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Chapter

Managed Pressure Drilling and

Cementing and Optimizing with
Digital Solutions
Behzad Elahifar

Abstract

This manuscript provides a comprehensive examination of cutting-edge drilling

technologies and their implications for the energy industry. Managed Pressure Dril-
ling (MPD) and Controlled Mud Level (CML) are meticulously dissected, uncovering
their techniques, equipment, and operational intricacies. Additionally, Managed Pres-
sure Cementing (MPC) is explored, showcasing the ingenious application of MPD
during cementing operations. The chapter then ventures into the realm of digitaliza-
tion and automation, highlighting the role of Wired Drill Pipe as a conduit for high-
speed data transmission, transforming drilling through real-time monitoring and
decision-making. The convergence of digitalization and automation with MPD and
CML systems is unveiled, elucidating how these technologies can create semi or fully
automated systems that optimize drilling processes, enhance accuracy, and reduce
nonproductive time (NPT). This manuscript invites readers on a journey into the
frontier of drilling technology, where innovation knows no bounds, and the future of
energy exploration and production is being reshaped.

Keywords: managed pressure drilling, controlled mud level, managed pressure

cementing, pressurized mud cap drilling, controlled mud cap drilling, digitalization

1. Introduction

In the ever-evolving landscape of drilling operations, two pioneering technologies

have risen to the forefront, promising enhanced control, efficiency, and safety: Man-
aged Pressure Drilling (MPD) and Controlled Mud Level (CML). This chapter
embarks on a comprehensive exploration of these groundbreaking techniques, their
respective equipment, and operational intricacies, delving deep into the core princi-
ples that underpin their success. MPD, a transformative approach that manages
wellbore pressure throughout the drilling process, is meticulously dissected to
uncover its techniques and instrumentation, while CML, a novel method to manipu-
late mud levels in the riser, is unraveled to illuminate its unique operational strategies.
Additionally, the chapter delves into the realm of MPC, an ingenious application of
MPD during cementing operations to mitigate losses and ensure cement placement
accuracy.
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Advances in Oil and Gas Well Engineering

Furthermore, we venture into the digital frontier where automation and high-
speed data transmission converge to revolutionize drilling. Wired drill pipes, acting as
the neural pathways of this digitalization, enable seamless communication between
downhole and surface, ushering in an era of real-time monitoring and decision-
making. The marriage of digitalization and automation with MPD and CML systems
forms the nucleus of our discussion, as we explore how these technologies can be
harnessed synergistically to create semi or fully automated systems that optimize
drilling processes, enhance accuracy, and ultimately reduce NPT. Join us on this
journey through the cutting-edge realms of drilling technology, where innovation
knows no bounds, and the future of energy exploration and production is being
reshaped before our very eyes.

2. Managed pressure drilling

Managed Pressure Drilling (MPD) is a drilling approach born out of the need to
combat the high costs associated with NPT caused by the precarious balance between
pore pressure and fracture pressure during drilling operations both onshore and
offshore drilling rigs.
MPD stands as an adaptable drilling technique deployed to regulate the annular
pressure configuration within the wellbore. Its primary aims encompass defining the
constraints of downhole pressure conditions and effectively orchestrating the
hydraulic pressure profile surrounding the annulus. Implicit in this definition is the
use of a single-phase drilling fluid treated to minimize flow friction losses.
Broadly speaking, Managed Pressure Drilling presents itself as a drilling approach
that empowers precise oversight of wellbore pressure dynamics.
MPD is a broad concept encompassing various strategies and equipment designed
to effectively control wellbore pressure. Its primary objectives are to prevent kicks,
lost circulation, and differential pressure sticking, all with the aim of reducing the
need for additional casing strings to reach the desired total depth.
This field of wellbore pressure management finds wide-ranging applications
within the drilling industry, offering solutions to issues like:

1. Reducing lost circulation occurrences.

2. Preventing the sequence of lost circulation followed by a kick.

3. Minimizing NPT associated with pipe differentially stuck.

4. Enabling drilling operations with total lost returns.

5. Enhancing drilling speed.

The primary objective of MPD is to prevent the continuous inflow of formation

fluids into the well [1]. Any unintended influx during operations is safely managed
through suitable processes. Additionally, MPD employs a range of tools and tech-
niques aimed at mitigating the risks and expenses linked to drilling wells with tight
mud window. This is achieved through proactive management of the annular
hydraulic pressure profile. MPD may encompass the control of various factors such as
back pressure, fluid density, fluid rheology, annular fluid level, circulating friction,
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Managed Pressure Drilling and Cementing and Optimizing with Digital Solutions
DOI: http://dx.doi.org/10.5772/intechopen.113287

hole geometry, or combinations thereof. MPD provides the advantage of swift

response to observed pressure variations, facilitating dynamic control of annular
pressures. This capability opens opportunities for drilling prospects that might other-
wise be economically unfeasible.

3. Managed pressure drilling techniques

There exist four primary iterations of MPD, each tailored to address specific
drilling hazards for which they have proven effective. Occasionally, multiple varia-
tions are combined for use on particularly challenging projects. This practice is antic-
ipated to become more common as the technology gains acceptance among drilling
decision-makers and as drilling prospects become progressively more intricate. The
four key MPD variations, along with their sub-categories detailing their application
areas and respective strengths, are as follows:

• Constant Bottom Hole Pressure (CBHP)

• Mud Cap Drilling (MCD)

◦ Pressurized Mud Cap Drilling (PMCD)

◦ Floating Mud Cap Drilling (FMCD)

• Dual Gradient Drilling (DGD)

◦ Riser-less Mud Recovery (RMR)

• Return Flow Control (RFC)

3.1 Constant bottom hole pressure

Many challenges in drilling and wellbore stability arise from the considerable fluctu-
ations in bottomhole pressure inherent in traditional drilling methods. These pressure
variations serve as the root causes of numerous cost overruns in conventional land-
drilling operations. These pressure spikes mainly occur during the start and stop of
circulation for making drill string connections in jointed-pipe operations. They specifi-
cally result from changes in equivalent circulating density (ECD) or annulus friction
pressure (AFP) when pumps are activated or deactivated. AFP contributes to
bottomhole pressure during circulation but vanishes when circulation ceases [2].
Constant Bottom Hole Pressure (CBHP) is the term typically used to describe
actions taken to correct or minimize the impact of circulating friction losses or ECD,
with the aim of staying within the boundaries set by pore pressure and fracture
pressure. To mitigate the effects of AFP or ECD, it’s crucial to grasp the concept of
backpressure (BP).

• Conventional Drilling:

◦ (During Drilling) Bottom Hole Pressure (BHP) = Hydrostatic Head of

Mud + AFP
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Advances in Oil and Gas Well Engineering

◦ (During Connection) Bottom Hole Pressure (BHP) = Hydrostatic Head of

Mud

• Managed Pressure Drilling:

◦ (During Drilling) Bottom Hole Pressure (BHP) = Hydrostatic Head of Mud +

AFP + BP

◦ (During Connection) Bottom Hole Pressure (BHP) = Hydrostatic Head of

Mud + New BP

In this approach, the objective is to closely follow the pore pressure line by
employing a fluid density that is closer to balance than conventional practices. This
strategy addresses challenges related to narrow margins between formation pore
pressure and fracture gradient, particularly when drilling ahead. Surface annulus
pressure remains nearly zero during drilling, but during shut-ins for jointed pipe
connections, a few hundred psi of backpressure is required. The use of backpressure
demonstrates the industry’s ability to utilize less dense drilling mud.
Figure 1 provides a simplified depiction of how ECD or Annulus Friction Loss
(AFL) can be compensated for. In theory, it’s possible to offset a decreasing amount of
AFL by simultaneously increasing Back Pressure (BP) when circulation stops,
enabling control of Bottomhole Pressure (BHP).
Although the main objective of the Constant Bottomhole Pressure Method (CBHP)
is to manage challenging pressure anomalies within the wellbore, the name might
suggest controlling the bottomhole pressure at the well’s base. Typically, lighter-than-
usual drilling fluids are used, resulting in a statically underbalanced hydrostatic col-
umn. The utilization of less dense mud exemplifies one of the management strengths
of MPD and highlights the application of this innovative concept.
MPD replaces the pressure exerted by static mud weight with dynamic friction
pressure to maintain well control while preventing fluid losses. The technique aims to
keep wellbore pressure within the range defined by the highest pressured formation’s

Figure 1.
ECD compensation during connection with MPD.

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Managed Pressure Drilling and Cementing and Optimizing with Digital Solutions
DOI: http://dx.doi.org/10.5772/intechopen.113287

pore pressure and the weakest formation’s fracture pressure. This is often
achieved by using a mud weight with a hydrostatic gradient lower than required to
balance the highest pore pressure, compensating for the difference through dynamic
friction during circulation. While it sounds straightforward, this process can be quite
complex.
The initial challenge lies in transitioning from static balance to dynamic (circulating)
balance without losing returns or encountering a kick. This can be achieved by gradually
reducing pump speed while simultaneously closing a surface choke to increase surface
annular pressure. The goal is to reach a point where the formation experiences the exact
pressure it encountered from ECD while circulating. It’s important to note that
bottomhole pressure remains constant at only one point in the annulus.
Various techniques have been employed to maintain constant bottomhole pressure
during the transition from dynamic to static (or vice versa). These methods include:

• Hydraulic models have been utilized to calculate an annulus pressure schedule to

follow while gradually reducing the pump rate.

• Computer-controlled chokes have been developed to automate the process of

adhering to the required pressure schedule.

• Circulating loops have been constructed with dedicated pumps to ensure

continuous surface circulation through a choke, facilitating precise control of
annular surface pressure.

• In some instances, a conventional rig pump has been repurposed as a dedicated

pump, offering the advantage of pump redundancy.

• Specialized equipment has been developed to sustain continuous circulation

through the drill string during connections, effectively eliminating the need for a
transition by preventing a static situation entirely.

With these methods, the well is typically never fully shut in, as any necessary
surface pressure is imposed through a partially closed choke.
In addition to surface equipment, during drilling operations, influx is prevented by
increasing annular friction pressure through pumping. During connections, drillers
manage influx by applying back pressure or by trapping pressure within the wellbore.
At the very least, a non-return valve (NRV) placed inside the drill string halts the flow
of mud up the drill pipe towards the surface [3].

3.2 Mud cap drilling

3.2.1 Pressurized mud cap drilling

PMCD, which stands for Pressurized Mud Cap Drilling, is a technique employed
for drilling while ensuring total loss returns. In PMCD, drilling takes place without
returning fluids to the surface, and a full annular fluid column is maintained above the
formation that receives injected fluid and drilled cuttings. Maintaining this annular
fluid column necessitates the application of observable surface pressure to balance the
downhole pressure.

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Advances in Oil and Gas Well Engineering

PMCD not only addresses lost circulation issues but does so by utilizing two
different drilling fluids. A heavy, viscous mud is pumped down the annular space on
the backside to a certain height, forming a mud cap that acts as a barrier. Simulta-
neously, the driller employs a lighter, less damaging, and cost-effective fluid to drill
into the weaker geological zones [3].
The driller pumps the lighter sacrificial fluid down the drill pipe. After circulating
around the drill bit, this fluid, along with cuttings, is injected into a zone located above
the last casing shoe, typically a weak zone. The heavy, viscous mud remains in the
annulus, forming a mud cap above the weak zone. If necessary, the driller can apply
backpressure to maintain control over annular pressure. This use of a lighter drilling
fluid enhances the Rate of Penetration (ROP) due to increased hydraulic power and
reduced chip hold-down.
The use of PMCD is contingent on experiencing total losses. These losses must be
significant enough to accommodate all the fluids pumped down the drill string and the
cuttings generated during drilling [4]. If circulation, even partial, is established, the
mud cap would be circulated out of the well, rendering PMCD unsuitable, and the
CBHP method would be the alternative.
Furthermore, unlike other methods, PMCD might be applied in situations where
total loss scenarios are not encountered, but total losses can be induced by altering the
wellbore pressure profile [4]. This variation is expected to be used in deepwater
drilling, particularly when drilling through heavily depleted pay zones to reach deeper
zones with virgin pressure. It enables safe drilling in cases where the depleted zone
above the target can accept the sacrificial fluid and drilled cuttings. The mud cap,
along with backpressure, directs the returns into the depleted zone above, the path of
least resistance (Figure 2).
When the drill pipe is removed from the hole, a weighted mud slug can be pumped
as a “pill” to balance bottomhole pressure, compensating for the loss of backpressure
when the bottomhole assembly is out of the hole. The volume of mud required for this
purpose depends largely on the hole’s diameter and the proximity of fractures since
returns are typically not seen at the surface [5].

Figure 2.
Mud cap drilling.

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Managed Pressure Drilling and Cementing and Optimizing with Digital Solutions
DOI: http://dx.doi.org/10.5772/intechopen.113287

3.2.2 Floating mud cap drilling

Floating Mud Cap Drilling (FMCD) is a specialized subset of the PMCD technique.
It comes into play when it’s challenging to design the annular fluid to provide surface
pressure, resulting in a “floating” mud cap. In FMCD, a sacrificial fluid, typically
water, is pumped down the drill pipe, like PMCD [5].
As drilling progresses and the well deepens, assuming increased formation pressure
with depth, the high-density annular mud cap may lose its ability to contain bottomhole
pressure independently. Over time and distance, an annular pressure differential of 200
to 300 psi, well below the pressure ratings for Rotating Control Device (RCD) tools, is
not uncommon. As annular pressure rises, the fluid density of the mud cap is often
increased to maintain pressure within acceptable limits. Surface pressure fluctuations
serve to monitor three downhole conditions:

• Detection of gas migration to the annulus.

• Management of produced fluid injection back into the formation at specified

rates and volumes.

• Handling of pore pressure increases by adjusting the annular hydrostatic fluid

density to maintain surface pressure within a safe range.

Addressing potential fracture plugging issues, wherein if cuttings obstruct frac-

tures, pressurized mud cap drilling may need to be halted in favor of conventional
drilling operations.
However, monitoring of mud levels in the annulus is challenging, particularly when
the formation pressure is below hydrostatic. In such cases, it’s challenging to maintain
the annulus full of fluid, and the fluid level in the well tends to reach an equilibrium
point. This situation can make it difficult to monitor influx or gas migration. FMCD
effectively means drilling blindly with limited annular pressure control [2].
New technologies such as wired drill pipe, which allows pressure monitoring along
the drill string, could unlock additional FMCD capabilities and provide enhanced well
control options. There are also considerations of using fluid technologies with light-
weight solid additives like glass beads to facilitate mud cap operations when drilling in
sub-hydrostatically pressured reservoirs.

3.3 Dual gradient drilling

Dual Gradient Drilling (DGD) is a term encompassing various strategies aimed at

controlling up-hole annular pressure in the context of deepwater marine drilling. DG
has found success primarily in offshore applications, where a significant portion of the
overburden is comprised of water. Since this liquid overburden is less dense than the
typical formation overburden, the drilling window is relatively narrow due to the
limited margin between pore pressure and fracture pressure. The weak formation
strength in deepwater conventional drilling often necessitates the use of multiple
casing strings at shallow depths to prevent severe lost circulation when employing
single-density drilling fluids.
To mitigate the impact of the deepwater overburden, the drilling system can be
balanced by reducing mud density in the upper sections of the marine riser or by
introducing sea water into the riser or dividing the system at the seabed into two parts.
7
Advances in Oil and Gas Well Engineering

Figure 3.
Dual gradient drilling.

In the dual-gradient approach, the goal is to simulate the saltwater overburden

with a less dense fluid. This can be achieved by injecting media with lower density,
such as inert gas, plastic pellets, or glass beads, into the drilling fluid within the marine
riser to adjust bottomhole pressure. Alternatively, the marine riser can be filled with
saltwater while diverting and pumping mud and cuttings from the seabed floor to the
surface. In this scenario, filling the drilling riser with seawater helps prevent collapse.
The primary objective is not to decrease the Equivalent Mud Weight (EMW) or
effective BHP to a point below formation pore pressure. Instead, the primary goal is
typically to avoid excessive overbalance and surpassing the fracture gradient.
Figure 3 illustrates a comparison of pressure profiles between the dual gradient
method and the conventional method. Particularly in deepwater drilling where frac-
ture pressure is a significant concern, transitioning from conventional to dual gradient
systems reduces the risk of fracturing weak zones under dynamic conditions [6].
Both methods involve altering fluid density near the mudline. By using two dif-
ferent fluids to create overall hydrostatic pressure in the wellbore, the fracture gradi-
ent is not exceeded, and formation breakdown is avoided. This prevents drilling
operations from incurring NPT associated with lost circulation problems and the
associated costs. This form of MPD can be implemented with or without a
subsea RCD [3].

3.3.1 Riser-less mud recovery (RMR)

In the Pre-BOP section, implementing a DGD system can effectively address

various operational challenges. Offshore drilling for the top-hole section often
encounters difficulties such as soft and unconsolidated formations, shallow gas, and
shallow water. Additionally, the use of seawater as a drilling mud can be less effective
for hole cleaning and wellbore stability. Disposing of cuttings into the sea becomes an
issue due to the absence of fluid return to the shakers, and cementing is challenging

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Managed Pressure Drilling and Cementing and Optimizing with Digital Solutions
DOI: http://dx.doi.org/10.5772/intechopen.113287

Figure 4.
Riser-less mud recovery system for top-hole drilling and cementing.

because of seawater mixing at the seabed and potential exposure of excess cement to
the sea, among other concerns.
To overcome these challenges, the Riser-less Mud Recovery (RMR) system
proves valuable. With RMR, engineered mud can be utilized, eliminating problems
related to hole cleaning and instability. Mud and cuttings can circulate efficiently and
be recovered without exposure to the sea on the shaker. Employing engineered mud
circulation in the top-hole section contributes to the formation of a mud cake,
enhancing wellbore stability and eliminating issues related to shallow gas during
drilling.
Furthermore, cementing operations can be conducted within a closed system,
enabling precise control of BHP. The closed system allows for accurate monitoring of
cement volume, and when the cement reaches the seabed, it can be confirmed
through pressure sensors in the return line. By adjusting and manipulating the speed
of the Subsea Pump Module (SPM), BHP can be controlled with precision. This
integrated approach addresses the challenges associated with drilling in the top-hole
section and enhances overall operational efficiency and safety (Figure 4).

3.4 Return flow control

As we gear up to respond securely and efficiently to any unexpected downhole

events, Return Flow Control (RFC) can be seen as a crucial aspect of the MPD
approach, even though it does not directly manage annular pressure. RFC also serves
the important purpose of diverting annular returns away from the rig floor to prevent
any gas, especially hazardous gases like H2S, from escaping onto the rig floor. This
practice is primarily a safety measure [2].
In the event of an influx during drilling, trip gas, or connection gas spilling onto
the rig floor, a safety protocol is activated. The flow line to the shakers is closed
immediately, and the flow is redirected to the rig choke manifold, where the influx is
safely controlled and circulated out of the wellbore. The utilization of an RCD negates
the need for closing the Blowout Preventer (BOP), minimizing the potential for
hydrocarbon release onto the drilling floor. It also allows for pipe movement while
managing an influx or addressing gas-cut mud.

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Advances in Oil and Gas Well Engineering

For RFC operations, two hydraulically operated valves are installed: one for the
conventional flow line to the shakers and the other for the flow line to the rig
choke manifold. This setup permits the handling of any influx through the rig choke
manifold, while in regular operations, the conventional flow line is used for fluid
circulation [7].
The primary objective of this approach is to conduct drilling with a closed annulus
return system primarily for Health, Safety, and Environmental (HSE) reasons. For
instance, during conventional production platform drilling operations with an open-
to-atmosphere system, there may be a risk of explosive vapors escaping from drilled
cuttings. This could trigger atmospheric monitors and potentially lead to automatic
shutdowns of production in other areas of the platform. Other applications of this RFC
variation include addressing toxicological concerns associated with drilling fluids
emitting harmful vapors onto the rig floor, taking precautions in areas with shallow
gas hazards, and drilling in populated regions. Typically, only an RCD is added to the
drilling operation to implement this variation [6].

4. MPD operation

Drilling in MPD mode closely resembles conventional drilling in most aspects. The
primary difference lies in the surface pressure (Surface Back Pressure or SBP), while
all other procedures typically remain unchanged. In cases where a Coriolis Flow Meter
is available, it enhances the detection of influxes or losses, and a new variable called
Delta Flow (the difference between Flow Out and Flow In) is closely monitored.
Although the procedures in MPD are like conventional drilling, the meticulous
control of pressures necessitates a more comprehensive monitoring of all parameters
that could influence BHP. While drilling in MPD mode, particular attention must be
paid to several key parameters, with some of the most crucial being:

• Standpipe Pressure trend can offer valuable insights into downhole events.

• Any increase or decrease in cuttings observed at the shakers may indicate

variations in hole cleaning. Accumulation of cuttings in the annular space can
significantly impact BHP.

• Parameters indicating influxes or losses:

◦ Pit Volume Totalizer

◦ Change in flow in and flow out

◦ Rate of Penetration

• It’s essential to remember that hydrostatic pressure is an important parameter

that contribute significantly to the pressure applied at the bottom of the hole
(mud weight).

• Changes in either of Mud Rheology and Flow Rate can affect annular friction
losses, ultimately influencing BHP.
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Managed Pressure Drilling and Cementing and Optimizing with Digital Solutions
DOI: http://dx.doi.org/10.5772/intechopen.113287

Additionally, it’s important to consider any specific operations that require alter-
ations in flow rates, such as monitoring slow circulating rates or conducting mud
telemetry operations when using Measurement While Drilling (MWD) tools [8].

4.1 Connection with MPD system

During pipe connections, the flow rate undergoes significant changes,

transitioning from drilling speed to zero or vice versa. This variation directly impacts
the calculation of annular friction losses and, subsequently, the BHP. As previously
discussed, it’s essential to adjust the Surface Back Pressure to compensate for the loss
of annular friction losses when the flow rate reaches zero. This is a necessary step to
facilitate the breaking of pipe connections, allowing for the addition or removal of
pipe sections to continue drilling operations.
Here’s a summarized procedure for handling connections:

Drilling Phase: Drilling continues until the top of the stand reaches the rig floor
level. All parameters are maintained at their drilling values during this phase.
Circulation is actively maintained to prevent cuttings near the bottom of the hole
from settling and potentially causing a pipe to become stuck.
Ramp Down: When the crew is ready to make the connection, the flow rate is
gradually reduced in steps. Simultaneously, Surface Back Pressure is increased at
each step to compensate for the loss of friction losses, ensuring a constant BHP.
The ramp-down pressure follows a predetermined schedule, with Surface Back
Pressure calculated for each step.
Connection: During this step, the drilling crew performs the actual pipe
connection. Notably, in this closed system, pressure inside the drill string does not
naturally bleed off. Thus, a bleed-off process must be executed before breaking
the connection.
Ramp Up: After completing the connection, circulation is resumed, and the flow
rate is gradually increased back to drilling values. This process reverses the ramp-
down procedure (Table 1) [8].

After successfully completing the connection and restoring drilling circulation

conditions, drilling operations resume. It is essential to continually monitor drilling

Step Choke pressure (Psi) Pump rate (gpm) Pump pressure (psi) BHP (psi)

Ramp down 20 196 2995 1566

Ramp down 113 183 2691 1611

Ramp down 155 170 2397 1608

Ramp down 155 155 2081 1566

Ramp up 347 85 1014 1590

Ramp up 347 71 931 1566

Ramp up 359 71 843 1578

Ramp up 413 0 0 1566

Table 1.
An example of typical MPD connection ramp down and ramp up.

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Advances in Oil and Gas Well Engineering

Figure 5.
Typical MPD connection illustration.

parameters to ensure they align with their pre-connection values. Significant

variations in these parameters could indicate issues arising from the cessation of
circulation.
Moreover, if, for any reason, the Surface Back Pressure did not synchronously
adjust with the changes in flow rate (there might be a delay between the flow rate
adjustment and the choke reaching the desired Surface Back Pressure value), it can
lead to fluctuations in BHP. This situation could also introduce the presence of gas
within the fluid stream.
Figure 5 is a visual representation illustrating the stages of a typical MPD connec-
tion procedure:

4.2 Rollover/rollback

In MPD operations where a positive Surface Back Pressure (SBP) value is consis-
tently maintained, the process of tripping can be carried out with surface pressure
applied. This is technically referred to as ‘stripping.’ However, it’s important to note
that stripping the pipe all the way to the surface is not feasible due to several limita-
tions, which will be discussed in future training sessions.
One critical limitation to consider is the inability to pass the Bottom Hole Assembly
(BHA) through the RCD. Consequently, at a certain point during the tripping process,
it becomes necessary to completely release the Surface Back Pressure.
In situations where the Surface Back Pressure plays a vital role in maintaining well
control, simply bleeding it off without considering the consequences is not an option.
In such cases, the well must be transitioned to a higher density drilling fluid. This
denser fluid creates a hydrostatic pressure significant enough to sustain well control
without relying on Surface Back Pressure [8].

4.2.1 Rollover

Following is the procedure of rollover to ensures that the well remains stable and
safe while tripping (Figure 6):
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DOI: http://dx.doi.org/10.5772/intechopen.113287

Figure 6.
Rollover steps in MPD tripping.

1. The rollover depth can either be at Total Depth (TD) or, more commonly, at the
last casing shoe depth. If it’s at the last casing shoe depth, the drill string needs to
be stripped to that depth while maintaining SBP.

2. Position the bit at the rollover depth and pump the kill mud. While the mud is
inside the drill string, refrain from making any system changes, as only events
occurring in the annular section affect BHP. Expect a decrease in standpipe
pressure as the heavier mud is easier to pump due to gravity assisting the process.

3. As the heavy mud enters the annulus, it impacts BHP, necessitating a gradual
reduction in Surface Back Pressure to compensate for increased hydrostatic
pressure. This reduction is done in steps, following a rollover schedule.

4. When heavy mud is observed on the surface returns, completely bleed-off

Surface Back Pressure.

5. Halt the pumps and inspect the well. It should now be static, allowing the safe
removal of the RCD bearing assembly. Proceed with the trip to the surface
following conventional drilling procedures, closely monitoring tripping
parameters to prevent excessive swab pressures [8].

4.2.2 Rollback

Here is the procedure for rollback (Figure 7).

1. Trip to the rollover depth using conventional tripping procedures, monitoring

parameters to avoid surge pressures.

2. Position the bit at the rollover depth, install the RCD bearing assembly, and
pump drilling mud (light). Maintain the system without changes as long as mud
is in the drill string, keeping Surface Back Pressure as low as possible.

3. As drilling mud enters the annulus, gradually increase Surface Back Pressure to
compensate for decreased hydrostatic pressure.
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Advances in Oil and Gas Well Engineering

Figure 7.
Rollback steps in MPD tripping.

4. Once drilling mud returns to the surface, maximize Surface Back Pressure for the
rollback operation.

5. Stop the pumps, apply extra pressure to account for friction losses, and check the
static well. Resume drilling operations [8].

5. MPD equipment and layout

In drilling operations, the fluid circulation typically starts by drawing fluid from
the mud tanks, which is then pumped through the rig pumps to add energy for return
to the surface. From the mud pits, the fluid is transported via the standpipe line and
surface drilling equipment before entering the drill string. Once it reaches the end of
the drill string, the fluid exits through the bit and flows upwards within the annulus. It
eventually returns to the surface through the BOP stack and is directed through a bell
nipple, an open system exposed to the atmosphere. Subsequently, the fluid travels
through a flow line, an atmospheric pipeline that is not designed to hold pressure. It
proceeds to the solids control equipment, and then finally returns to the mud pits,
thus completing the circulation cycle [9].
However, in MPD, the fluid follows a similar pathway but with some notable
differences. Instead of the bell nipple, there’s an RCD employed to create a sealed
system around the drill pipe, so it established a closed system. From the RCD, the fluid
is redirected to the MPD choke manifold through a specially designed primary line,
rigorously tested to handle pressure. Conventional drilling rigs typically feature a choke
manifold for well control, but MPD applications require an additional choke manifold,
known as the MPD choke manifold, for continuous use in regulating surface pressure,
serving as the primary method of pressure control in MPD. Downstream from the MPD
choke manifold, another pipeline directs the fluid back to the shakers [8].
The backpressure MPD system has several essential equipment requirements,
including (Figure 8).

• The Rotating Control Device

• Choke manifold
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DOI: http://dx.doi.org/10.5772/intechopen.113287

Figure 8.
MPD equipment set up.

• Backpressure pump

• Mud gas separator

The Rotating Control Device serves as a crucial pressure seal element positioned
above the BOP and below the drill floor. Its primary function is to guide the annular
flow and establish a closed-loop system. Meanwhile, the Choke manifold is employed
to control well pressure, with its operation mode varying from manual to fully auto-
mated or semi-automated, depending on the situation. It can be used independently or
in conjunction with the backpressure pump. Additionally, an integrated pressure
management and hydraulic flow model can be integrated into the system, continu-
ously updating flow parameters, and adjusting the choke opening in response to
pressure variations. This hydraulic model also aids in early kick detection. In cases
where a kick occurs, a mud gas separator can be utilized to separate fluids, even if the
well remains unclosed and circulation continues [9].

6. Control mud level

Control Mud Level (CML) technology revolutionizes mud level management in

the riser, serving as a Dual Gradient Drilling (DGD) solution designed primarily for
post-BOP drilling operations. The key innovation involves a subsea pump integrated
into a modified riser joint (MRJ), enabling precise control of mud levels within the
riser’s annular space. CML effectively eliminates the challenges associated with ECD
and facilitates drilling with a nearly constant BHP. This groundbreaking technology
can significantly influence well design, optimizing casing point placements. By erad-
icating the impact of circulating friction, it also allows for increased flow rates in
horizontal sections and unstable formations, enhancing wellbore cleanliness. CML
proves particularly invaluable when drilling through formations with a high potential
for losses or layers at a heightened risk of influx.
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Advances in Oil and Gas Well Engineering

Figure 9.
CML system overview.

The EC-Drill technology represents a specialized CML method tailored for

post-BOP drilling scenarios. This system employs a subsea pump installed on an
MRJ to exert control over the mud level within the riser. By dynamically adjusting
the mud level within the riser, the system compensates for fluctuations in
hydrostatic and hydrodynamic pressures (ECD) encountered during drilling
operations.
In stark contrast to conventional MPD systems that rely on an RCD to virtually
extend the height of the mud column by applying back pressure, the CML system
offers the distinct advantage of utilizing denser mud weight. Additionally, it provides
the flexibility to lower the mud level within the riser, thus exerting precise control
over BHP. Remarkably, CML system eliminates the need for an RCD [10].
The CML system comprises various components on both surface and subsea levels,
including (Figure 9).

• Office Tool and Control container

• Umbilical Reel
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• Top-fill pump

• Subsea pump module (SPM)

• Mud return line

• Modified Riser Joint (MRJ)

Within this system, the primary barrier consists of the drilling fluid (depicted in
blue), while secondary barriers include subsea BOP, the wellhead, casing, and cement
(depicted in red).
The Subsea Pump Module features three electrical pumps designed for efficiently
handling the transfer of mud and drill cuttings at high rates. The SPM connects to a
designated modified riser joint, directing the return flow into a dedicated Mud Return
Line (MRL). For extended deployments, an improved solution involves integrating
the MRL into the riser itself, enhancing both robustness and efficiency. This MRL
integrates into the flowline upstream of the shaker box. Communication and electrical
power to the SPM are facilitated by an umbilical line equipped with a winch, with the
dedicated Control Container (CC) overseeing electrical power and communication.
Operators and control systems are situated within a separate Office and Tool Con-
tainer (OTC) located adjacent to the CC. The outlet from the riser is equipped with
two isolation valves, enabling swift isolation of the CML system from the riser when
necessary [10].
The SPM’s placement on the drilling riser is meticulously selected based on mud
weight and ECD reduction requirements, accounting for a margin to prevent pump
cavitation. The number of pumps, their head, and power requirements are meticu-
lously tailored to the task at hand. The relationship between the change in fluid
column and BHP alteration adheres to the formula:

• (BHP during connection): P = Mud density x g (gravity constant)  (TVD-h1)

• (BHP during drilling): P = Mud density x g (gravity constant)  (TVD-h2) + AFP

Where P is the bottom hole pressure, ρ is the mud weight, g is the gravity constant,
TVD is the true vertical depth of wellbore, h1 and h2 are the fluid column reduction in
riser, and annulus friction pressure.

6.1 Effect of CML on BHP

The impact on well pressure (BHP), with the CML system is notable. When
the SPM is mounted on the riser, the well’s pressures become adjustable by varying
the riser’s level. This contrasts with traditional MPD methods where well pressure
is typically controlled by selecting a Mud Weight (MW) lower than necessary and
then introducing backpressure via a choke. With CML system, the technique is
the opposite. A conventional overbalanced MW is chosen, and the riser level is
reduced to attain the desired well pressure. This approach results in a less steep
dynamic mud gradient, a characteristic dependent on the mud weight utilized
(Figure 10) [11].

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Advances in Oil and Gas Well Engineering

Figure 10.
Pressure gradients of different drilling system.

6.2 Effect of CML on well design

The implications for well design are profound. The CML system’s unique capabil-
ities, combining a gentler dynamic mud gradient with the flexibility to adapt to
unforeseen formation pressures, can enable the drilling of longer sections. This opti-
mization extends to casing point placements, offering more flexibility in designing
wells. Additionally, the capacity to enhance circulation rates for improved hole
cleaning may eliminate the need for employing hole openers in deepwater settings.
This simplification of the BHA contributes to reduced downtime risks. The benefits of
dual-gradient drilling and the mud density gradient slope are most prominent in the
upper well sections, while the ability to maintain high circulation rates finds its
greatest utility in the lower regions of the well. In formations prone to weakness,
traditional methods necessitate reduced circulation rates to prevent losses, putting
hole cleaning at risk and increasing the potential for pack-offs. CML system, however,
permits the maintenance of full circulation rates [10–12].
The accompanying Figure 11 depicts a typical well and illustrates the mud weight
window that dictates the need for multiple casing strings. Due to the common uncer-
tainty surrounding pore and fracturing pressure, planning for additional casing is
often essential. In such cases, this can result in the installation of 7 or 8 strings after the
BOP is installed.
Figure 12 portrays the same well as in Figure 11, but this time with the CML
system. Manipulating the mud level in riser represents a practical enhancement of the
existing CML equipment. Change in the slope of mud gradient (with low mud level in
riser) will help to fit BHP inside mud window. This will lead to set the TD (casing
points) deeper which will ending up eliminating number of casing points in the
planning phase. It’s worth noting that in this scenario, filling the riser without frac-
turing the shoe would require the qualification and implementation of new well
control methods [11].

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Figure 11.
Conventional casing points determination.

Figure 12.
Casing point determination by CML.

7. Advantages of the CML system

The implementation of the CML system on offshore wells offers several significant
advantages, enhancing well design and operational efficiency while minimizing NPT
and cost.
Early Kick Detection: The CML system demonstrates superior kick detection capa-
bilities compared to conventional Early Kick Detection (EKD) systems. It can identify
kicks at an earlier stage based on real-time data, enhancing well safety.
No Rig Heave Limitation: Unlike some other systems, the CML system operates
without being limited by rig heave. It can effectively detect influxes, contributing to
safer drilling operations.
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Advances in Oil and Gas Well Engineering

Extended Reach and Horizontal Drilling: The CML system proves valuable in
extended reach drilling and long horizontal sections. By adjusting the mud level in the
riser to compensate for increased friction pressure loss, it enables the drilling of longer
horizontal sections.
Narrow Mud Window Drilling: CML’s ability to manipulate the mud level in the
riser allows for precise control of BHP within narrow mud weight windows.
Loss Prevention: The CML system significantly reduces losses by lowering the mud
level in the riser and thereby reducing bottom hole pressure. This approach has led to
a remarkable 70% reduction in losses.
Managed Pressure Cementing (MPC): The CML system has facilitated successful
MPC operations by manipulating fluid levels in the riser, BHP can be controlled
effectively during cementing operations, preventing losses.
Hole Cleaning: With the CML system, there’s no need to reduce flow rates to
compensate for friction pressure losses. It automatically compensates for increased
friction pressure, allowing for higher flow rates. This not only reduces hole-cleaning
issues but also maintains efficient drilling operations.
In summary, the CML system, presents a range of advantages in offshore drilling,
encompassing improved safety, efficiency, loss prevention, and the ability to handle
complex drilling scenarios [10–12].

7.1 Early kick detection (EKD) with CML system

In traditional rig site practices, the detection of influxes or losses primarily relies
on monitoring mud pit levels and return flow rates. The rig crew typically uses these
parameters in combination to identify any potential influxes while drilling or tripping.
However, the CML system introduces a more sophisticated approach by augmenting
these traditional indicators with the monitoring of two critical parameters: hydrostatic
pressure in the riser and the speed of the SPM.
Hydrostatic Pressure Monitoring: Pressure sensors positioned at the same level as
the SPM installation point (pump outlet) continuously measure the hydrostatic pres-
sure within the riser. An influx (extra volume) into the well causes a noticeable
increase in riser pressure because the mud level within the riser rises in response to the
additional volume.
SPM Speed Monitoring: To maintain a constant mud level within the riser, the
CML system keeps the speed of the SPM constant. Consequently, any influx is
detected as an increase in riser pressure because the mud level in the riser rises with
the extra volume. However, if the riser pressure remains constant during drilling
(indicating a fixed mud level in the riser), any influx is detected through an increase
in the speed of the subsea pump module. As the SPM endeavors to maintain the mud
level in the riser at a fixed pressure, it must work faster when it encounters extra
volume. This dual monitoring approach places the CML system at the forefront of
early kick detection.
To effectively detect losses or influxes with the CML system during operations, it is
imperative to monitor the following parameters:

• Speed of the pump (SPM speed).

• Hydrostatic pressure within the riser (mud level in the riser above the SPM inlet).

• Flow rates into and out of the well.

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During drilling operations in the Gulf of Mexico (GOM), ten kick drills were
meticulously conducted to validate the system’s efficacy. These drills unveiled a dis-
tinctive pattern: the initial indicators were a rise in riser pressure and an increase in
SPM speed, promptly detected and recorded. The second indicator, the return flow,
followed 48 seconds later. This represents a notable improvement over conventional
drilling practices where flow out typically provides a faster response compared to
monitoring the gain or loss from the active pit [10, 11].
When operating CML system while drilling, there are repeatable events in opera-
tions, such as connections, that detecting influxes or losses can be challenging due to
the dynamic nature of the parameters. Therefore, the system employs a baseline
established from recorded connection data (fingerprint) from before the operation.
This baseline aids in identifying any deviations from the established connection
procedure, enhancing early kick detection capabilities.

7.2 Extending horizontal section with CML system

Horizontal drilling, particularly the extension of horizontal sections, benefits sig-

nificantly from the implementation of the CML system. This technology offers a
means to push the boundaries of horizontal drilling, which conventionally faces limi-
tations due to ECD restrictions.
The CML system enables the extension of horizontal sections beyond the typical
stopping point imposed by ECD limits. By strategically lowering the mud level in the
riser, the adverse effects of ECD can be mitigated and brought below the critical ECD
limit. Consequently, drilling operations can continue, and the horizontal section can
be significantly extended, surpassing what is achievable with conventional drilling
methods.
Moreover, the CML system introduces the flexibility to increase the flow rate for
enhanced cuttings removal and improved hole cleaning within the horizontal section.
This is a valuable advantage as it ensures efficient wellbore cleaning in these chal-
lenging drilling environments. Additionally, the system can effectively compensate
for any extra friction pressure loss that might arise due to the higher flow rate. This

Figure 13.
Extending horizontal section by using CML system.

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Advances in Oil and Gas Well Engineering

capability is accomplished by strategically lowering the mud level in the riser, dem-
onstrating the adaptability and versatility of the CML technology.
To vividly illustrate the effectiveness of the CML system in extending horizontal well
sections, this section provides a comparative analysis of a drilling operation conducted
with and without CML. In Figure 13 data from a North Sea well’s horizontal section is
presented. In the initial segment of the section, the CML system remained dormant.
Consequently, the Actual ECD soared to its maximum threshold, halting conventional
drilling operations. To resume drilling, the ECD needed reduction, prompting the acti-
vation of the CML system. The mud level was deftly adjusted to 200 meters (as indicated
by the orange line), resulting in a remarkable drop in ECD from 1.28 sg to 1.12 sg.
Subsequently, an additional 2000 meters were successfully drilled with the lowered riser
level, maintaining ECD within permissible limits. Without the intervention of the CML
system, this extended section of the well would have remained unattainable.

8. Managed pressure cementing (MPC)

Managed Pressure Cementing (MPC) utilizing the CML system is a comprehensive

approach to controlling wellbore pressure during the critical phases of pumping and
displacing cement. This technique is instrumental in preventing losses and ensuring
the proper placement of cement in the wellbore.
MPC’s core objective is to manage the pressure gradient within the wellbore effec-
tively. This entails using the SPM to manipulate the pressure conditions within the
well, ensuring that the pressure stays within the desired range during the cement
displacement process. This control over wellbore pressure is crucial for cementing
operations, as it helps prevent issues such as lost circulation and ensures that the
cement is delivered precisely where it is intended.
The MPC process involves the use of a step-down table to guide the cementing
operation (Table 2). This table outlines the desired pressure values at the wellhead
throughout the operation. It consists of several columns, with the first column indi-
cating the volume of cement returned. The second and third columns specify the
desired pressure values at the wellhead in pounds per square inch (psi) and bar,
respectively.
Here’s a step-by-step description of the MPC process:
Start SPM and Maintain Low Riser Level: The MPC process begins with the
activation of the SPM. Initially, a low riser level is maintained.

Volume returned from start of pumping spacer (bbl) Pressure (psi)

0–840 761

880 757

920 753

960 748

1000 744

1040 740

1080 735

Table 2.
MPC Step down table.

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Standby Phase: During this phase, the system remains in standby mode while
keeping a constant riser level. The goal is to maintain this level until the cement
exits the drill pipe. The detection of this phase is achieved by monitoring the
increase in standpipe pressure.
Pressure Reduction Strategy: As the cement progresses up the annulus, a
systematic pressure reduction strategy is employed. For every 15-psi increase in
standpipe pressure, the riser pressure is reduced by 10 psi. This strategy is
designed to compensate for increase in standpipe pressure. Consequently, it
provides an estimated 80% compensation for the corresponding increase in
hydrostatic pressure downhole.

This approach ensures that wellbore pressure remains within the specified param-
eters throughout the cementing operation, preventing potential issues and facilitating
successful cement placement in the wellbore. The MPC process with the CML system
enhances the overall safety and effectiveness of cementing operations, particularly in
challenging well environments.

9. Controlled mud cap drilling (CMCD)

Having a CML system onboard also enables the use of Controlled Mud Cap Drilling
(CMCD) as a contingency measure in case of total mud losses. CMCD is a technique
where mud cap fluid is introduced into the wellbore to control pressure, especially in
zones where total losses are encountered. CMCD is introduced as a response to spon-
taneous reactions during drilling into zones where total mud losses occur. It’s a drilling
technique with no returns to the surface, meaning that drilling fluid and cuttings are
lost to the formation. In CMCD, the key control parameters are the amount of viscous
mud cap fluid injected into the annulus from the top-fill pump at the surface and the
riser booster pump. These parameters are adjusted using the Subsea Pump Module
(SPM) (Figure 14) [12].
To prevent gas from entering the wellbore, the minimum required injection rate of
mud cap fluid into the annulus must be greater than the gas migration rate. Gas
ingress into the wellbore is not tolerated. The injection rate of mud cap fluid is

Figure 14.
CMCD overview.

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Advances in Oil and Gas Well Engineering

adjusted using the SPM, and it’s determined based on the mud cap fluid level in the
riser, friction pressure due to the injection rate, and formation injectivity. Unlike
traditional drilling techniques where bottom hole pressure is controlled, CMCD can-
not control bottom hole pressure effectively. This is because the drilling fluid and
cuttings are lost to the void space, leading to a constant bottom hole pressure on top of
the loss zone. CMCD is a valuable technique in situations where total mud losses are
encountered, and conventional drilling methods are no longer effective. It allows for
some level of control over pressure and wellbore stability in challenging drilling
environments.

10. MDP vs. CML

Here is a Table 3 comparing MPD and CM) systems, highlighting their respective
advantages and disadvantages:
Please note that the advantages and disadvantages listed here are general and can
vary depending on specific drilling conditions, equipment, and operational practices.
Both MPD and CML systems have their merits and are valuable tools in the oil and gas
industry, with their effectiveness depending on the context in which they are applied.

Aspect MPD CML

Primary Objective Controlling BHP and ECD by Controlling BHP and ECD by
adjusting surface backpressure. manipulating mud level in the riser.

Application Both onshore and offshore Just offshore

Pre job installation Weeks to months Days to weeks

time

Effect on Well Design MPD may have minimal impact on CML may impact well design positively
well design. by optimizing casing points

Operational system Pressurized closed system Open to atmosphere system

Well control scenario Involved Not involved

Affecting operational Controlled ROP due to RCD Flexible ROP due to open system
sequence

Kick and Loss Conventional MPD systems rely on CML systems can detect kicks earlier with
Detection pit-level monitoring. riser-level monitoring.

Total loss curing PMCD CMCD

system

Switching to Not possible in short time Instantly

conventional drilling

Tripping time More time needed (roll back and roll Less time included (lowering or
over) increasing mud level in riser)

High gas cut in mud Safe drilling (closed system) Need to isolate and apply well control
during drilling (open system)

Cost comparison More expensive Less expensive

Table 3.
Comparing MPD vs. CML.

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DOI: http://dx.doi.org/10.5772/intechopen.113287

11. Digitalization and automation of MPD and CML

Digitalization and automation are transforming the drilling industry by ushering in

a new era of efficiency, precision, and safety. At the heart of this transformation is the
utilization of advanced tools like wired drill pipes and high-speed data transmission
systems that establish seamless communication between downhole operations and the
surface. These technologies enable real-time data collection, analysis, and decision-
making, which is paramount for enhancing drilling operations [13].
The core value of digitalization tools, such as wired drill pipes, lies in their ability
to provide operators with a continuous stream of downhole data. This real-time data
can include critical information about wellbore conditions, pressure differentials, and
formation analysis. By transmitting this data quickly and reliably to the surface,
drilling operators can make immediate adjustments to drilling parameters, thereby
optimizing drilling processes and minimizing NPT.
Furthermore, digitalization and automation go hand in hand in
revolutionizing drilling operations. These technologies enable the development of
semi or fully automated systems for drilling processes like MPD and CML. With
automation, key drilling parameters can be controlled and adjusted in real time
based on the data received from downhole sensors and models. This ensures that
drilling remains within specified pressure windows and wellbore stability limits,
reducing the risk of issues like kicks and losses. Ultimately, the integration of
digitalization and automation enhances the operational sequence, making it more
accurate and significantly increasing drilling speed while simultaneously
reducing NPT.
Incorporating MPD and CML systems into the digitalization process is the next
logical step. By digitizing the operation of these systems, operators can leverage real-
time data to make precise adjustments to drilling conditions, pressure levels, and fluid
dynamics. This can lead to semi or fully automated MPD and CML operations, where
the systems respond autonomously to wellbore changes and operator-defined param-
eters. As a result, these systems can optimize drilling processes more effectively,
maintain wellbore integrity, and enhance drilling safety, all while contributing to a
significant reduction in NPT. The synergy of digitalization and automation holds
immense promise for the drilling industry, paving the way for more efficient, cost-
effective, and environmentally friendly drilling practices.
A fully automated CML system aims to maintain constant BHP throughout drilling
operations, including connections. This is achieved through real-time pressure moni-
toring with technologies such as Pressure While Drilling (PWD) or Along String
Measurement (ASM) positioned behind the drill bit. To achieve this, a hydraulic
model is established, allowing calculations to determine the required mud level
adjustments based on the input BHP data, ensuring precise and continuous control of
well pressures and ECD (Figure 15).
This level of full automation, ensuring constant BHP during drilling and connec-
tions, can also be applied effectively in MPD systems, offering enhanced well control
and operational efficiency for the drilling industry (Figure 16).
In summary, the integration of digitalization and automation into both CML and
MPD systems represents a transformative leap in the drilling industry. With real-time
data transmission, wired drill pipes, and advanced sensors, these systems can now
maintain constant bottom hole pressure, optimize drilling parameters, and swiftly
respond to downhole conditions, significantly reducing NPT. Whether pursuing a
fully automated CML system, an MPD solution, or a combined approach, these
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Advances in Oil and Gas Well Engineering

Figure 15.
Automated CML system.

Figure 16.
Automated MPD system.

advancements hold the promise of safer, more efficient drilling operations, providing
greater control and precision to the energy sector.

12. Conclusion

In conclusion, this chapter has delved into the intricate world of drilling technol-
ogy, encompassing MPD, CML, and MPC. We’ve explored their techniques, equip-
ment, and operational nuances. Furthermore, we have illuminated the transformative
potential of digitalization and automation, facilitated by Wired Drill Pipe, in conjunc-
tion with MPD and CML systems. This convergence promises to usher in a new era of
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drilling, characterized by enhanced precision, reduced NPT, and optimized opera-

tional sequences. The fusion of cutting-edge technology and time-tested drilling
methods beckons a future where energy exploration and production are more
efficient, economical, and sustainable than ever before.

Acknowledgements

I would like to express my gratitude to NTNU (Norwegian University of Science and

Technology) for their invaluable support in the preparation and completion of this work.

Nomenclature

MPD Managed Pressure Drilling

CML Controlled Mud Level
MPC Managed Pressure Cementing
NPT Non-productive Time
CBHP Constant Bottom Hole Pressure
MCD Mud Cap Drilling
PMCD Pressurized Mud Cap Drilling
FMCD Floating Mud Cap Drilling
DGD Dual Gradient Drilling
RFC Return Flow Control
AFP Annular Friction Pressure
ECD Equivalent Circulating Density
BP Back Pressure
AFL Annulus Friction Loss
BHP Bottom Hole Pressure
NRV Non-Return Valve
ROP Rate of Penetration
RCD Rotating Control Device
EMW Equivalent Mud Weight
BOP Blow out Preventer
HSE Health Safety Environment
MWD Measurement While drilling
SBP Surface Back Pressure
BHA Bottom Hole Assembly
TD Total Depth
MRJ Modified Riser Joint
SPM Subsea Pump Module
MRL Mud Return Line
CC Control Container
OTC Office Tool Container
TVD True Vertical Depth
MW Mud Weight
GOM Gulf of Mexico
CMCD Controlled Mud Cap Drilling
ASM Along String Measurement
PWD Pressure While Drilling
RMR Riser-Less Mud Recovery
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Advances in Oil and Gas Well Engineering

Author details

Behzad Elahifar
Department of Geoscience and Petroleum, Norwegian University of Science and
Technology (NTNU), Trondheim, Norway

*Address all correspondence to: behzad.elahifar@ntnu.no

© 2023 The Author(s). Licensee IntechOpen. This chapter is distributed under the terms of
the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0),
which permits unrestricted use, distribution, and reproduction in any medium, provided
the original work is properly cited.
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DOI: http://dx.doi.org/10.5772/intechopen.113287

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