regarded as a reasonable kick tolerance. This was particularly

evident in view of the limited ability to accurately control shut-in pressure during a kick and avoid losses. There was also the

possibility of a weaker than expected surface casing shoe producing a narrower than expected margin. In addition, an

acceptably workable contingency plan for the moored drill ship could not be found. Approval of this project therefore hinged

on finding and implementing a solution to mitigate the risks and provide additional safeguards. One of the safeguards was todrill a small pilot hole prior to drilling the main hole section and confirm the pressure at the planned shoe depth. Reducing

the size of hole allowed for dynamic kill operations if gas was encountered.

SolutionAssured that in the worst case scenario personnel and equipment would not be at risk in the event of kick, a team was

assembled to prepare the drilling program and specifically develop the means to safely drill the well using dynamic BHP

control.

PETRONAS Well Engineering specified a solution that included:

•

Automated real-time pressure control while drilling, making connections, and during a kick• Micro kick detection

• Automated kick control

• Real time BHP readings

Recognizing that they could not get this from any conventional drilling system, and after considering all the availablesafeguards that could be put in place PETRONAS elected to use:

• Managed Pressure Drilling (MPD) for pressure control

• Pressure While Drilling (PWD) for accurate downhole pressure information

• High data rate, drill string telemetry to transmit BHP data in real time

• Coriolis flow meter and trending software for micro kick detection

• Controlled drilling to detect any influx as early as possibleOnce in place, these components would form a system that could monitor and respond quickly to actual downhole

fluctuations and more accurately control BHP during a kick. In addition to the modifications that had to be made to the MPD

system and the PWD tool to provide the functionality required for Nagar-1, concerns surrounding possible interface issues between the system components required resolution.

Project timing was tight, but as a result of considerable effort by all parties, PETRONAS became the first operator tocombine and use these technologies for closed-loop pressure control.

Planning and Preparation

Rig Survey

In preparation of this project two rig surveys were conducted by the MPD personnel, one while the drill ship was docked

in Singapore undergoing refurbishment and the other while it was on location in the Andaman Sea drilling an offset well.Rig surveys are used to assess a number of things including stack height and spacing required for RCD installation, establish

equipment locations that minimize flow line length and turns, identify piping tie-in points, map out piping paths, and locate



IADC/SPE 112651 3

mud supply and discharge points. Normally, only one rig site survey is necessary but the refurbishment work that was

underway in Singapore prevented completion of the required tasks. A second survey was performed on the rig while it was

on location in a nearby block drilling which actually provided better conditions for installation and rig up planning.

HAZID/HAZOP

Hazard Identification (HAZID) workshops were conducted in Yangon four months in advance of MPD operations during

which personnel reviewed the MPD system and operations, identified and defined the potential risks associated with the

Nagar drilling project, and wrote contingency response procedures. The top level threat was identified as a kick and the top

level consequence uncontrolled gas release to the surface.Managed Pressure Drilling on Nagar-1 represented a fundamental change to previous conventional operations.

Recognizing that HS&E hazards specific to MPD operations needed to be identified the associated risks were assessed and

reduction measures put in place to make them as low as reasonably achievable (ALARA).A Hazard and Operability (HAZOP) study of the key MPD operational phases and DAPC system was held only a short

three weeks before the start of drilling due to the constrained project time line.

There were four areas, or nodes, identified in the HAZOP, these were:

• From the RCD to the downstream, low pressure side of the MPD choke manifold

• From the low side of the MPD choke manifold to the three discharge points

a. Trip tank

b. Header boxc. Low side of the rig choke manifold

• Batch tank to the backpressure pump suction

• MPD system bypass valve (K1 in Figure 5) up to the high pressure side of the rig choke manifold

Training

Clearly defined drilling success criteria were developed during project planning based in part on known geological data.

These criteria established system and personnel performance goals, operating pressure window, and response times. Both theoperating equipment and personnel had to be ready and able to respond within the prescribed limits to safely drill Nagar-1.

Training was conducted at 3 levels:

In level 1 training a half day was devoted for an introductory course to educate project personnel about MPD operations

and the DAPC equipment.Level 2 training focused on the rig crew and others directly involved in execution. It was an interactive course designed

to provide greater detail about the DAPC system and its interfaces with the rig, the drill string telemetry network, and the

MWD tools. It also involved a full description of the interaction and communications between key service and rig personnel.

The purpose of level 3 training was to provide intensive training of field crew members. It was designed to demonstratethe DAPC system performance and functionality during simulated MPD operations and it coincided with the rig-site testing

and commissioning.

During the testing phase on the rig enough time was devoted to allow every crew member to work with the equipment.Pressure tests were conducted, different drilling and connection scenarios were performed, and multiple gas kick simulations

were performed by injecting nitrogen into the wellbore to certify the system’s ability to control constant BHP.

Commissioning was carried out safely and successfully.

Prior to drilling out the 13-3/8” shoe, minimum equipment performance criteria were established for a range of leak off

tests (LOTs) and mud weights. These formed the basis for practical rig-site workshops involving the drilling crew. The purpose of these sessions was to practice managed pressure drilling with the following requirements:

• Drilling margin 150 psi

• Expected LOT 10.6ppg EMW

• Mud weight 9.1 ppg

• Transient pressure BHP +/-70psi

• Steady state pressure BHP +/-30psi

Technology Components

Managed Pressure Drilling

Managed Pressure Drilling was selected because it was determined that a closed wellbore circulation system would

provide better kick control than a conventional open circulation system. In addition, MPD would provide the means to

maintain the BHP at the desired constant level during the drilling operation. The MPD system consisted of several integratedcomponents, described below. Figure 5 illustrates the MPD interconnecting piping diagram used on Nagar-1.

Dynamic Annul ar Pressure Control (DAPC) System

Constant BHP control was provided by the DAPC system1. This is a fully automated system that applies a calculated,

controlled amount of backpressure to the surface annulus to maintain the BHP at a specified set point in the well, which for



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Nagar-1 was the casing shoe. It consists of an integrated pressure manager (IPM), real-time hydraulics model, choke

manifold, automated backpressure pump, and Coriolis flow meter. Figure 6 is a schematic of the DAPC system components

and Figure 7, a photograph of its components positioned on the drill ship.

I ntegrated Pressure Manager

Pressure measurement, monitoring, backpressure calculation, and kick detection are performed by the Integrated Pressure

Manager (IPM). The IPM consists of a control computer with a Human Machine Interface (HMI), programmable logic

control system, real-time hydraulics model, and data communications network. Maintaining the BHP at the set point at all

times is the pressure manager’s most important task. The set point is the pressure control point at a specific depth in the well- it guides the pressure manager’s every action - and in Nagar-1 it was located at the casing shoe. In response to BHP

fluctuations from the set point the IPM automatically adjusts the choke position and if necessary turns on the backpressure

pump.

Real-time Hydraul ics Model

This is a key component of the DAPC system. It calculates the BHP and other hydraulics data using manually enteredinformation and real-time drilling data. In normal drilling mode the model calculates flow and pressure every second and

calibrates itself every time it receives PWD data. As the PWD update rate increases so does calibration frequency and model

accuracy.Accurate in low compressibility, single phase fluids the model was ideal for steady state drilling with water-based mud in

Nagar-1. However, in the event of a high volume influx of gas the mud would become a compressible, dual phase fluid,

creating a scenario in which the model would lose accuracy. Any loss of accuracy was unacceptable for this project because

it would affect the system’s ability to control pressure during a kick and protect the shoe. A contingency was put in place to prevent this from happening which required the use of the high speed drill string telemetry network.

This contingency required the DAPC system provider to make two modifications to the IPM. One allowed the model to

use the steady stream of PWD from the wired pipe for near continuous calibration while drilling. Another allowed the IPM

to switch from using model data to PWD data in the event of a kick to preserve its ability to accurately control the BHP and protect the shoe.

Choke Manifold

Controlled by the IPM the DAPC choke manifold is used to make continuous adjustments to the backpressure to maintain

the BHP at the programmed set point. The manifold used on Nagar-1 consisted of two primary 4” hydraulic choke legs andone 2” auxiliary hydraulic choke leg. Normally, only one primary choke is active, the other acts as a backup – a redundant

feature of the manifold.

All three chokes are hydraulically gear driven, mechanical position chokes activated by a hydraulic power unit (HPU) on

the manifold. Another redundant feature of the manifold allows the HPU to be powered from multiple sources in case of

malfunction or failure.Primary electrical power was supplied by a separate generator and secondary power by a standby generator. Rig

electrical power was not used due to conditioning and the length of power cable required. Primary power was always

maintained on Nagar-1, the backup was never used.The rig’s well control manifold was connected in parallel for backup manual choke control (refer to Figure 5).

Backpr essure Pump

Like the manifold, the DAPC backpressure pump is controlled by the IPM which continuously monitors return flow. The

IPM uses flow limits to know when to turn on the backpressure pump before the flow rate drops below the choke control

level. The pump used on Nagar was a triplex pump rated to supply 50 gpm to the manifold through a direct connection to the2” auxiliary choke leg.

On-demand backpressure supply is a dynamic means to actively stabilize the BHP during connections, from rig pumps-on

to rig pumps-off and back, or any event in which the rig pumps are shut down. The pump was also essential on Nagar-1 to back fill the riser choke line while removing the gas kick.

The cement pump was connected in line with the backpressure pump to act as a backup (refer to Figure 5). It was testedand confirmed to provide the necessary stable flow rate. High flow rates were tested with the cement pump which placed the

choke in a more stable part of the CV curve. However, high flow was unnecessary because it did not increase theeffectiveness of choke control, in large part due to the precise control exhibited by the IPM.

Rotating Control H ead

Managed Pressure Drilling uses a closed wellbore circulation system in which drilling fluid returns to the surface and

flows out of the well under pressure. A rotating control device (RCD) installed on the riser seals the annulus, diverts flow,

and supports continuously applied shut-in pressure during static and dynamic modes.On Nagar-1, Weatherford provided a Williams 9000 rotating control device with a pressure rating of 1,000 psi static and

500 psi dynamic pressure. Figure 8 shows the RCD installed on the riser. Prior to installation the riser was modified to

increase its pressure rating – the top seals were removed from the slip joint and with the slip joint in the collapsed position



IADC/SPE 112651 5

the inner and outer barrels were welded in place. Heave motion, for the most part, was minimal (less than 2-3 ft) though it

did interfere with RCD bearing replacement once, during unusually high seas.

The RCD was connected to two diverter lines one for closed and the other for open circulation. For pressure control thedrilling returns were circulated through the closed diverter to the DAPC choke. The second diverter was in place to circulate

open returns to the trip tank or allow mud to be pumped into the annulus to keep the hole full. During system testing and

certification on rig the RCD and riser were pressure tested to 300 psi.

Coriolis Fl ow Meter

Using the system described, the Driller would not be able to see a kick occurring during connections because the backpressure pump would be on.

Precise kick detection was required around the clock, while drilling, during connections, and at any time the pump rate

was being changed up or down. Because the PWD tool could not be used to identify a minor influx a precise flowmeasurement was required.

There was such a small difference between static and dynamic pressure that an influx was just as likely to occur during

one or the other conditions. A Coriolis flow meter capable of detecting small changes in flow was installed downstream of

the choke manifold to monitor flow out of the well. The Coriolis flow meter is shown Figure 9 rigged up near the moon pool.

Micro Kick Detection & Control

Shallow gas is a well known hazard which is normally avoided whenever possible. However, for the Nagar-1 well,

shallow gas bearing sands were themselves the target. This demanded mitigation of the potential risk of breaking down the

shoe and allowing a large volume of gas to enter the riser. To avoid this PETRONAS selected a system that would identify

kicks and allow them to shut-in and control the well within a very short period of time. Hydraulic modeling of potentialinflux rates indicated that within 8 minutes of kick initiation the kick would have to be detected, the well shut-in, and well

control operations started to prevent an appreciable amount of gas from entering the riser and breaking down the shoe.

Pressure while drilling data is often used for kick detection. However in a large bore, shallow well like Nagar-1, a PWD

tool would not be able to detect an influx of a few gallons per minute because the pressure drop would be so small. So, foraccurate detection of a small volume kick it was decided to monitor flow out with a meter capable of detecting small changes

in flow and compare it to flow in. This method is commonly used in slim hole wells to identify influx rates as small as 1

gpm.In Nagar-1, the average change in the flow (flow system noise) was about +/- 3 gpm, due to a small amount of heave,

flow variation from the rig’s triplex pumps, the shallow depth, controlled drilling, and the water based mud system. Kick

levels were set in the IPM to filter out the flow noise and to issue alarms at any point above or below the flow noise level.

Effectively, this allowed the system to detect an influx volume of 1 gpm. Kick detection was tested and confirmed using asecond rig pump to simulate an influx and during nitrogen gas migration and expansion. As part of the kick detection

training, the system operator was not notified beforehand of the impending test and had to respond as if the kick was real.

In addition to kick detection, PETRONAS wanted a method to maintain BHP above pore pressure and safely remove anygas from the well. A modified volumetric kill method was developed using the DAPC system and real-time PWD data to

bleed and lubricate the gas flowing out of the well while maintaining a constant BHP at the required level above pore pressure. This method simplified the well control process because the Driller only had to follow the line up procedure

without engaging the rig pumps which could have introduced pressure transients into the system.

Kick simulation testing using injected nitrogen gas was performed to confirm and practice the volumetric kill method.During the simulations, while the gas migrated to the surface the mud was diverted through the choke line and bled off

through the DAPC choke manifold. The pressure manager controlled the backpressure at the levels required to maintain a

constant BHP (within the +/- 15 psi window) while allowing the gas to expand. A plot of one of the nitrogen tests is pictured

in Figure 10. It indicates the sequential phase of the test and shows the ability of the closed-loop system to maintain aconstant BHP.

Pressure buildup levels were monitored continuously to determine when the nitrogen gas was no longer migrating to the

surface. At that point the well was isolated by closing the BOP fail safe valves, effectively trapping the remaining gas in the

choke line. From there, the remaining gas was bled off to the atmosphere and replaced with mud using the system’s backpressure pump. The process was repeated if evidence indicated the presence of additional gas below the BOPs.

Nitrogen testing was carried out with all service and rig personnel several times to ensure all parties involved were

familiar with their roles and responsibilities. The volumetric kill method proved to be an accurate method for controlling akick.

Pressure While Drilling

For accurate downhole pressure information, it was obvious that pressure while drilling (PWD) would be required. The

unique application of controlling pressure during a kick with PWD required an MWD tool that could provide the DAPC

system a real-time, continuous stream of annular pressure measured every 2 seconds. There were two additional

requirements the MWD system had to satisfy for this application. One was the ability to provide and select at will a separate



6 IADC/SPE 112651

battery supplied power source when there was no mud circulation and the other was the ability to reprogram the MWD tool’s

processor without tripping out of the hole.

PETRONAS elected to go with a commercial MWD architecture that satisfied these requirements and provided a pressuresensor that could detect changes of 1 psi at the given conditions. In addition to pressure, the MWD tool also measured

resistivity, gamma ray, downhole temperature, as well as borehole direction and inclination. Figure 11 illustrates the features

of this MWD tool.

The MWD service provider was able to mobilize under the short lead time imposed by the project’s operating window

because it already had a proven drill string telemetry interface sub which it started developing in 2003. This sub wasspecially developed to condition downhole data and connect it to the drill string telemetry network.

It was important to ensure that power would be available when it would be needed most, during well control. To satisfythis requirement, separate power sources were supplied: a modular Bi-directional Communication and Power Module

(BCPM) and Smart Battery Sub (SBS). Power was provided by the turbine generator in the BCPM module when mud flow

rate was high enough to run the turbine and by the battery sub when mud flow dropped or stopped completely. A

modification was required to enable the MWD operator to access the BHA and switch from turbine to battery power duringcritical phases of the well. This conserved the batteries and ensured a reliable source of power during no-flow conditions. In

addition, the modification allowed the MWD operator to reprogram the downhole tool settings over the drill string network

ensuring a continuous supply of PWD data to the DAPC system.

Overall latency from time of acquisition until feed into the DAPC system was between 2 – 4 seconds during drilling using

standard data acquisition and distribution architecture. In contrast, under normal mud pulse telemetry circumstances, pressure updates are usually stored to the downhole memory every 20 seconds and typically transmitted every 40 seconds.

Before being shipped to the job site, the complete MWD bottom hole assembly (BHA) was built and tested in Celle,Germany consisting of:

• 6¾ inch MWD tool run directly above the bit sub and bit

• Mud flow power generation sub

• Smart battery sub

• Interface sub linking the BHA to the telemetry drill string network.

The MWD tool was placed directly above the bit sub which put the pressure sensors only 7.3 ft away from the face of the bit. The rest of the BHA consisted of the BCPM, the SBS above it, followed by the interface sub on top which connected to

the 5” wire pipe. A schematic of the MWD BHA is illustrated in Figure 11.

In turning to PWD for accurate downhole pressure data, it was necessary to overcome the limitations of commontelemetry techniques. Even though the PWD tool can use battery power to measure and record pressure when the pumps are

off, a mud pulse telemetry system can transmit real-time data only when mud is circulating at the appropriate flow rate. In

addition, real-time data transmission is limited with mud pulse telemetry as is alternative electromagnetic transmission which

has almost the same bandwidth restrictions.

To overcome the limitations of mud pulse telemetry PETRONAS turned to a drill string telemetry network, or wired pipe,that provided high bandwidth, bi-directional data, circulating or not. Wired pipe not only provided the means to transmit

frequent pressure updates it also provided an interactive communication channel between surface and downhole which

allowed battery power to be conserved by turning them on only when needed - before critical pressure zones and during kickcontrol.

The decision to use wired pipe for high speed, real-time pressure measurements dictated a change of MWD service

companies because the current supplier was unable to provide a downhole interface sub to connect to and transmit data overthe drill string telemetry network. This, in turn presented significant contractual and logistical issues.

Drill String Telemetry

PETRONAS elected to use the IntelliServ Network, a drill string telemetry network, to overcome the limitations of

conventional mud pulse telemetry under no-flow or low-flow circulation. The network utilized modified drilling tubulars

that incorporated a high strength coaxial cable encapsulated within a pressure sealed, stainless steel conduit running the

length of each joint. Each drill pipe in the network contains two low-loss inductive coils embedded in double-shoulderedconnections, linked by the cable - one coil installed in the pin nose and another in the box shoulder.

When two connections are threaded together the pin end coil in one joint is brought into close proximity with the box end

coil of another. Data is passed from one coil to another by the electromagnetic (EM) field associated with the alternatingcurrent (AC) signal transmitted along the cable. As the alternating EM field from one coil induces an AC signal in the

nearby coil it passes data from one joint to the next.

The drill string BHA included 5", 19.50 pound, grade S-135, range 2 pipe with 6 5/8” regular connections. It also

included 5", tri-spiral, grade 95 heavy weight drill pipe and 6.5” x 3” drill collars. In addition, link subs were installed at

regular intervals in the drill string to boost the signal. On the surface, a swivel sub was installed in the top drive whichextracted the downhole signal and routed it to the surface network controller which in turn routed it to the MWD surface

system for decoding and processing2.



IADC/SPE 112651 7

Data speed was essential in Nagar-1 due to the shallow depth of the gas - minutes meant the difference between gaining

and losing control in the event of gas kick. This drill string telemetry network enabled high speed transmission of annular

BHP and ECD data to the surface from the downhole PWD tool and reduced the inherent lag time of mud pulse telemetry.The network’s architecture supported bi-directional data communication at speeds up to 57,600 bits per second which at one

point early in the well enabled the MWD tool to be reprogrammed from the surface for faster pressure updates. This

eliminated the need to trip the MWD BHA out of the hole.

No special handling or make-up procedures were required and standard thread compound was used. Other than a higher

make-up torque, the drill string exhibited the same mechanical and hydraulic properties, and were handled in the same way as previously used standard, double shouldered, drilling tubulars.

The key physical components of the wired drill pipe connection are illustrated in Figure 12.

Data Communication and Interfaces

Timely, accurate drilling data were essential to this project given the shallow depth of the potential hazard, the narrow

pressure margin at the shoe, and the speed with which adjustments would have to be made in the event of a gas kick.

In consideration of the speed that would be needed PETRONAS asked the DAPC system provider to speed up its

response. The model is capable of making hydraulics calculations more than once a second. The integrated pressure

manager uses the reference set point to make backpressure adjustments with only occasional updates from the PWD.However, by modifying the pressure manager to accept real-time PWD data the model would be continuously calibrated,

ensuring the most accurate calculations and adjustments while drilling.

Accurate control requires a timely flow of pump stroke data for the IPM to maintain constant BHP. This is the primaryindicator that the pumps are working, mud is flowing, and there is ECD in the well. A delay in this data results in delayed

calculation of choke position and backpressure. Regularly updated drilling parameters and real-time data from the PWD toolwere transmitted from the well data logging system to the IPM.

Figure 13 illustrates the data flow in the surface network. Downhole pressure data passed through the drill string to thenetwork controller which routed it to the MWD database on a RS232/DB9 cable. From there the annular pressure and

equivalent circulating density were sent to the data logger RTG machine and the DAPC controller. The RTG machine

distributed the data and surface sensor data over a TCP/IP using WITS level 0 protocol to all the connected computers.

During testing on the rig, delays of up to 30 seconds were observed in the pump stroke signal being fed to the IPM, which prevented it from maintaining BHP within the required +/- 30 psi margin. The rig pump stroke rate is the IPM’s primary

indicator that the pumps are working, mud is flowing, and there is ECD in the well. Investigation showed that these were a

result of the increasing buffer size in the well data logger system used to monitor the rig data. Although such delays arecompletely acceptable for normal data logging and acquisition purposes, accurate pressure control required a timely flow of

accurate data on which the IPM relies to maintain constant BHP.

One of the failsafe features of the DAPC system allows the control system technician to enter the stroke rate manually if

all rig data is severed. This was used to work around the pump stroke delay and allow the hydraulics model to provide thenecessary calculated data to the IPM, which could then continue to generate the required backpressure set point for BHP

control. It was not a satisfactory long-term solution even though it was used several times. After trying to resolve the delay

within the well data logger system it was decided to transmit the pump stroke signal directly to the high speed counters in the

DAPC system’s PLC.

A signal delay was also discovered during the initial kick simulation test with nitrogen, which again effected the pressuremanager response time. It is standard for the MWD processor to buffer the measured data in memory prior to transmitting

selected values to the surface via mud pulse telemetry. The MWD downhole programming and surface setup was notoptimized for this project until the impact of the PWD delay was felt during the first kick simulation. Data buffering created

delays of up 90 seconds in the transmission of the PWD WITS stream which prevented the DAPC system from using it for

pressure control.

Figure 14 shows a pressure plot of the measured delay. In the plot, the red line is the surface pressure measured by the

IPM and the blue line the downhole pressure measured by the PWD tool. The issue was resolved by reprogramming theMWD tool over the drill string telemetry network. Table 1 shows the results of ramp up/down tests before and after

programming changes and the subsequent improvements. Tests 1 to 3 were made before software changes, tests 4 and 5 after

the first software change, and tests 6 to 8 were after the second change. Figure 15 is a plot of the surface backpressure

compared to bottom hole pressure from the PWD tool during one of the last connections made on the job. It highlights thevery small delay that the closed-loop system was able to achieve between surface and downhole.

System TestingThe novel and safety-critical nature of the system demanded that it was thoroughly tested and proven on the rig before

use. PETRONAS management approval for drilling the target hole section was conditional upon the satisfactory outcome ofthese tests.



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Certain aspects of system testing would normally have been completed before going offshore, during a yard trial3.

However, the compressed timeline for the project did not allow enough time for this. Separately, the modifications made to

the DAPC system and the MWD BHA components were each tested before being mobilized from their home bases.Prior to drilling out of the 13-3/8” casing shoe, about a week’s worth of rig time was spent testing and commissioning the

integrated system, training the crew on MPD and kick operations, and conditioning the mud. Testing and commissioning

involved injecting different amounts of N2 down the drill string to test the closed loop ability of the DAPC system, PWD,

and the drill string network to work together to detect the kick and control the BHP at the set point.

DrillingA 13 ⅜” casing string was set in the cap rock immediately above the target sand. The shoe was drilled out and a leak off

test was conducted to 10.1 ppg. Afterwards, drilling commenced for the 8 ½” pilot hole at a measured depth of 680 m with

9.0 ppg static mud. The equivalent circulating density was estimated at 9.6 ppg. To stay within the target BHP margin, theset point for the DAPC system was set at 1075 psi at 676.5m, MD. Surface pressure loss was approximately 70 psi with the

drill rate controlled at 5 m per hour and the flow rate at 450 gpm through the 4” choke 100% open.

At the start of drilling, debris in the mud system blocked the primary choke. After switching to the backup choke it too

became partially blocked. Eventually, the debris was cleaned from the system and drilling proceeded with no further choke

plugging. The backup choke was always kept 100% open to simplify and speed up choke switching.In the DAPC system used on Nagar-1 return mud flowed through one of the 4” chokes and mud from the backpressure

pump flowed through the auxiliary choke leg. In this version the IPM isolates the primary chokes and uses the auxiliary

choke to manage pressure during a connection. The system maintained the BHP at the 13 3/8” shoe within +/-15 psi whiledrilling and +/-45 psi during connections. Figure 15 illustrates the pressure windows within which the system maintained the

BHP.Total depth was reached with no well control events. At TD the mud was weighted up to 9.4 ppg in preparation to trip

out and run wireline logs.

ConclusionThe results of advanced well flow modeling performed by PETRONAS during their initial evaluation of the system

showed that it was necessary to have early kick detection and timely processes to shut in and control the well and maintain

the integrity of the shoe.The rig pump ramp-down and ramp-up speeds that were established during testing and followed throughout the drilling

operation allowed the DAPC system to manage the choke position and maintain the BHP in the prescribed window.

Improving data quality made it possible to reduce the pump ramp times to less than 2 minutes while still maintaining BHP

within the prescribed pressure window of +/- 50 psi.Equipment commissioning and thorough crew training ensured that the system operated as prescribed, drilling proceeded

in a safe and timely manner, and that the project’s objectives were met. With no prior MPD experience it was imperative that

the rig crew and company supervisors became familiar with MPD operations, the kick detection being employed, and therevised well control procedures that would be followed in the event of a kick. Multi-level training proved to be invaluable in

providing the necessary level of familiarity with MPD operations and practice with actual kick control procedures.PETRONAS reduced their risks in Nagar-1 to a level that was as low as reasonably achievable through proper planning

and preparation, and the innovative integration of automated pressure control, drill string telemetry, and PWD technology.

This integrated system demonstrated that closed-loop pressure control is a workable, practical solution to maintainconstant BHP at a prescribed value during shallow kick control and can provide the necessary safe guards to drill shallow gas

or other pressure hazards.

PETRONAS could not have drilled Nagar-1 without this jointly operated pressure management system. The complexity

of the system required close cooperation and team work between the providers, and it was clearly acknowledged that thesuccess of the operation owed much to the professionalism and enthusiasm of the companies and individuals involved.

Lessons Learned1. Several high viscosity sweeps failed to remove all the float shoe and wiper plug rubber from the well which

plugged the chokes during initial kick tests. It also occurred while drilling the first few meters of new hole. TheDriller mistakenly interpreted the increase in BHP as a kick even though there was no change in flow-out compared

to flow-in. The lessons to be learned from this are:

a. Circulate a complete bottoms up preferably through the choke line to clean the hole before drilling ahead

b. Give the Driller the means to compare delta flow and BHP by either installing a delta flow gauge on the drillfloor or display delta flow on the Driller’s data monitor

2. Pump stroke signals should be an independent device fed directly to the IPM. WITS or other communications

protocols where pump data can be obtained should be used for data confirmation purposes only.

3. Given the time constraints on this project and its remote location it was not possible to do a full yard trial of the

entire closed-loop pressure control system (MPD, PWD, Wired Pipe, Data). Testing this equipment prior to arrivalon the rig would have significantly reduced rig time and costs.



IADC/SPE 112651 9

4. Training should start earlier and more training time should be allotted for the rig crew away from the rig. This

should be a special consideration for a crew completely unfamiliar with MPD and when the training is being done

in a language that is not native to the people being trained.5. Consider electrical power carefully in a critical operation like this. A dedicated generator was used to power the

DAPC and drill string telemetry systems. This proved beneficial because even though the usual highly variable

quality of the rig power proved sufficient to sustain drilling operations it proved problematic to the equipment of

other service providers.

6. Improvements to the DAPC system were identified during internal, post-well after action reviews. Some of themore important ones which have already been implemented include:

a. The ability to actively control pressure with all three chokes at any time to better manage and mitigate theaffects of pressure spikes

b. The ability to use the auxiliary choke as a dynamic pressure relief valve to eliminate the sudden pressure

changes that occur with POP type valves

c. Primary pump monitoring sensor signals are wired directly into the IPM PLC; 3rd party data is used as backup

d. As a result of the problems encountered with the stroke counter a flow differential alarm was set in the

DAPC system to detect interruptions to the stroke sensor signal and data communications

e. Backup stroke counters are now being used with the DAPC system on all jobs

AcknowledgementsAt Balance, IntelliServ, and Baker Hughes INTEQ thank PETRONAS for their patience and positive attitude during the

planning and execution of this industry first project. We also want to give special recognition to the PETRONAS drillingstaff that had the foresight to pursue and implement a leading edge technology solution that few would do but from which all

companies will benefit.Acknowledgment is also due to the many individuals who contributed valuable effort to make this a successful project

including Henk Boer, Deepwater Drilling Superintendent, PETRONAS, Zulkarnain Ismail and Charles Stirrett, PETRONAS;

Russell Morris, At Balance; Aravindh Kaniappan, Aimran Ratim, Andreas Peter, and Dave Taylor, Baker Hughes INTEQ;

Lamar Farnsworth, Mike Reeves, and David Fish, IntelliServ Inc.;The authors thank PETRONAS for their permission to publish this paper.

References1. van Riet, E.J., et al (2003): “Development and Testing of a Fully Automate System to Accurately Control Downhole

Pressure During Drilling Operations” SPE 85310 presented at SPE/IADC Middle East Drilling TechnologyConference & Exhibition held in Abu Dhabi, UAE, 20-22 October 2003

2. Reeves, M., et al (2006): “High-Speed Drill String Telemetry Network Enables New Real-Time Drilling and

Measurement Technologies” IADC/SPE 99134-MS presented at the IADC/SPE Drilling Conference, 21-23February 2006, Miami, Florida, USA

3. Chustz, M., et al (2007): “Managed Pressure Drilling with Dynamic Annular Pressure Control System ProvesSuccessful in Redevelopment Program on Auger TLP in Deepwater Gulf of Mexico” SPE 108348 presented at

IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference in Galveston, Texas, 28-29

March 2007



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Figure 1- Map illustrating location of Nagar-1 in block M-16 offshore Myanmar. Detail image on right shows closest offset M15B-1which is over 100km away.

Figure 2- Fracture Gradient plot derived from the LOTs obtained in the offset wells, corrected for the water depth at the Nagar-1location. The scatter created an uncertain foundation for geopressure control in Nagar-1.



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Figure 3- Schematic illustration of cross section through survey area showing the three well locations considered relative to thecrest of the gas cap. Nagar-1_Opt3 was the final location where the 20” shoe was set approximately 100 m below the top of thecrest.

Figure 4- A minimum required formation strength can be calculated with a given gas column. It was determined that by setting thecasing shoe away from the crest and drilling the well into the cap 100m below, they could achieve an acceptable 195 psi margin.



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Figure 5- Simplified illustration of the piping and instrumentation for the MPD setup on Nagar-1. The section highlighted in yellowrepresents the DAPC system, and in gray the contingency backups.

Figure 6- Diagrammatic illustration showing the main components of the DAPC system.



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Figure 7- Picture of the DAPC system rigged up on the drill ship drilling Nagar-1.

Figure 8- Picture of the rotating control device used on Nagar-1, in place on the riser.



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Figure 9- This photo shows the Coriolis flow meter rigged up down stream from the choke manifold next to the moon pool on thedrill ship.

Figure 10-Pressure plot of nitrogen test of the closed loop system. BHP held constant during the kick.



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Figure 11- Illustration of the MWD bottom hole assembly showing the key components used while drilling Nagar-1.

Figure 12- Illustration of the telemetry drill pipe connection features.



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Figure 13-Surface data network illustrating the flow path (in red) of PWD data from downhole to the DAPC controller. Surface datawas collected and distributed by the well data logger which initially included pump strokes, which were later re-routed direct to thecontroller.

Figure 14-Pressure plot highlighting the delay seen between the surface pressure and the PWD downhole pressure.



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Figure 16-Plot of bottom hole pressure managed while drilling and during connections, showing the windows within which theclosed-loop system maintained the BHP.

SPE 112651 WiredDrillPipeandMPD

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