C H A P T E R
5
Advances in managed pressure
drilling technologies
5.1 Introduction
Conventional well drilling in petroleum industry uses drilling fluids with densities high
enough to exceed formation pressure. This technology is known as overbalanced drilling
(OBD). This time honored technology was motivated by drill safety and prevention of
blowout, which are compromised in case formation fluid flows uncontrollably. However,
OBD has disadvantages, including damaging the producing formation, causing differential
sticking, loss of circulation, reducing drilling rate or rate of penetration (ROP), and causing
lost circulation. To overcome these disadvantages, various techniques have been introduced.
In general, they are called Unconventional Drilling Techniques (UDT). Conventional drilling
utilizes a single-phase drilling fluid, which works on the premise of keeping an overbalanced
pressure at the sand face. It discourages influx from a reservoir while drilling or when drilling
stops for any other operation. Conventional drilling is also an open-loop operation, where the
returned fluid from the well is directed to a flowline that is open to atmosphere.
Conversely, UDTs can be either single- or multiphase in terms of drilling fluid. The UDT
equipment suite negates the conventional drilling mud circulation, frequently called a closedloop operation. One example of UDT is air drilling, for which atmospheric air is pumped
down the drillstring using compressors and a booster on surface. This makes it unique in
its application and operational challenges. Most UDTs are employed on conventional rigs,
unless coiled-tubing units are used, which makes them easy to incorporate within a conventional drilling operation.
However, the main two categories are: Managed Pressure Drilling (MPD) and Underbalanced Drilling (UBD). In UBD drilling, fluids are lighter to keep pressure lower than formation pressure and this has many advantages including high ROP, eliminating differential
sticking, minimize formation damage, and no fluid losses. The disadvantages of UBD include
high cost, complex operations, and being not applicable in all wells. Although UBD is useful
in drilling depleted reservoirs and where complete loss may occur but for pressurized shale
or high pressure formations, UBD cannot be used. MPD is a more comprehensive technique,
Drilling Engineering
https://doi.org/10.1016/B978-0-12-820193-0.00005-8
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5. Advances in managed pressure drilling technologies
FIGURE 5.1 Various UDTs.
which is adaptive and controls fluid pressure dynamically. In this chapter, these two technologies are discussed and their latest developments presented (Fig. 5.1).
5.2 Managed pressure drilling
MPD is an adaptive process used to more precisely control the annular pressure profile
throughout the wellbore while drilling (Killalia, 2015).
The International Association of Drilling Contractors (IADC) Subcommittee on Underbalanced and Balanced Pressure Drilling has made the following formal definition of managed
pressure drilling: “Managed Pressure Drilling (MPD) is an adaptive drilling process used to
more precisely control the annular pressure profile throughout the well bore. The objectives
are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. This may include the control of back pressure by using
a closed and pressurized mud returns system, downhole annular pump or other such mechanical devices. Managed Pressure Drilling generally will avoid flow into the well bore”
(IADC, 2015).
API (2017) somewhat adopts a similar definition, such as, MPD is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. American
Bureau of Shipping (ABS, 2018) defines MPD as: An adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to
ascertain the downhole pressure environmental limits and to manage the annular hydraulic
pressure profile accordingly.
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5.2 Managed pressure drilling
Drilling Systems (CDS)
Well Control System
(WCS)
BOP System &
Equipment
Lower Marine Riser
Package (LMRP)
Marine Drilling Riser
Riser & Guideline
Tensioning
Diverter System
Choke and Kill System
including Mud Gas
Separator
Cement/Kill Unit
Well Control Systems
(including Secondary,
Emergency & Auxiliary
Well Control)
Derrick Systems
(DSD)
Conductor Tensioning
System
Drill String
Compensation System
Derrick and Masts
Hoisting Equipment
Riser Running
Equipment
FIGURE 5.2
Drilling Fluid
Conditioning Systems
(DSC)
Pipe/Tubular
Handling Systems
(DSP)
Bulk Sorage and
Transfer System
Well Circulation
System (High Pressure
& Low Pressure)
Mud Retum
(Conditioning) System
Lifting Equipment
dedicated for drilling
Handling Equipment
dedicated for drilling
(Tubular, Pipe, BOP,
X-mas)
Rotary Equipment
Miscellaneous
Equipment
Various components involving the MPD process.
MDP is motivated by minimizing nonproductive time (NPT) as the drilling takes place in close
proximity between pore pressure and fracture pressure. Although, this is a problem associated
with offshore drilling, in reality, this is just as relevant in onland drilling. The MDP as process
is a technique developed to limit well kicks, lost circulation, and differential pressure sticking,
in an effort to reduce the number of additional casing strings required to reach total depth
(TD). This results in saving considerable time, which would otherwise be required with conventional drilling program. Various components affected by the MPD program are shown in Fig. 5.2.
5.2.1 Process description
MPD is primarily a technique that uses a single-phase drilling fluid to control equivalent circulating density (ECD) or dynamic mud weight (MW) without adding any weighting material to
the drilling fluid. The main purpose of any MPD operation is to work on issues that can be the
cause of heavy MW or high ECDs. As such, MPD improves the overall efficiency of the operation,
leading to a significant amount of savings in both time and cost. The objective of all well control
methods is to overbalance the flowing formation and circulate out the kick fluid without
exceeding the surface or subsurface-pressure limitations, often dictated by the fracturing pressure
and formation pressure of the well. The rotating-control-device rating and the maximumallowable annular surface pressure (MAASP) before formation fracture constitute these two limitations, respectively. In hydraulically challenged hole sections, narrow pore-/fracture-pressure
envelopes set a conservative limit to the surface pressures that can be safely applied during a well
control event. Therefore, in those sections MAASP often constitutes a more-restrictive wellintegrity-failure criterion than the rating of the surface equipment.
In general, MPD is a drilling method that allows for greater control over the pressure in the
wellbore. Additional equipment is required to achieve this, which may be divided into two
sections: the modified riser joint and the MPD pressure management system.
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5. Advances in managed pressure drilling technologies
The modified riser joint consists of the top and bottom adapter, the Rotating Control
Device (RCD), the Annular Isolation Device (AID), and the flowspool. The RCD is required
to establish a “closed system” in order to allow MPD and the AID is located below the RCD
as another layer of protection from kicks, providing a closed seal around the drill pipe. As
mud pumps down the drill pipe, it returns up the annular space to the flowspool, and directs
toward the MPD pressure management system. (It can also direct overboard, or to the platform’s well control choke manifold.)
The flowspool returns the drilling fluid to the surface through the MPD choke manifold, as
opposed to conventional drilling where it returns to the surface via the riser, which is open to
the atmosphere.
Choke valves control the backpressure and the drilling fluid then goes through the flow
meter. The flow meter provides data to allow adjustment of the backpressure, acting as an
early kick detection system.
Finally, the drilling fluid passes from the flow meter into the conventional mud treatment
system (or directs into the Mud Gas Separator).
Fig. 5.3 shows the components of the modified riser joint and Fig. 5.4 is a diagram of a
typical MPD system.
Conventional well control equipment remains in place to ensure safety of the drilling operation. However, drilling operations utilizing MPD introduce additional equipment along
with a different set of drilling procedures than that of conventional drilling. In essence,
MPD creates a closed system with the introduction of an additional equipment, whereas conventional drilling is an open system. This additional equipment and new drilling procedures
securely control the pressure within the wellbore. The conventional drilling well control
equipment remains in place as the primary and secondary well barriers.
MPD can be used to reduce well construction times, which in today’s high-cost rig market
is appealing to any exploration, appraisal, or field development team. The MPD technology
can, to a certain degree reduce drilling fluid-related formation impairment, and can through
the reduction of the mud weight reduce the cost of mud losses as well as the related nonproductive time that is spent in curing losses. The MPD has broad applications in the drilling
industry. In the offshore applications, the following applications can be cited for Deepwater
and Continental Shelf projects:
e
e
e
e
e
e
e
e
Drilling
Drill string trips
Circulations
Running casing/liner
MPC: cementing casing/liner string and zonal isolation
Preserving safety
Some completion operations
FIT/Leak off test
For land rigs or onshore operations, the following applications are found:
e
e
e
e
Drilling
Drill string trips
Circulations
Running casing/liner
5.2 Managed pressure drilling
FIGURE 5.3
e
e
e
e
387
Components of the modified riser joint.
MPC: cementing casing/liner string and zonal isolation
Preserving safety
Some completion operations
FIT/Leak off test
5.2.2 Benefits of MPD
The foremost benefit of MPD is displayed in these otherwise technically undrillable formations where kick tolerance is reduced to less than the precision and accuracy limitations of
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5. Advances in managed pressure drilling technologies
FIGURE 5.4 Statistical causes of NPT in the Gulf of Mexico between years 1993 and 2003 for gas wells. Modified
from Rehm et al. (2013). In the above figure, dark shade implies 'shallower than 15,000 ft' and lighter shade implies 'deeper than
15,000 ft'.
conventional well control equipment and methods. MPD offers the critical benefit of the
ability to detect kicks and promptly control the well at minimum kick size before it poses
a potential threat to the well integrity. Consequently, the annulus pressures at the surface
that are required to maintain CBHP can be kept at a practical minimum, allowing the kick
to be circulated at full circulation rate and without the need to shut-in the well. In general,
MPD provides solutions to the following problems (IADC, 2017):
• Extending casing points to limit the total number of casing strings and the subsequent hole
size reduction.
• Limiting the NPT associated with differentially stuck pipe
• Avoiding the lost circulationewell kick sequence
• Limiting lost circulation
• Drilling with total lost returns
• Increasing the penetration rate
• Deepwater drilling with lost circulation and water flows
The process has the following advantages:
• Improve ROP
• Enhance early kick loss detection
5.2 Managed pressure drilling
•
•
•
•
•
•
389
Mitigate reservoir damage due to mud and cuttings invasion
HPHT application
Improve well stability
Mitigate hole problems
Enable drilling through narrow pore and fracture pressure windows
Characterize the reservoir while drilling
There are numerous benefits of MPD. Some are:
1. It alleviates the risk of H2S exposure or unloading a pocket of gas with the MPD closed
loop. For deepwater applications, the riser gas handling (RGH) system includes a risermounted annular BOP and flowspool. The compact BOP features fast closing capability.
Normally used to seal off the annulus so that riser gas can be diverted to a choke manifold,
the BOP provides a backup seal during MPD operations when the balance speed sealed
rotating system (SRS) requires maintenance. The flowspool enables circulation of drilling
fluid returns to the surface RGH and MPD manifold.
The BTR RCD is seamlessly integrated into a single LoadKing deepwater riser system
using special flanges. The upper flange connects the RCD to the bottom of the riser telescopic
(slip) joint while the lower flange connects the RCD to the slimline annular as part of the
integrated riser joint.
Davoudi et al. (2011) evaluated alternative initial kick responses in MPD operations and
concluded that the most applicable response that avoids the disadvantage of shutting in
the well is to increase the surface backpressure until the return flow equals the flow-in while
maintaining constant pump rate. Bacon et al. (2012) investigated the impact of compressibility on this method and proposed an improved technique to determine influx cessation.
Santos et al. (2007) presented microflux-control system that employs an automatic choke system controlled by an intelligent control unit to detect and respond to an influx. Several authors presented case studies where an MPD system demonstrated its dynamic well control
capabilities and was used to mitigate drilling challenges (Gravdal et al., 2010; Cenberlitas
et al., 2011; Vieira et al., 2008; Medina et al., 2014). Valli (2015) presented a case study
from western Canada where a gas kick was detected and controlled by an automated
MPD system. The study was extended with an in-depth engineering study of the event to
provide a quantitative comparison with conventional well control method. The approach
was to first regenerate the event in a simulation environment, and then conduct what-if simulations to investigate the effect of total response time on the overall operational variables.
2. It reduces NPT to almost zero, particularly when the system is automatized for MPD
(Pallanich, 2019). Recently, Weatherford launched an automated MPD riser system. The
automated riser system combines artificial intelligence, condition-based maintenance,
and additional sensors to speed operations. A closed loop system is used to determine
the downhole pressure limits and manage the annular pressure profile accordingly.
Previous operations of Weatherford showed distinct advantages that translated into
savings of $18 million in a clastic formation off Indonesia, trouble-free drilling in
offshore Angola, elimination of 13 days of nonproductive time (NPT) despite total
loss zone offshore Brazil, reaching 20,000 ft total depth (TD) with zero losses in the
pre-salt offshore Brazil, reaching 21,000 ft TD with zero NPT in an abandoned well
390
5. Advances in managed pressure drilling technologies
PICTURE 5.1
Automated MPD riser system.
offshore Brazil, and achieving 20,000 b/d by reviving an abandoned well offshore
Brazil. One of the most important improvements has been in automatizing the riser system. For Weatherford, for instance, the automated MPD riser system features a robotic
arm that can connect a single subsea control umbilical and flowlines in a matter of
20 min or less. Picture 5.1 shows a photograph of the automated MPD Riser system.
For deepwater operations, Schlumberger companies Cameron and M-I SWACO offer the
deepwater MPD system. A key component of this system is the integrated MPD riser joint,
comprising the Cameron riser gas handling (RGH) system and the below-tension-ring
rotating control device (BTR RCD) from M-I SWACO. The system is bolstered with an integrated riser joint (IRJ), which is operated through an integrated control system, connected to
the IRJ with a single umbilical. It eliminates potential equipment incompatibility and provides a single point of contact and rapid response for all MPD-related matters.
3. MPD provides an active approach to well control that can be used to optimize the performance
of drilling operations in any well. During the design phase, additional components can be
selected to meet high-specification needs, such as kick detection, fluid separation, and nitrogen
gas generation and injection. Each flowmeter, mud-gas separator, and other technological
components can be adjusted to suit these applications.
4. Well control in deepwater drilling applications. In deepwater exploration wells uncertainty in pore pressure (PP) and fracture gradient (FG) and the margin between them
increases the potential risk of gas influx, lost circulation, and wellbore instability. The
risk of total losses is even greater in deepwater exploration prospects that contain salt
and fractured carbonates. An MPD system can address many of these problems and
potential risks (Weems et al., 2016).
In addition to improving the drilling operation, MPD has the potential to introduce economic value. As an average in the Gulf of Mexico, NPT increases drilling cost between $70
and $100 per foot.
Statistics and economic analysis indicate that applying MPD to the current drilling practices can reduce NPT and improve the economy. The economic advantages of MPD have
driven companies to consider this technology and drilling costs.
5.2 Managed pressure drilling
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5.2.3 Types of MPD
The ability of MPD to dramatically reduce NPT in today’s high rig rate market makes it a
technology that demands consideration in any drilling or development program. MPD helps
manage the problems of massive losses associated with drilling fractured and karstic carbonate reservoirs. It also reduces problems associated with equivalent circulating density (ECD)
while drilling extended reach wells and wells with narrow margins between formation breakdown and well kicks. In long horizontal sections, reducing ECD helps mitigate the impact of
drilling fluid induced impairment that is amplified by high overbalance. There are four basic
techniques covered under MPD. They are:
The four basic MPD techniques are the following:
1. Constant Bottomhole Pressure (CBHP) Profile: CBHP is an MPD method, for which the
annular pressure is kept close to constant at a given depth to eliminate cycles of kicks or
losses that are commonly encountered in deep wells. The typical application for this technique is for cases where there are high uncertainties on the pressure limits, a narrow mud
weight window with kicks/losses, and high associated nonproductive time (NPT). This is
typical for depleted, fractured, and unusually high-pressure reservoirs.
2. Mud Cap Drilling: Mud Cap Drilling is appropriate when normal techniques have difficulties to maintain circulation. Drilling fluid, together with water and cuttings, pumps into
the wellbore and drillpipe to help prevent and control kicks and lost circulation while
drilling in fractured or layered (different pressures) formations.
3. Dual Gradient: Dual Gradient Drilling is an MPD technique that employs two different
annulus fluid gradients to find a closer match to the natural pressure regime; one above
the seabed, another beneath. This concept is the most applicable technology for deepwater drilling as the use of a dual gradient system can eliminate the heavy mud column
in the marine riser. The objective is to reduce formation damage and the related fluid losses when drilling deep formations with low-fracture gradients eliminating mud density
changes (Mæland and Sangesland, 2013).
4. Return Flow Control (Health, Safety, and Environment [HSE] Method): Return Flow
Control Drilling is an MPD method that reduces risks from drilling fluid, hazardous
gases, and well control incidents to the personnel and the environment. This method
specifically enables drilling high-pressure, complex wells at reduced operational costs,
as it provides accurate measurements and analysis of flow and pressure (Rehm et al.,
2008). The system allows operators to make decisions on actual data versus predicted
data, resulting in safer operations.
5.2.4 Historical background
Most of the techniques associated with MPD are not new and have been used for decades.
Lumping them under the name MPD is, however, new. For instance, rotating heads were
described in the 1937 Shaffer Tool Company catalog (Rehm et al., 2013). Similarly, the
ECD was effectively used in well control practices developed in the 1970s. It has been well
known that the dynamic mud pressure is always less than the static mud pressure due to
pressure loss owing to friction. In addition, the laws of governing equations were known
and have not been changed ever since. Finally, the prevention and mitigation techniques
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5. Advances in managed pressure drilling technologies
are also largely old technologies. However, modern technologies have made it possible to
improve monitoring and sensing devices and introduced integration tools to deal with
some of the most common drilling problems, such as well kicks and lost circulation.
Many of the ideas on which MPD is based were first formally presented in books dealing
with abnormal pressure systems in various forums and books. For instance, three Abnormal
Pressure Symposia were held at Louisiana State University between 1967 and 1972. These
symposia looked at the origin and extent of abnormal pressures and how to predict pressures
and fracture gradients from available data. Every wildcat is also treated with the precaution
of an abnormal pressure formation. Then, there are actual abnormally high formation pressure (AHFP) zones, the knowledge of which prior to drilling into them can prevent considerable economic losses and, possibly, save human lives (Chilingar et al., 2002). The various
origins, undercompaction, tectonics, etc., of AHFPs are important issues, but for a driller, it
is useful to lump them into a protocol.
In the 1970s, a major oil company, out of its New Orleans office, was drilling from “kick to
kick” in offshore Louisiana to increase drilling rate and avoid lost returns (Rehm et al., 2013).
In today’s vocabulary, this would be a clear case of managed pressure drilling in the Gulf of
Mexico.
Similarly, mud cap drilling (MCD) was common for years as “drilling dry” or “drilling
with no returns.” It was introduced as Continuous Annular Injection method, to drill and
develop this marginal fields with efficient and low cost wells. A more formalized version
of MCD was tried in Venezuela in the 1980s, in the Hibernia Field off Nova Scotia (Canada)
in the 1990s, and later in Kazakhstan, in the former Soviet Union. This technique continues to
be used in its original form. For instance, Hamizan et al. (2014) reported the use of MCD in a
formation, for a formation for which one of the wells penetrated carbonate zone with total
losses (injecting up to 1200 gpm). No kicks or well control issues were experienced and
well barrier policy was accomplished by maintaining the annulus with overbalanced fluid
at all times using this method. Well was drilled to TD successfully, and all the primary objectives of the well were achieved. Drilling time was reduced significantly by over 50%,
and fluid cost for this operation was reduced to almost zero.
With the formalization of some of the older techniques, new techniques have been added:
• Using surface impressed pressure with a light mud to compensate for ECD.
• Continuous circulation in pressurized containment systems.
• Dual-gradient proposals for drilling in the ultradeep offshore waters where a subsea pump
is used to pump the drilling fluid up from the seafloor.
• Downhole valves to allow trips under pressure without stripping.
5.2.5 Case studies MPD
As stated earlier, the primary advantage of managed pressure drilling is to reduce drilling
costs due to NPT while increasing safety with specialized techniques and surface equipment.
In deep water, many projects would not be economically viable without MPD techniques. It is
the same with many marginal oil reservoirs. For these reservoirs, a number of significant and
recurring problems increase drilling costs. The relationship of the problems shifts as drilling
moves offshore, into very deep water, depleted fields, or superdeep wells. It is difficult to
rank the problems, because each drilling event has its own unique history.
5.2 Managed pressure drilling
393
FIGURE 5.5 Automatic detection and control of the kick: mud-flow-rate-in and mud-flow-rate-out data. From
Kinik, K., Gumus, F., and Osayande, N., 2015, Automated Dynamic Well Control WithManaged-Pressure Drilling: A Case
Studyand Simulation Analysis, SPE Drilling and Completion, 110e118.
Rehm et al. (2013) reported a comprehensive documentation of a number of case studies
using MPD. Fig. 5.5 illustrates statistical causes of NPT in the Gulf of Mexico between years
1993 and 2003 for gas wells. About 40% of NPT, a significant percentage of drilling problems,
are because of pressure-related issues, such as lost circulation, kicks, and well-bore instability.
MPD is known to mitigate pressure controlerelated problems and has great potential to increase the efficiency of drilling operation.
In 2014, Hamizan et al. did a case study of carbonate reservoir drilling. Due to highly fractured nature of limestone and the existence of karst, the amount of losses that occurred in the
offset wells was tremendous where situation of losing the primary barrierdhydrostatic
columndwas highly possible which could have lead to catastrophic well control incident/
loss gain scenario. The offset well encountered total fluid losses equated to approximately
25,000 bbls. TD was called early and losses were cured only with cement plugs. A total of
17 days was spent to mitigate the losses. In followup operations, the team decided to use
MCDdcontinuous annular injection methoddto drill and develop this marginal carbonate
field with efficient and low cost wells. Compared to the conventional MCD method utilizing
oil-based Light Annular Mud (LAM), decision of utilizing seawater as the sacrificial fluid and
LAM was made due to sub normal nature of the reservoir. Seawater was continuously
injected down the annulus and the drill pipe at rates allowed by the LOT and injection test
values. One of the wells penetrated carbonate zone with total losses (injecting up to
1200 gpm). No kicks or well control issues were experienced and well barrier policy was
accomplished by maintaining the annulus with overbalanced fluid at all times using this
method. Well was drilled to TD successfully, and all the primary objectives of the well
were achieved. Drilling time was reduced significantly by over 50%, and fluid cost for this
operation was reduced to almost zero.
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5. Advances in managed pressure drilling technologies
Kinik et al. (2015) reported a case study and detailed numerical simulation analysis of the
drilling events in order to examine the benefits of automated influx detection and control by
use of an MPD system and compared with a conventional well control method. In the case
study, a fully automated MPD system successfully detected and controlled a gas influx in
oil-based mud while drilling in onshore Montney formation in Alberta, Canada. The analysis
used dynamic well control simulations to regenerate the event, and a close match with the
field data was achieved. A sensitivity analysis was then conducted to study the effect of total
response time on pressures at the surface and at the casing shoe during the application of the
conventional “driller’s method” of well control. The findings from the study demonstrated
how automated early kick detection and control can minimize influx volume and increase
operational safety. The implementation of an MPD system with such capabilities significantly
reduced nonproductive time by enabling influx circulation at full rate and eliminating the
need for flow check, blowout-preventer closure, and operational delays inherent in conventional well control.
Fig. 5.5 shows the data recorded by the MPD system during the event. While drilling the
buildup section at 8063 ft MD, a drill break was observed with an increase in rate of penetration (ROP) from 20 to 80 ft/h, which was soon after followed by a sudden increase in return
flow. The parameters gas flow rate out, density out, and mud temperature out were measured
by a single-phase Coriolis flow meter lined up at the downstream of the automated chokes.
Fig. 5.5 shows the surface-pressure and choke-position data recorded during the event. An
eventual 510-psi SBP was required to re-establish the steady-state flow-out versus flow-in
balance, which in turn resulted in a 235-psi increase on the SPP side. This condition was
then verified for 20 s before an additional 100 psi was added to the SBP as a safety factor.
The time difference between the kick detection (t1 in Fig. 5.5) and regain of control (t2 in
Fig. 5.5) was measured as 3 min, and the additional gain during this period was 62 gal.
Mean while, the driller was informed and was advised to stop rotation, and continue
circulation at the full drilling rate. After regaining the control of the well, the MPD system
automatically switched to SPP-control mode to maintain constant BHP while the kick gas
was circulated out. It can be seen from the kick intensity that the difference between the
BHP immediately before a kick is taken and after the well is overbalanced. The size of the
kick taken is controlled by this pressure underbalance, in conjunction with the in flowperformance parameters of the reservoir, type of the kick fluid, and depth drilled into the
formation. In conventional well control, shut-in-drillpipe pressure directly provides this
measure because the circulation is stopped and the mud column inside the drillstring can safely
be assumed free of cuttings and gas. However, in a dynamic well control operation, the
circulation is not ceased. Therefore, a different approach was used to calculate the kick intensity. In the dynamic well control event presented here, the entire operation (detection, control,
and circulation) was conducted at full circulation rate and the mud density going into the well
was kept constant; therefore, the difference in the SPP before the kick detection (at t0 in Fig. 5.6)
and immediately after the formation was balanced (at t2 in Fig. 5.6) indicating the kick intensity, formulated by
KI ¼ SPPt2 SPPt1 ¼ 2:35 psi
where KI is the kick intensity.
(5.1)
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5.2 Managed pressure drilling
1,250
100
4,000
1,000
SPP
75
3,000
t0
750
SBP
50
2,000
500
25
1,000
t1
250
Standpipe Pressure (psi)
Surface Backpressure (psi)
Choke Position (%)
t2
0
0
08:30
0
08:40
08:35
08:45
09:00
08:55
08:50
Time (minutes)
FIGURE 5.6
Automatic detection and control of the kick pressure data.
A detailed pressure/volume/temperature (PVT) analysis was performed and O’Bryan and
Bourgoyne’s (1990) formulation used to determine the pit gain associated with a given kick
size and presented a correlation to calculate gas solubility. Fig. 5.7 shows the close match between the simulation output and the recorded data with two sets of simulation. In the initial
simulation, Simulation I, the surface-backpressure (SBP) data that were recorded by the MPD
Surface Backpressure (psi)
800
600
Annular
friction
400
200
0
08:25
FIGURE 5.7
Shut-in casing pressure
Field data
Simulation I
Simulation A
MPD kick
detection
08:30
Conventional
kick
Shut-in
detection
08:35
08:40 08:45
Time (minutes)
08:50
08:55
09:00
Comparison of the kick data and interactive simulation results: annular surface pressures.
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5. Advances in managed pressure drilling technologies
system during the kick event were tracked by dynamically manipulating the annulus pressure at surface with 30-s steps. In the initial simulation, Simulation I, the SBP data that
were recorded by the MPD system during the kick event were tracked by dynamically
manipulating the annulus pressure at surface with 30 s steps. In the next simulation, Simulation A, the driller’s method of conventional well control was used to control a kick that was
detected at 1.88 bbl pit gain, by use of the identical simulation setup. In Simulation A, the
objective was to determine the total response time required to control the identicalintensity kick by use of the driller’s method. Multiple simulations were iteratively entered
to change the total response time to obtain a match with the output parameter, peak pit
gain. During the event, a peak 14.2 bbl pit gain was measured when the head of the kick
reached the surface, as shown in Fig. 5.7. The simulations revealed that 2 min of total
response time would be needed to complete the kick control, including the time spent for
pump ramp-down, flow check, blowout-preventer closure, and possible operational delays.
5.2.6 Key factors for improving performance
Rehm et al. (2013) presented key factors that affect the effectiveness of an MPD operation.
The following factors are important in shaping the effectiveness of MPD.
5.2.6.1 Adaptability
A successful project requires careful planning and attention to the operating details. A
common problem in otherwise meticulous planning is the lack of flexibility. Because nature
is unpredictable, problems are bound to occur, for which the planned approach cannot function at its optimum. Any planning should be flexible enough to remedy the situation that
may arise. The very definition of MPD involves an “adaptive drilling process” that stipulates
flexibility and adaptability. It is in line with the classical “Adaptive control” process that has
been in place for decades. It inherently has the capability of the system to modify its own
operation to achieve the best possible mode of operation. A general definition of adaptive
control implies that an adaptive system must be capable of performing the following functions: providing continuous information about the present state of the system or identifying
the process; comparing present system performance to the desired or optimum performance;
making a decision to change the system to achieve the defined optimum performance; and
initiating a proper modification to drive the control system to the optimum. These three
principlesdidentification, decision, and modificationdare inherent in any adaptive system.
In an MPD process, innovations made in the areas of monitoring and data transfer in real
time have made it possible to make the system highly flexible and adaptable (Fig. 5.8).
5.2.6.2 Extending the casing points
Casing is the solution to most well-bore problems. However, until the advent of expandable
casing, each casing string reduced the hole size.1 The offshore industry ended up in awkward
1
With the expandable casing, an operator runs a section of pipe into the well and then drops the expansion cone,
which is moved by hydraulic fluid run through a smaller line that is connected to the cone. As the cone is pulled
back through the pipe with hydraulic and mechanical pressure, the pipe is cold-formed and expanded to its new
diameter. Normally, expandable casing only refers to liner.
397
5.2 Managed pressure drilling
(B)
(A)
Pil Gain (bbI)
Gas-Flow-Rate Out (sd/min)
Field data
Simulation I
Simulation A
12.5
10
7.5
2,500
Top of kick mixture
reaches surface
15
Conventional
kick detection
5
MPD kick
detection
2,000
Bottoms-up
at full rate
1,500
Gas reaches
degasser
1,000
2.5
0
08:30
08:45
09:00
Time (minutes)
FIGURE 5.8
09:15
09:30
08:30
08:45
09:50
09:00
09:10
09:20
09:30
Time (minutes)
Comparison of the field data and interactive-simulation results: (A) pit-gain and (B) gas-flow-rate-
out trends.
situation of starting with a 36 in. (914 mm) diameter hole to drill a 6 in. (152 mm) hole into a
reservoir. MPD techniques deal with methods of extending the casing point beyond the normal
pore pressure or fracture gradient limit to reduce the number of casing strings required. Fig. 5.9
illustrates how MPD can eliminate casing strings. Conventional drilling requires seven casing
strings while MPD reaches the target with three casing strings (Fig. 5.10).
5.2.6.3 Lost circulation
Many factors can lead to lost circulation. Some are: complex lithology, unpredictable formation pressure, multiple pressure systems in vertical direction, and local high pressure. It is
not possible to achieve effective separation of all complex intervals by using limited casing
programs. Consequently, two or more alternating high-pressure and low-pressure layers
may coexist in the same open hole interval. In addition, production layers are with
FIGURE 5.9 Conventional drilling provides a narrow drilling window.
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5. Advances in managed pressure drilling technologies
FIGURE 5.10 MPD techniques allow drillers to eliminate or reduce the offshore fields because of the extra
hydrostatic pressure of mud in the riser.
fracture-pore features. All these could cause lost circulation and overflow, narrow drilling
fluid density window, the occurrence of both blowout and lost circulation, posing high threat
to well control. Currently, there are few technical means available to deal with such complex
conditions.
Lost circulation is one of the major causes of NPT. It occurs when the mud density is
increased to the point where the formation fracture pressure is exceeded. All drilling engineers are trained to control pressures down the hole. They are trained to increase the mud
density as the first response to lost circulation in order to avoid well kicks and trip gas. In
MPD, maintaining the mud density below the fracture pressure and using a variable annular
back pressure at the surface enable the operator to maintain the well-bore pressure between
the pore pressure and fracture pressure. Therefore, lost circulation and well kicks are
avoided.
5.2.6.4 Well kicks
The objectives of MPD are to ascertain the downhole pressure environment limits and to
manage the annular hydraulic pressure profile accordingly. It means that the annular pressure profile is controlled from surface in such a way that the bottom hole circulating pressure
(BHCP) is balanced with the pore pressure at all times. This balance is perturbed whenever a
well kick is detected. MPD seeks to avoid the problem of well kicks by carefully monitoring
the ECD in the hole and controlling inflow and outflow or pressure changes in the well bore
with impressed surface pressure. Under carefully controlled conditions, an incipient well kick
caused by ECD change can be dissipated without consequences.
5.2.6.5 Differentially stuck drill pipe
Stuck pipe is a major cost issue in some drilling in most drilling operations. Differential
sticking is, for most drilling organizations, the greatest drilling problem worldwide in terms
of time and financial cost. It is a condition, for which the drillstring cannot be moved (rotated
or pushed up and down) along the axis of the wellbore. Differential sticking typically occurs
5.2 Managed pressure drilling
399
when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both,
are exerted over a sufficiently large area of the drillstring. It is important to note that the sticking force is a product of the differential pressure between the wellbore and the reservoir and
the area that the differential pressure is acting upon. This means that a relatively low differential pressure (Dp) applied over a large working area can be just as effective in sticking the
pipe as can a high differential pressure applied over a small area. Often a well kick initiates or
is the result of the pipe sticking. Under the stuck pipe scenario, the mud filter cake retards the
flow of liquid into the lower-pressure permeable zone and the pipe is differentially stuck
against the wall.
5.2.6.6 Deepwater drilling
Deepwater programs are challenging from many angles. The numerous technical challenges coupled with the economics of deepwater projects make it essential to plan a tedious
MPD program. Dual gradient drilling methods have been proposed as a means to provide
simpler, safer, more economic well designs and subsequently increase the ultimate development and utilization of deepwater resources. A new system that would provide a more simple and economic design consisting of a light density fluid equivalent to a seawater density in
the riser annulus and of a higher density mud in the wellbore is expected to provide a favorable pressure profile in these deepwater wells with narrow pore and fracture pressure
margins. This system is called a dual density, gaslift system and is intended to utilize
more standard equipment than the separate industry projects called dual gradient systems
focused on the use of seafloor pumps to achieve the advantages of a dual gradient method
(Stanislawek, 2005). Two different fluid gradients would be present in this system. Specifically, one from the surface to the mudline being equivalent to a seawater gradient, and
the second one in a wellbore below a mudline to provide enough overbalance for a trip
margin. The apparent advantages of such a system would be fewer casing strings, larger
mud weight margins, and larger production casing size for increased production revenue.
Dual-density drilling has evolved a solution to this problem. A “riserless system” pumps
the heavier drilling fluid down the drillpipe but recovers it at the subsea wellhead and,
with a subsea pump, returns it through an umbilical line connected to the drilling vessel.
The subsea pump supports the column of mud to the surface. This solves the problem of
increased pressure from a long column of heavy drilling fluid in the annulus. In the upper
hole intervals of deepwater wells, drilling with returns to the seafloor is a common practice.
Seawater is being used as the drilling fluid and when formation pressure requiring higher
density mud is encountered, seawater as a drilling fluid is stopped. The desirability of maximizing the well depth before installing the blowout preventer stack and riser has resulted in
the use of a weighted mud with returns to the seafloor that is referred to as “pump and
dump.” It is a truly dual density drilling method, but it does not provide for reuse of the
drilling fluid or a positive method of well control.
In deepwater drilling, the fracture pressure of the soft sediment on the seafloor is approximately equal to overburden pressure. Within the sediment, sand containing water zones is
pressured to near overburden pressure. The long column of drilling fluid in the riser can
be given the density to control water flows just below the casing shoe, but as the open
hole is deepened, any increase in drilling fluid density required to control the deeper and
more-pressured water flow will cause lost circulation at the shoe or drive pipe. One solution
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5. Advances in managed pressure drilling technologies
to this problem is “pump and dump.” A drilling fluid heavy enough to hold back any water
flows is pumped down the drillpipe and up the annulus to the seafloor, where it is dumped.
This process has potential environmental problems, particularly when the mud used is heavy
on synthetic materials. Although the presence of crude oil is also considered to be environmentally toxic, scientifically crude oil can be assimilated with the ecosystem, unlike synthetic
chemicals that are added to the mud system.
5.2.7 Basic mathematics behind MPD
Mathematical formulations used in programming MPD are simple that involve solutions
of algebraic equations that govern the fluid flow in the drilling pipe. Various levels of calculations are presented below.
5.2.7.1 Bottomhole pressure calculations with liquids
The bottomhole pressure in a well bore filled with a drilling fluid are reasonably approximated with the following equation:
BHP ¼ D r C
(5.2)
where, BHP ¼ bottomhole pressure
D ¼ depth
r ¼ density
C ¼ units conversion factor
The thermal expansion in both water-based and oil-based mud can lead to the calculation
of bottomhole pressure that is calculated by the simple BHP expression, particularly for oilbased or inverted emulsion cases. For heavy oil cases, oil-based drilling fluid compression can
override the expansion effects of high temperature and increase bottomhole pressure.
Hydrostatic pressure calculation in deep wells, with high bottomhole pressure and temperature, requires a correction for the fluid density of each interval of the hole. As Fig. 5.11
shows, increasing temperature decreases the density of fluid, while increasing pressure
increases fluid density. The effect of pressure is particularly significant in synthetic and oilbased mud.
5.2.7.2 Basic well control
Almost all MPD operations involve circulating a well as a closed system with a constant
pump rate and choke control. The MPD techniques tie back to some of the basic wellcontrol procedures with some modifications. Well-control ideas apply directly to a very specific condition of no lost returns and a minimal amount of gas spread out through the mud
column (and no gas in the drill pipe). Following steps are given as a general guideline for well
control (Rehm et al., 2013).
5.2.7.3 Driller’s method
The following steps are for the “driller’s method” of well control:
1. Shut in the well on a kick.
5.2 Managed pressure drilling
401
FIGURE 5.11 The density of drilling fluids, especially oil-based fluids, changes with pressure and temperature. In
high-pressure/high-temperature wells, the density change may be significant (Rehm et al., 2013).
2. Read the shut-in drillpipe pressure, annulus pressure, and kick size (pit volume increase).
3. Start circulating using the predetermined slow-rate circulating pressure (SRP) plus the
shut-in drillpipe pressure, or hold the annulus pressure constant until the pump rate is up
to the planned slow rate, then hold the drillpipe pressure constant.
4. Continue circulating keeping the pump rate constant.
5. Circulate until the kick is out of the hole.
6. Calculate:
a. The mud density increase.
b. The time required for the mud to fill the drillpipe (surface-to-bit time).
7. Start pumping at the required rate and hold the annulus pressure constant until the new,
heavier mud fills the drillpipe.
8. Then, hold the drillpipe pressure constant until the well is clean and shut-in drillpipe
pressure (SIDPP) and shut-in casing pressure (SICP) are zero.
5.2.7.4 Dual gradient methods
Well control methods for the subsea mudlift dual gradient drilling method have been
fairly well developed. Schubert et al., (2003) provided a description of how essentially conventional well control methods would be applied with a subsea mudlift system. His model
describes kick detection for subsea mudlift drilling by comparing conventional and dual
gradient methods. An important assumption and kick indicator for the subsea mudlift system
is that subsea pumps operate on a constant inlet pressure and the increase in flow may be
seen by an increase in the subsea pump rate, this value is closely monitored by system computers. A U-tube phenomenon is described along with a Drill String Valve (DSV) to arrest it.
Furthermore, a “shut-in” procedure is presented where influx is stopped and circulated from
the wellbore without complete shut-in. Schubert et al., (2003) proposed to retard the subsea
pumps to the rate before the kick and allow the drillpipe pressure to stabilize. Afterward, the
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5. Advances in managed pressure drilling technologies
drillpipe pressure and pump rate should be recorded and kept constant while circulating the
kick from the wellbore. Adjusting the subsea pump inlet pressure would maintain the constant drillpipe pressure in a way similar to the conventional kill procedure with the choke.
Determination of SIDPP with DSV is equal to the postkick opening pressure with pumps
at slow circulating rate minus the prerecorded opening pressure. In the case when no DSV
is used, a more complicated approach must be undertaken to determine SIDPP. Kick circulation concerns are addressed including measurement of kick circulating pressures and determining a drillpipe pressure schedule.
The U-tube effect, mentioned above, is a complication that results from the pressure in the
well annulus at the wellhead being significantly less than the pressure inside the drillstring at
the same depth. It is caused by the dual gradient only existing in the annulus whereas the drillstring is filled with the weighted mud from surface to total depth. Therefore, the U-tube created
by the drillstring and the annulus is inherently unbalanced. This unbalanced U-tube creates
several complications for well control. The traditional method of using a flow check to verify
whether a kick is being taken is impractical because returns will continue from the annulus until the U-tube becomes balanced due to the fall of the fluid level in the drillstring. This process is
expected to be too slow to be practical or safe. The hydrostatic imbalance affects surface and
downhole pressures if the well is shut-in conventionally. Therefore, a special drillstring valve
(DSV) has been developed to help overcome this complication. It is essentially a back pressure
valve placed in the drillstring to oppose, or support, the excess hydrostatic pressure in the
drillstring. It allows the well to be shut in at the subsea BOP or the seafloor pump without
the excess hydrostatic pressure in the drillstring being imposed on the annulus, which would
typically cause lost returns. Once the well is shut in, an annulus pressure greater than the
normal seafloor pressure is indicative of a kick being taken. Trapped pressure can be relieved
by operating the mudlift pump, and if continued pumping is required to maintain a pressure
equivalent to seafloor pressure then the well is confirmed to be flowing.
One possible way to overcome these problems is with the use of a dual density drillingsystem or, as it is sometimes referred to, a “dual gradient drilling” system. This system uses two
fluids with different densities in the wellbore as opposed to the single density used in conventional drilling. These two fluids can give a more favorable pressure profile in the well
compared to conventional drilling.
The basic flow paths for such a system are shown in Fig. 5.12.
Choe et al. (2004) investigated kick detection in subsea mudlift drilling with the inherent
U-tube effect. He determines the transient flow rate and the corresponding mud level inside
the drillpipe. A comparison of kick detection methods while circulating for subsea mudlift
and conventional drilling was presented. They considered two cases as a means to detect a
kick during the U-tube effect, one with the circulation rate that is higher than the maximum
free fall rate, and the second one with the circulation rate below the maximum free fall rate.
When circulating with the drillstring full of mud, an increase in return flow is indicative of a
kick as long as surface rate is higher than the free fall rate. If the drillstring is not full of mud
due to pump rate lower than the maximum free fall rate, kick indications are missing as fluid
level in the drillstring is unknown and surface pressure equals zero. Summarizing, if circulation rate is higher than the maximum free fall rate, kick detection will be much more feasible
compared with the circulation rate below the free fall rate. Choe et al. (2004) calculated the
drilling its trajectory with directional data, such as measured depth, inclination angle, and
azimuth as inputs. They suggested the use of the radius of curvature method, the minimum
5.2 Managed pressure drilling
403
FIGURE 5.12 Conventional drilling profile. From Shelton, J., 2005, Experimental Investigation of Drilling Fluid
Formulations and Processing Methods for a Riser Dilution Approach to Dual Density Drilling, Master’s thesis, Department of
Petroleum Engineering, Louisiana State University.
curvature method, or one of many other methods available in the literature for trajectory
calculation. Their calculations are in a 2D plane, especially for well planning.
Their wellbore simulator is based on constant bottomhole pressure (BHP), which is the
same or slightly higher than the formation pressure to prevent an additional kick. The
problem is reduced to determining surface choke pressure, required to maintain the predetermined BHP. There are two typical types of assumption for gas kick: One is two-phase; and
the other is single-phase. Well control models are also available for special purposes such
as subsea mudlift drilling. For the Two-Phase Kick Model, one assumes the kick as a twophase mixture, and there are many computer models for analysis of transient kick behavior.
Eight variables describe the two-phase flow system completely. They are:
-
Pressure;
Temperature;
Gas and liquid fractions;
Gas and liquid densities; and
Gas and liquid velocities.
For water-based muds, they assumed incompressible mud with known temperature
gradient in the wellbore. Therefore, there are five unknowns such as gas and liquid velocities,
gas fraction, pressure, and gas density for typical water-based muds. Five equations are
required to calculate the unknown variables with boundary conditions. The following equations are applicable to a variable annulus geometry.
The conservation of mass equation for mud is:
v
v
ðArm Hm Þ þ ðArm vm Hm Þ ¼ 0
vt
vx
(5.3)
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5. Advances in managed pressure drilling technologies
The conservation of mass equation for gas is:
v v
Arg Hg þ
Arg vg Hg ¼ 0
vt
vx
(5.4)
The conservation of momentum for the mud-gas mixture is:
i
v h vpf v vp
A rm vm H m þ rg vg H g þ
þ rm vm þ rg vg g ¼ 0
A rm v2m Hm þ rg v2g Hg þ A þ A
vt
vx
vx
vx
(5.5)
The two-phase correlation to calculate in-situ gas velocity is:
vg ¼ f ðvm ; vg ; q; do di ; s; p; TÞ
(5.6)
The equation of state to compute gas density is:
rg ¼ 0:3611
gg p
zT
(5.7)
Where, A is the flow area, r is the density, H is the volume fraction, v is the velocity, p is the
pressure, T is the temperature, and z is the gas deviation factor. Subscripts m and g denote
mud and gas, respectively.
The Single-Phase Kick Model assumes that kick fluid enters into the well as a single phase
and remains as a single slug all the time. A single-phase model is easy to use. However, it
cannot consider gas slip velocity as a function of gas fraction. It also overestimates kick volume and choke pressure compared to a two-phase model. As long as the gas kick remains in
the well, the two major unknowns are the pressure and volume of the kick. Pressure and volume of the gas kick are calculated from the real gas law and the dynamic system equilibrium.
Vk;x ¼ Vk;b
pb zx Tx
px zb Tb
pb ¼ pk;x þ Dpf þ Dphy
(5.8)
(5.9)
where, V is the volume. Subscript k denotes the kick and subscripts b and x represent the
bottom and the given depth x of the well, respectively.
The kick model can be modified for a dynamic two-phase well control simulation. It is
highly sensitive to the time step size selected so that it cannot have an arbitrary time step
or grid size. Since a transient two-phase model has numerical problems for an arbitrary
time step size, the modified two-phase model proposed by Choe and Juvkam-Wold (1996,
1997) was used. Their model is applicable for vertical, directional, horizontal, and multilateral
wells with a kick induced by tripping. The modified two-phase model mimics a two-phase
mixture as several slugs and each slug has an effective gas fraction. By assigning the initial
gas fraction correctly, they can match the modified model with their fully dynamic model
within 5% relative error for most cases.
5.2 Managed pressure drilling
405
The kick influx rate was computed assuming an infinite acting reservoir with data from
Table 5.1. Although an actual kick was detected by a combination of several kick indicators,
for the simulation purpose, a kick was detected by a preset pit volume gain of 10 bbls. The
return rate difference, delta flow, and pit volume gain are common and reliable detection
methods. The final pit volume gain would be different depending on well trajectory and
reduction of BHP due to the kick (Fig. 5.13).
Fig. 5.14 shows a comparison of the choke pressure for directional, extended reach,
and horizontal wells at the final hold angle of 40, 80, and 90 degrees, respectively. The
SICP decreases as the final hold angle increases to horizontal. The choke pressures for the
extended reach well are similar to that of the horizontal well except for the time delay
(Fig. 5.15).
Fig. 5.16 shows a comparison of the choke pressure for three different horizontal hold
lengths. If there is no horizontal hold section, the SICP is higher than the SIDPP. However,
they are the same as long as all the kick remains in the horizontal section due to no hydrostatic pressure loss in the well. For the case with the 8000 ft hold section, the choke pressure
remains constant when the kick is in the horizontal section. The difference between the SICP
and the constant choke pressure is the amount of frictional pressure loss in the annulus.
Fig. 5.17 shows the choke pressure for a medium radius and long radius well, whose BURs
are 10 and 1 degrees/100 ft, respectively. For the medium radius of 573 ft, the choke pressure
increases rapidly when the kick starts to fill the build section of the well around 30 min. The
increase in choke pressure results not from the kick expansion but from the increase of the
kick vertical height. After the kick passes the entire build section, the choke pressure is
relatively constant. For the long radius of 5730 ft, it shows a gradual increase of the choke
pressure when the kick fills the build section.
5.2.7.4.1 Riser gas lift
Lopes (1997) detailed the riser gas lift technique in his Ph.D. dissertation. He conducted a
feasibility study on the use of an automated riser gas lift system used on a marine riser. The
lift system is set up so that it would maintain a sub-sea wellhead pressure that is the same as
the surrounding seawater pressure. The control of abnormal formation pressures is to be provided by a weighted mud system in the wellbore, as part of the MPD process. Lopes (1997)
proposed a shut-in procedure for dual density drilling. He indicates that after a kick is
detected, the pumps should be stopped. The nitrogen injection should be stopped also and
the BOP should be closed with the choke line open. The choke line should be kept filled
with seawater, as it is the common practice. The density difference between the mud inside
the drillstring and the composite column in the wellbore and choke line should lead to a “Utube” effect. This lowers the mud level until the hydrostatic pressure in the drillstring equals
the bottomhole pressure. The difficulty here is how to determine the bottomhole pressure,
since the liquid level inside the drillpipe is below surface. There should be no pressure
reading in the drillstring. One solution was proposed by Lopes (1997) to read the pressure
using a well sounder to determine the fluid level inside the drill pipe. This approach however, would include complications while waiting for pressures to equalize. That might inevitably lead to the underbalanced conditions in a well as indicated by Lopes. He also
proposed using the bullheading procedure for kick circulation if the open hole interval is
small. He briefly stated that reduction of the gas injection rate to increase bottomhole
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TABLE 5.1
5. Advances in managed pressure drilling technologies
Input data used by Kong et al. (2014).
Mud density, ppg
14
Fluid model used
Power-law
Water depth, ft
5,000
Plastic viscosity, cp
64
Bingham yield point, lbs/100 ft
2
40
Number of bit nozzles
3
Bit nozzle diameter, 1/32nd in.
12
Well vertical depth, ft
10,000
Depth of last casing seat, ft
15,000
Length of HWDP, ft
1,000
Length of drill collars, ft
600
Inner diameter of the last casing, in.
9.01
Open hole diameter, in.
8.75
OD and ID of drill pipe, in.
5 4.214
OD and ID of HWDP, in.
5.5 3
OD and ID of drill collars, in.
7.5 2
Circulation rate while drilling, gpm
410
Kill circulation rate, gpm
205
For kick analysis:
Formation over pressure, psi
832
Gas specific gravity
0.65
Mud compressibility, 1/psi
6.0E-6
Surface temperature, F
70
Mud temp. grad. to 4220 ft water depth
0.9 F/100 ft
Mud temperature grad. below mudline
1.1 F/100 ft
Minimum seawater temperature, F
32
Formation permeability, md
250
Formation skin factor
2
Formation porosity, fraction
0.25
Rate of penetration, ft/hr
60
407
5.2 Managed pressure drilling
FIGURE 5.13
Pressure profiles for dual density drilling and conventional drilling.
FIGURE 5.14
Pressure versus depth for dual density drilling.
Directional
Extended Reach
Horizontal
2000
Pressure, psing
1500
1000
500
0
0
50
100
150
200
Time, minutes
250
300
350
FIGURE 5.15 Comparison of surface choke pressure for directional (40 degree), extended reach (80 degree), and
horizontal (90 degree) wells. Numbers indicate the final hold angle in degree of each trajectory.
408
5. Advances in managed pressure drilling technologies
0 ft
2000
4000 ft
8000 ft
Pressure, psig
1500
1000
500
0
0
50
100
150
200
300
250
350
Time, minutes
FIGURE 5.16
Comparison of surface choke pressure for different final hold length.
2000
1 deg/100 ft
10 deg/100 ft
Pressure,psig
1500
1000
500
0
0
50
100
150
200
250
300
350
Time,minutes
FIGURE 5.17 Comparison of surface choke pressure for different buildup rates.
pressure and underbalanced techniques should be considered for the future well control
research (Fig. 5.18).
Stanislawek (2005) examined riser gas lift with the multiphase flow simulator, OLGA. This
work included a mathematical model of mud and gas flow into OLGA to recreate the real
well settings of Lopes. He then compared the results of his simulations to Lopes’ results.
This was done to evaluate and confirm the validity of OLGA for use in making determinations upon transients and multiphase flow in a riser gas lift system. Once the relevance of
OLGA was verified, it was used to define gas requirements, the practical limits, and develop
well control methodology for a riser gas lift system.
409
5.2 Managed pressure drilling
Dilution Fluid
Pump
Separation
System
Wellbore Fluid Pump
Riser
Fluid
Marine
Riser
Casing
String
Dilution
Fluid
Sea Floor
Drillstring
Wellbore Fluid
Wellbore
FIGURE 5.18
Fluid flow paths for a dual density system based on riser dilution.
Herrmann and Shaughnessy (2001) proposed a variation of riser gas lift. This system
would use smaller, high pressure, concentric risers to reduce the required volumes of gas.
The modified system would also allow use of a surface blowout preventer stack. They proposed that in order to avoid the inherent well control concerns with dual density system,
only the upper part of the well should be completed using the gas lift system and the prospective pay zone should be drilled using the conventional drilling system. This will probably
decrease the chance of kicks and simplify well control as well. According to them, a drilling
break and reduced pump pressure with nitrogen injection rate constant will indicate a kick in
progress. The U-tube effect will take place and mud level in the riser should be measured. In
this process, pressure sensors should be applied to give the direct measurement of the wellhead pressure and riser mud level as well. Finally, Herrmann proposed shutting down and/
or decrease the gas injection rate as an promising alternative to control a kick.
Shelton (2005) introduced another variation to this technique. It involved the injection of a
low density liquid into the base of the riser to achieve dual density drilling and was referred
410
5. Advances in managed pressure drilling technologies
Dilution Mud
8.5 ppg
8.6 ppg
88.1% Total Flow
1st Stage OF
83.3% Total Flow
2nd Stage OF
Riser Mud
2
9.5 ppg
10.35 ppg
4.8% Total Flow
1
100% Total
Flow
1st Stage
Feed
2nd Stage UF
16.15 ppg
Wellbore Mud
14.5 ppg Calculated
14.55 ppg Measured
16.7% Total Flow
11.9% Total Flow
1st Stage UF
FIGURE 5.19 Hypothetical two-stage hydrocyclone scheme using results from actual tests (1: First stage
hydrocyclone; 2: Second stage hydrocyclone).
to as “riser dilution.” This modification is aimed at formulating a drilling fluid that would
effectively suspend solids and transport cuttings after heavy dilution with an unweighted
dilution fluid. Rendering the process continuation would make the system sustainable.
He suggested a 2-stage hydrocyclone process (Fig. 5.19) that yielded improved results. A
qualitative comparison showed that a hydrocyclone separation system may offer a feasible
and desirable alternative to centrifuge separation system at a lower capital and operational
cost. A hydrocyclone system may be able to provide similar density separations while
achieving better emulsion stability.
5.2.7.5 Magnetic gradient drilling
Although MPD implies mainly mechanical manipulation of the hydraulic pressure within
the drilling system, there is much room to include mud rheology to the solution spectrum.
Part of this newly proposed managed pressure drilling method is the new drilling fluid,
such as a magnetorheological fluid. A magnetorheological fluid is a fluid, for which the yield
stress changes due to the influence of a magnetic field. Typically, a ferromagnetic material is
used as the weighting material instead of barite. Nielsen (2018) proposed a new technique,
capable of increasing the density of the drilling fluid, thereby increasing the pressure at
greater depths. This can facilitate the process to stay within the mud weight window. In
this technique, the drilling fluid is changed to a magnetorheological fluid, which is a fluid
whose apparent viscosity is modified through the application of a magnetic field. Experimental results suggest that a stable magnetorheological drilling fluid can be created. Using
this magnetorheological fluid, in combination with a magnetic tool, it is possible then to
generate pseudochokes downhole. This allows for operator controlled pressure drops in
the wellbore, increasing the pressure upstream of the tool location without affecting the pressure window downstream of the tool. More importantly this allows for the use of a lower
density drilling mud, and create pressure drops that allow it to follow more complex casing
5.2 Managed pressure drilling
411
FIGURE 5.20 A typical measured result of piston displacement and flow pressures across the rectangular channel
with MR effects (Wang and Gordaninejad, 2006).
setting lines within the drilling plan. Thus the benefits of a typical MPD are accentuated. In
addition, it has advantage of allowing this to be performed at multiple locations within the
wellbore. This will enable the operator to reach the formation with less strings of casing and
cementing, and due to the time associated with casing and cementing also lower time to drill
the well.
When a magnetic field is applied, the iron particles align themselves with the magnetic
field and create a barrier to flow. The particles are attracted to each other due to the magnetic
dipoles they obtain while under the influence of the magnetic field, resembling a chain of particles (Wang and Gordaninejad, 2006). Their typical results for the input and output profiles
are presented in Fig. 5.20. As can be seen from this figure, initially, an internal pressure of
approximately 300 kPa (50 psi) was applied by the accumulator. A pressure drop offset about
30 kPa (6 psi) across the channel test section was observed. For the first ramp, the piston
pushes the MR fluid through the channel with a constant velocity. As a result of the MR effect, the pressure drop (Dp ¼ P1eP2) across the magnetically activated region increases significantly. This pressure drop is defined as the dynamic pressure drop, since its value depends on
the combination of the applied magnetic flux density and the input velocity of the piston. In
this study, the dynamic pressure drop experimental data can establish the shear stress and
shear strain rate relationship needed to obtain the apparent viscosity and dynamic yield
stress of MR fluids. or the second ramp, the piston returns to its original position. Both the
pressures P1 and P2 decreased, while the accumulator pushes the MR fluid back. In addition,
P1 drops more than its initial pressure. This means that a vacuum may have been formed in
the inlet chamber. The material resistance due to the MR effect may prevent the MR fluid
returning back completely. A negative pressure drop is obtained at this phase. This pressure
drop is referred to as the static pressure drop, as shown in Fig. 5.20. The static pressure drop is
highly dependent on the magnetic flux density and nearly is unaffected by the piston
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5. Advances in managed pressure drilling technologies
movement or the second ramp; the piston returns to its original position. Both the pressures,
P1 and P2 decreased, while the accumulator pushes the MR fluid back. In addition, P1 drops
more than its initial pressure. This means that a vacuum may have been formed in the inlet
chamber. The material resistance due to the MR effect may prevent the MR fluid returning
back completely. A negative pressure drop is obtained at this phase. This pressure drop is
referred to as the static pressure drop. When the piston is completely stopped, after returning
to its initial position, the static pressure drop can be kept in equilibrium until the magnetic
field is switched off. After a short period, following the input electric current being turned
off, the pressures P1 and P2 recover to their original values, as can be seen in Fig. 5.20.
This would suggest that the static pressure drop is the minimum pressure that can induce
MR fluid flow.
The strength of this effect is dependent on the strength of the magnetic field, as well as the
volume percent of ferromagnetic materials (Bossis et al., 2002). They investigated fundamental properties of these materials as related to the gelation of the suspension and prevalent
hydrodynamic forces. They also developed analytical models to predict the yield stress that
can explain how the combination of field and flow can give rise to a very rich rheology with
hysteresis and shear-induced phase separation.
They performed certain experiments on steel spheres, with known bulk magnetic properties. The magnetization curve was well fitted by a FrolischeKennelly curve: M ¼ miMs/
(MsþmiH) with Ms ¼ 1360 kA/m and mi ¼ 250. Then the radial force Fr between two spheres
has been calculated by using either finite elements or a simplified model. The experiments
were conducted by shearing chains of seven steel spheres (of diameter 1 mm) placed on a
ring inside a rheometer. The spheres at the extremity of the chains were glued on the rings.
The finite element calculations were found to be close to the experimental result.
The yield stress data are plotted in Fig. 5.21. This graph was generated for millimetric hard
spheres at a volume fraction of 15%. The experimental yield stress (solid circles) appears to be
quite below the analytical prediction (upper curve), and as already stated, the finite element
calculation lies in between.
Since the fluids response decreases relative to the amount of ferromagnetic particles it contains, it could be possible that at the desired fluid densities that would be applicable to field
use the magnetorheological fluid does not show an adequate yield stress response for the
desired application. If this is the case then either the fluid has to be changed such that
more ferromagnetic particles can be added, or the particles themselves must be changed in
such a way that the magnetorheological response is increased. Research has shown that partial substitution of the iron 6 microspheres with iron nanowires can greatly increase the fluids
response to an applied magnetic field, while also greatly decreasing the particle settling rate
of the iron microspheres (Jiang et al., 2011). Jiang et al. (2011) prepared a special type of
dimorphic magnetorheological (MR) fluid by adding wirelike iron nanostructures into the
conventional carbonyl iron-based MR fluid. The Fe nanowires were synthesized through
reducing Fe2þ ion with excessive sodium borohydride in aqueous solution. The rheological
behaviors of the dimorphic MR fluids were measured with a rotational rheometer and the
sedimentation properties were also studied in this work. It was found that the Fe wires
additives can greatly enhance the stress strength of the dimorphic MR fluids. Results demonstrate that the shear stress increases with the magnetic field strength. It is worth mentioning
that the shear stress of the dimorphic MR fluid is much higher than that of the conventional
5.2 Managed pressure drilling
FIGURE 5.21
413
Yield stress for a suspension of steel spheres; F ¼ 15%.
CI-based MR fluid containing the same weight ratio of CI and nano Fe wires. For fluid containing 6 wt% magnetic nanowires with and without spherical CI particles, the shear stresses
are 34.71 KPa and 373.8 Pa, respectively. Meanwhile, under the same magnetic field strength
(0.5 T), the shear stress of the conventional MR fluid is only 17.44 KPa. It can be calculated
that the shear stress of the dimorphic MR fluid is even higher than the sum of the shear
stresses of the conventional CI-based MR fluid and the Fe nanowires-based ferrofluid. These
results indicate that the Fe wirelike products can greatly improve the stress strength of MR
fluids. In addition, under the same magnetic field strength (0.5 T) and the same shear rate
(100 s1), the shear stresses of the MR fluids containing 2, 4, and 6 wt% of Fe nanowires
are 22.96, 30.41, and 34.71 KPa, respectively.
Some research has suggested that the pressure the fluid is under also has a significant effect on
the change in yield stress. According to Zhang et al. (2004), an approximately 220 psi increase in
pressure, from atmospheric, can result in a 25 times increase in yield stress (Zhang et al., 2004). The
method for this compression-assisted aggregation, referred to in research as the squeeze strengthening effect, is believed to be a rearrangement of the aligned ferromagnetic particles; such that the
particle chains attach to each other increasing their thickness (Hegger and Maas, 2016). This
squeeze strengthening effect only occurs when the pressure increases while the fluid is under
the influence of a magnetic field (Hegger and Maas, 2016). Also this squeeze strengthening effect
will diminish as higher amounts of shear on the material occur (Spaggiari and Dragoni, 2012). In
other words, once the material is flowing these interconnected chains break back up into single
chains (Hegger and Maas, 2016). The problem with this research is that it involves creating a strain
on the flow path, which therefore also reduces the cross-sectional flow area and potentially gives
false results for the change in apparent viscosity.
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5. Advances in managed pressure drilling technologies
FIGURE 5.22
Pressure drop across magnets versus batch number at 0.62 ft/s (60 Hz).
Nielsen (2018) conducted a series of experiments with magnetorheological fluids. Fig. 5.22
shows the pressure drop across the magnets as plotted versus the number of batches of
weighting material that had been added, for each flowrate tested. The 60 Hz (0.62 ft/s in
the annulus and 5.23 ft/s in the inner pipe), 50 Hz (0.51 ft/s in the annulus and 4.36 ft/s in
the inner pipe), and 10 Hz (0.10 ft/s in the annulus and 0.87 ft/s in the inner pipe) graphs
are shown for comparisons. It can be seen from the 60 Hz graph that the pressure drop across
the magnets is clearly different for the magnetorheological fluid versus the barite fluid. This
difference is not seen in the lower batch numbers, which suggest that there are either not
enough ferromagnetic particles for the effect to exist or not enough for it to be measured
in this setup.
While this technique has promises, much research work is to be done. Implementation of
this technique requires research to answer key questions. Following tasks are recommended:
1.
2.
3.
4.
5.
6.
7.
Scaled model studies, covering wide range of flow rates;
Effect of concentration of magnetorheological fluid in the mud system;
Effect of magnet size;
Time effect on stress-strain relationship;
Use of naturally occurring microspheres;
Effect of temperature;
Role of the type of magnetic field.
5.3 Underbalanced drilling
Conventional high pressure, high productivity reservoirs form a minority of the total available petroleum resource of the world. As the demand for petroleum resources grows and the
number of highly productive formations dwindle, low pressure marginal reservoir, naturally
fractured formations, and others have come to the forefront. These reservoirs are not
5.3 Underbalanced drilling
FIGURE 5.23
415
Schematic of underbalance drilling. From Air drilling Association Inc.
amenable to conventional drilling operations, for which high-density mud weight can be
maintained. For those reservoirs, underbalanced drilling, or UBD, can be helpful. It involves
the use of a mudweight, which the pressure in the wellbore is kept lower than the pressure
then the formation being drilled. As the well is drilled, formation fluid is allowed to flow into
the wellbore. This is in sharp contrast to the usual situation, where the wellbore is kept at a
pressure above the formation to prevent formation fluid entering the well. In conventional
drilling, the surge of wellbore pressure beyond the hydrostatic mud pressure would be
considered to trigger a kick and onset blow out. This is why, in underbalanced drilling there
is a “rotating head” at the surfacedessentially a seal that diverts produced fluids to a separator while allowing the drillstring to continue rotating. Fig. 5.23 Shows the schematic of the
underbalanced drilling process. Because the flow from the formation is continuous, well must
be controlled with a rotating control head, furbished with a rotating inner seal assembly that
is used in conjunction with the rotating table. An important factor to successful underbalanced drilling, drilling, and completion operations must remain underbalanced at all times
during operations.
Underbalanced drilling is performed with a light-weight drilling mud, which allows for a
mud pressure slightly less than the formation pressure. This increases the drilling penetration
rate while preventing formation damage. Formation damage is typical of any drilling that
uses conventional or overbalancing.
In addition to alleviating formation damage, lost circulation, differential sticking, and slow
drilling rates are minimized in underbalanced drilling. However, underbalanced drilling
cannot be used while drilling shaley formations. This aspect will be addressed in Chapter 6.
5.3.1 Gaseated mud drilling
Mud density is decreased with gas in the mud injection system. Some of the gases used for
underbalance are: air, nitrogen, and natural gas. Although it is not typical, if natural gas is
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5. Advances in managed pressure drilling technologies
recovered from the well, it can be reinjected into the well to establish underbalance, resulting
in the most cost-effective solution for underbalanced drilling. Recently, the word “gaseated”
has been in use to describe aerated, or gas/liquid mixtures (Rehm, 2012). Gaseated fluids are
used in reducing drilling mud density. The gas phase is embedded in the slurry, maintained
without the use of any emulsifier or surface active agent. In this system, the liquid can be
almost any fluid suitable for drilling or workover and this bulk phase determines the overall
characteristics, such as, inhibition, temperature stability, resistance to contamination, of the
system. Of particular importance is the consideration of dangers associated with surface
fire, downhole fire, corrosion, gas cost, and/or availability. On the mechanical side, it is
important to maintain the gaseated system in well mixed two-phase system. Because of
the gravity segregation, the gas phase tends to rise above the liquid or slurry phase, leading
to surge in pressure within the drillstem.
The application for using underbalanced drilling was first patented in the United States in
1866 (Rehm, 2012). The original application was contemplated for preventing lost circulation.
In 1932, for instance, the Imperial Oil Company used natural gas and bentonite drilling mud
to reduce lost circulation in the Atlas Mountains of Persia. Similarly, in 1939, in the Sour Lake
Field in Southeast Texas, natural gas injected into the mud was used to avoid lost circulation
in the depleted parts of the field. Even at that time, a Shaffer Rotating Head was listed in their
catalog at this time. Such applications continued through 1960s through 1970s for both petroleum and geothermal drilling operations. In the 1980s gaseated systems of natural gas and
diesel oil for reservoir protection in Canada and lost circulation control in North Africa
were used. During the1990s, a new area of applications was found. Underbalanced drilling
was adapted for offshore drilling throughout Europe and the technology moved into the
Middle East and Far East shortly thereafter.
The gasses described in the following material are (Rehm, 2012):
-
Air
Natural gas
Membrane nitrogen (N2 with some oxygen and trace gases)
Cryogenic nitrogen (pure N2)
Carbon dioxide (CO2) and super critical carbon dioxide
None of the gasses fits all the ideal functions of a gas in a particular system. The choice of a
gas is almost always a compromise between properties, availability, and cost.
In certain situations, gas drilling is used. In gas (and air) drilling, the following functions
are carried out:
-
Move the cuttings out from under the bit
Transport the bit cuttings and cavings to the surface
Transport any formation fluids or gas safely to the surface
Safely and simply release the cuttings and formation fluid and gas at the surface
Prevent or avoid corrosion of the drillpipe and casing
Cool the drill bit
Cool the air hammer or air motor
Be cost-effective
5.3 Underbalanced drilling
417
In the case of mist drilling, gas acts as the continuous phase in the annular flow of liquid
and gas. In this case, the annular flow of the liquid materially adds to the functions.
In gaseated and foam fluids, the following functions are carried out:
-
Reduce the hydrostatic head of the fluid by displacing part of the fluid out of the hole
Avoid any adverse reactions with formation fluids and gasses
Be consistent within the limits of the General Gas Law (so the gas can be modeled)
Be cost-effective
Help support the wall of the open hole
Move cuttings out from under the bit
Transport the bit cuttings and caving to the surface
Transport any formation fluids or gas safely to the surface
Safely and simply release the cuttings, formation fluid, and gas at the surface
Operate the hammer or mud motor
Help limit corrosion or not add to corrosiveness of the system
Cool and lubricate the bit and mud motor or hammer
Moderate some of the effect of pipe movement
Protect the formation from damage
5.3.2 Definitions
Flow (Live) operations: During which wellbore pressures maintained below formation
pressure and the well is intentionally allowed to flow during drilling or completion
operations.
Gasified Fluid Operations (aerated fluid operated): Operations intentionally undertaken
with a two-phase drilling fluid containing some form of gas mixed with a liquid phase.
No surfactant or emulsifier is present.
Foam Operations: Operations intentionally undertaken with a two-phase drilling fluid
containing some form of gas mixed with a liquid phase and tied together with a surfactant.
The liquid phase is continuous.
Gaseated Mud, Aerated Mud, or Gas/Liquid Mixture: It is a simple mixture of a drilling
fluid and a gas.
Quality: It is a measurement of the actual gas to liquid volume at any pressure point in the
hole. It can be reported as a percent, a decimal, or a whole number. Fig. 5.24 shows how
hydrostatic pressure changes the ratios and quality at different depths.
Jet Sub: It is a tool for introducing gas from the drillpipe into the annulus to help eliminate
the pressure build-up due to loss of gas in the drilling fluid in the upper section of the
annulus.
Concentric String, or Dual Casing String: It is a method of injecting gas near the bottom of
the hole.
Parasite String or Parasite Tubing String: It is a method for injecting gas near the base of
the surface casing.
Mist Operations: Intentionally drilling with a two-phase fluid having a gas as the continuous phase. The liquid in this fluid system is suspended in the mixture as droplets.
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5. Advances in managed pressure drilling technologies
FIGURE 5.24
Quality versus depth. From Rehm (2012).
Air Operations: Intentionally drilling using a pure gas as the drilling fluid. The gas can be
air, nitrogen, natural gas, or any combination of gases.
Mudcap Operations: Operations undertaken when the annular pressure during flow drilling exceeds the safe pressure limit of the rotating control element. Mudcap operations are not
underbalanced operations, but often are a result of drilling underbalanced and employ many
of the same techniques and equipment.
Snubbing Operations: An intentional operation that employs either a snubbing unit or
coiled-tubing unit in order to operate at surface pressures that exceed the limits of rotating
control elements such as rotating heads or rotating blowout preventers.
Coiled-tubing drilling: Use of a continuous-spool of pipe to drill with instead of the conventional jointed drillpipe.
5.3.3 Underbalance techniques
There are four main techniques to achieve underbalance, including using lightweight
drilling fluids, gas injection down the drill pipe, gas injection through a parasite string,
and foam injection. Using lightweight drilling fluids, such as fresh water, diesel, and lease
crude, is the simplest way to reduce wellbore pressure. A limitation of this approach is
that in most reservoirs the pressure in the wellbore cannot be reduced enough to achieve
underbalance.
5.3 Underbalanced drilling
419
There are several kinds of underbalanced drilling. The most common are listed below.
Dry air. This is also known as dusting. Here air compressors combined with a booster
(which takes the head from the compressors and increases the pressure of the air, but does
not increase the volume of air going down hole) are used and the only fluid injected into
the well is a small amount of oil to reduce corrosion.
Mist. A small amount of foaming agent (soap) is added into the flow of air. Fine particles of
water and foam in an atmosphere of air bring cuttings back to the surface.
Foam. A larger amount of foaming agent is added into the flow. Bubbles and slugs of bubbles in an atmosphere of mist bring cuttings back to the surface.
Stable foam. An even larger amount of foaming agent is added into the flow. This is of the
consistency of a shaving cream.
Airlift. Slugs and bubbles of air in a matrix of water and soap can or cannot be added into
the fluid flow of air.
Aerated mud. Air or another gas is injected into the flow of drilling mud. Degassing units
are required to remove air before it can be recirculated.
If the formation pressure is relatively high, using a lower density mud will reduce the well
bore pressure below the pore pressure of the formation. Sometimes an inert gas is injected
into the drilling mud to reduce its equivalent density and hence its hydrostatic pressure
throughout the well depth. This gas is commonly nitrogen, as it is noncombustible and
readily available, but air, reduced oxygen air, processed flue gas, and natural gas have all
been used in this fashion.
In performing the gas injection via parasite string, a second pipe is run outside of the
intermediate casing. While the cost of drilling increases, this technique applies constant bottomhole pressure and requires no operational differences or unique MWD systems.
A less common underbalanced application, nitrogen foam, is less damaging to reserves
that exhibit water sensitivities. While the margin of safety is increased using foams, the additional nitrogen needed to generate stable foam makes this technique cost prohibitive. Additionally, there are temperature limits to using foam in underbalanced drilling, limiting using
the technique to wells measuring less than 12,000 ft deep.
If the formation pressure is relatively high, using a lower density mud will reduce the wellbore pressure below the pore pressure of the formation. Sometimes an inert gas is injected
into the drilling mud to reduce its equivalent density and hence its hydrostatic pressure
throughout the well depth. This gas is commonly nitrogen, as it is noncombustible and
readily available, but air, reduced oxygen air, processed flue gas, and natural gas have all
been used in this fashion.
Coiled tubing drilling (CTD) allows for continuous drilling and pumping and therefore
underbalanced drilling can be utilized which can increase the rate of penetration (ROP).
In underbalanced drilling in a reservoir, the well is designed to allow the reservoir to flow
to surface while drilling. In underbalanced drilling, the wellbore pressure is maintained
below the reservoir pressure at all times, and the resulting inflow from the reservoir is carefully controlled during the entire drilling process.
The primary mechanism is given below:
For underbalanced drilling, Pr > Pwf ¼ Ph þ Pacc þ Pwh
where Pr is the reservoir pressure, Pwf the bottomhole pressure, Ph is the hydrostatic
pressure, Pacc is the pressure due to fluid acceleration, and Pwh is the wellhead back pressure.
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5. Advances in managed pressure drilling technologies
In the above equation, Ph is a function of gas and liquid densities and gas void fraction. Gas
density is strongly dependent on pressure and temperature. The gas void fraction depends on
the gas and liquid flow rates. Pacc is the acceleration pressure due to fluid acceleration. Naturally, this pressure depends on the flow rate. Pwh depends on the surface control on the
choke, gas and liquid rates, and surface pipe network. Therefore, all four components will
be dynamic and dependent on time and the state of the system. When a perturbation is added
to the system, for instance, change in either gas or liquid rate, all four components will change
accordingly. Depending on the design and the state of the system, a disturbance may be
damped out quickly, or on the other hand, it may lead to the instability of the system.
During underbalanced drilling, the well continues to be controlled by controlling the wellbore pressure. However, the pressure is maintained below the reservoir pressure. Primary
well control is no longer an overbalanced barrier of a column of fluid, but is replaced by
flow control using a combination of hydrostatic pressure, friction pressure, and surface choke
pressure. In this process, the BOP stack remains as the secondary well control barrier. Note
that a UBD well operates on a single barrier.
As shown in the expression above, the Bottom Hole Circulation Pressure is a combination
of hydrostatic pressure, circulation friction losses, and surface pressure applied at the choke.
The hydrostatic pressure is considered a positive pressure and is a result of the fluid density
and the density contribution of any drilled cuttings and a small contribution of any gas in the
well.
The friction pressure, which results from circulating friction of the fluid used, is a dynamic
pressure and is independent of the flow rate, as long as turbulent flow regime is maintained.
The choke pressure arises from annular back pressure applied at surface.
These three pressures are controlled at all times and ensure that flow control is maintained
while drilling underbalanced.
The bottomhole hydrostatic head avoids the build-up of filter cake on the reservoir
formation and avoids the invasion of mud and drilling solids into the formation. This helps
improve productivity of the wellbore and reduces any pressure related to drilling problems.
If the underbalanced condition must be generated artificially, gas injection via either drillstring or a type of parasitic string is employed. Since in an underbalanced drilling operation,
production occurs simultaneously, a UBD operation becomes a combined drilling and
production operation.
• The major factors involved are:
• Nonlinear two-phase flow system,
• Drill string connection
• Drilling and tripping operation
• Full liquid column for MWD survey
• Interrupted supply and equipment failure
• Initial flash production
5.3.3.1 Nonlinear two-phase flow system
If gas injection is used through either drillstring or a type of parasitic string, there will be
interactions between the gas injection line, the wellbore, and the reservoir. This system is
similar to a gas lift well. Similar to gas lift wells, the interactions among gas injection,
5.3 Underbalanced drilling
421
wellbore, and reservoir may lead to an unsteady gas injection rate into the well, unsteady
production from the formation, and unsteady wellbore pressures. These are all prone to instability. While the instability in gas lift wells is well documented, such information on underbalanced drilling is rare.
Before the injection gas breaks through into the well, the BHP and wellhead pressures are
relatively steady and the compressor pressure increases steadily. As injected gas starts to
enter the well with a sharp increasing rate and at the same time, both the BHP and
compressor pressure start to drop rapidly and wellhead pressure starts to increase. Wang
et al. (1997) observed that the energy in the gas injection line is depleted quickly. The injection
rate into the well peaks at t ¼ 76 min, then drops sharply, and becomes zero at t ¼ 90 min.
The BMP starts to increase at t ¼ 84.5 min. From t ¼ 90 min, no gas is injected into the well
from the concentric annulus, and the BHP increases rapidly due to fill-up of the top part
by hydrostatic head. The gas injection line is pressured up again in this period. At
t ¼ 130 min, gas starts to enter the wellbore again, a similar trend is observed as in the first
cycle. In order to avoid the kickoff problem, the wellhead pressure is increased to prevent the
wellbore pressure from dropping too rapidly. This is done by closing the choke somewhat at
t ¼ 136.5 min when we observe that BHP has dropped about 50 bar from the plateau of about
217 bar and the gas flow-out rate is increasing. Although the wellhead pressure is increasing
rapidly, the BHP continues to drop because the gas rate into the well is higher than gas flowout rate and gas expands rapidly as it approaches the surface. This action has stabilized the
system and the formation starts to produce again at t ¼ 150 min. A few minutes later, the
choke is opened gradually to the originally setting. The system becomes stable and approaches a steady one under the designed condition. This example provided by Wang
et al. (1997) demonstrates how the system interacts among the various flowing units.
5.3.3.2 Drill string connection
In jointed pipe drilling, drillstring connections are considered to be the most critical factor
causing pressure fluctuations and spikes, in particular, when drill string gas injection is used.
The magnitude of this effect depends on the gas injection method, i.e., drillstring injection or
parasitic string injection.
During drillstring connection, both gas and liquid injections are stopped. The bottomhole
pressure is reduced due to the part loss of the frictional pressure in the well. This reduction in
BHP may result in an increased oil and/or gas production. The extra production depends on
the type of the well, the reservoir productivity, and the designed reservoir drawdown. In horizontal wells with long exposed section, the extra production may be so much that it may
lead to the difficulty in regaining the circulation without causing an overbalanced condition
after a connection. This is typical because of the surface area contacted by a horizontal well
that is several times larger than a vertical well. During the stoppage period, fluid separation
occurs both in the drillstring and in the well. This is due to gravity segregation. Although the
hydrostatic pressure in the well is increased only by the extra production during connection,
the profiles of hydrostatic pressures in the well and drillstring are changed due to the accumulation of liquid slugs near the lower part of the well and drillstring. When the circulation is
reestablished, friction pressure is exerted on the bottomhole, liquid slugs in the drillstring are
then pumped into the well, increasing the hydrostatic pressure in the well, in addition to the
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5. Advances in managed pressure drilling technologies
fluid acceleration. Consequently, a pressure spike is often observed with a short period of
sustaining higher bottomhole pressure.
In case of parasitic (annulus) gas injection, when gas injection is facilitated with a parasitic
string, the pressure spikes, caused by drill string connection, may be smaller or larger
depending on the procedures used. When circulation is stopped for connection, a drop in
the BHP occurs due to loss of frictional pressure. If the annulus is left open during connection,
the drop in BHP and the stoppage of pump will lead to (i) an increased production from the
reservoir; (ii) an increased gas rate into the well from the parasitic string; and hence (iii) high
gas-liquid ratio in the gas lifted top part of the well. If caution is not exercised, the gas energy
in the gas injection line may be depleted quickly. During the stoppage period, fluid separation occurs in the top part of well if the annulus is closed. The hydrostatic pressure is not
increased probably much due to extra production during connection if the annulus is left
open. However, the profile of hydrostatic pressure gradient in the top part of the well may
change somewhat due to the accumulation of liquid slugs. When the circulation is reestablished, friction pressure is exerted on the bottomhole, plus fluid acceleration. If the gas energy
is properly preserved during connection, large pressure spikes may be avoided. Otherwise, a
pressure spike may be observed with a long period of sustaining higher bottomhole pressure.
Unlike in the case of drillstring gas injection, the BHP depends mainly upon the liquid holdup in the top part of the well and the gas injection rate into the well from the gas injection line.
The interaction between the well and gas injection is more important in this case.
5.3.3.3 Drilling and tripping
Tripping is considerably more challenging in maintaining the desired underbalanced conditions than the drilling operation itself. When a coiled tubing unit is used, circulation may be
facilitated while tripping in and out in the most part of the operation. The availability of circulation while tripping leads to a much better management of the underbalanced condition,
especially when drillstring gas injection is used. However, caution must be exercised when it
comes to BHA deployment during which period, circulation is not available. On the other
hand, when the conventional rig is used, circulation is not normally available continuously
during tripping although the well may be circulated at some intervals. If the drillstring is
not to be tripped with pressure on the well, the well should have been killed by the hydrostatic pressure before tripping. This causes an overbalanced condition, especially when reestablishing circulation when new bit is tripped in. Even when the string is snubbed out with
well pressure and production, the underbalanced condition may become lost due to depleted
reservoir pressure and the flowing well killing itself. When parasitic string gas injection is
used, a similar situation occurs unless the string is snubbed in and out under pressure. But
if the string is snubbed out, the underbalanced condition can be maintained since the gas
injection can be maintained during tripping.
5.3.3.4 Full liquid column for MWD survey
If drillstring gas injection is used, full liquid column may be required for conducting conventional mud pulsed MWD logging. This may lead to large liquid slugs into the well during
and after the data logging, hence creating a large pressure spike. With the increasing use of
and improvement in MWD, this restriction may be removed. When parasitic string gas
5.3 Underbalanced drilling
423
injection is used, full liquid column is available inside the drillstring and this does not present
any problem.
5.3.3.5 Interrupted supply and equipment failure
When gas injection is used, there are many reasons that a continuous supply is interrupted. During an UBD operation, more dedicated surface equipment and downhole tools are
used. This increases the probability of equipment failure. When equipment failure and/or
interruption in gas injection supply occur, the drilled portion may be exposed to an overbalanced condition either by hydrostatic pressure or in a shut-in condition. After stoppage,
the subsequent reestablishment of circulation results in the undesired bottomhole pressure
fluctuations.
5.3.3.6 Localized reservoir pressure depletion
By conventional definition, the pressure underbalance is defined as the difference between
reservoir pressure and the flowing bottomhole pressure. In a UBD operation, when the well is
underbalanced and has produced for a while, localized reservoir pressure depletion may
occur. This becomes more significant in the cases of low permeability reservoir, high underbalance pressure, and limited reservoir drainage area. A reservoir pressure profile is formed
during production as illustrated in Fig. 5.25. When this situation occurs, the dynamic wellbore pressure fluctuation will cause somewhat fluid invasion even if the largest spike is still
within the nominal reservoir pressure.
Similar pattern was depicted by Rehm (2012), as shown in Fig. 5.26.
FIGURE 5.25
Simulated results of an underbalanced drilling operation. From Wang, Z. et al., 1997, On the Dynamic
Effects during Underbalanced Drilling Operations and Their Prevention, OSTI Report 97/015.
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5. Advances in managed pressure drilling technologies
Drilling rate
Perfect
hole cleaning
Bi flounder
is not common
while drilling
with foam
Pb
Pp
-500
0
+500
+1000
Differential pressure, psi
FIGURE 5.26
Drilling rate for various differential pressures.
Assuming a steady state flowing condition without significant drillstring movement, the
average bottomhole pressure will be mainly determined by the following factors (Wang
et al., 1997):
•
•
•
•
•
•
•
Wellbore geometry;
Types of drilling fluid and injection gas;
Drilling fluid pump rate and gas injection rate;
Surface control procedures;
Injection methods;
Rate of reservoir production;
Reservoir fluids type, especially gas oil ratio.
5.3.4 Means of wellbore pressure reduction
As stated in previous sections, the wellbore hydrostatic pressure is reduced by adding gas
into the mud system. The addition of gas decreases bottomhole pressure by displacing fluid
out of the hole through hydrostatic reduction. In the hydrostatic regime, the wellbore pressure
is highly sensitive to changes in the gas injection ratio and can be unstable.
With continued increase in the volume of injected gas, the velocity of the liquid in the upper annulus increases and the flowing friction increases. The system enters the friction dominated regime, where the increase in liquid velocity in the upper part of the hole caused by
expanding gas creates friction that increases the wellbore pressure at that point. The increased
friction pressure keeps the gas from expanding with the result that further increases in gas
injection actually tend to increase the bottomhole pressure. The greater part of the friction
effect is from the wetted perimeter, which is a function of the conduit diameter.
425
5.3 Underbalanced drilling
Hydrostatically-dominated
Friction-dominated
Siim
hole
Large hole
Friction pressure
Hydrostatic pressure
Gas injection rate
FIGURE 5.27
Hydrostatic and friction dominated regimes (Rehm, 2012).
In the friction dominated regime, the bottomhole pressure is only slightly sensitive to gas
injection rate changes, and responds almost as a pure liquid to surface pressure changes, i.e.,
changes in choke pressure, as shown in Fig. 5.27 (Rehm, 2012).
In the high friction pressure regime, applied backpressure by choke stabilizes the system
and makes it possible to control the natural surging of gaseated systems. The gas injection
point can be in the stand pipe at the surface, downhole from a parasite tubing string, downhole through a ported collar that is run on a concentric string of casing, or through a special
dual drillpipe.
It emerges from the general gas law, gas compresses to half its volume every time the pressure is doubled, limited only by temperature and the gas compressibility factor (z). Near the
bottom of a deep well the gas is so compressed that even doubling the injected gas volume
does not significantly decrease the volume of fluid in that interval.
5.3.5 Challenges in UBD
UBD offers many benefits, but there are challenges as well. It is important to have excellent
planning. In addition, following aspects offer significant challenges.
5.3.5.1 Cost
UBD is normally more expensive on a daily basis than conventional drilling, especially in
remote locations. In addition to conventional operating costs, a rotating control device, compressors, separators, flare lines, storage tanks for oil if it is encountered, more personnel, and
more space is required, imposing a higher operational cost. The cost increases significantly if
an offshore location is involved. Similarly cost considerations are important if there is sour
gas present. Costs can be reduced by integration of the extra equipment and services that
are required to drill underbalanced (Rehm, 2012).
426
5. Advances in managed pressure drilling technologies
5.3.5.2 Pressure surges
The fluid system in UBD is inherently unstable. The gas and liquid separate by gravity and require mixing to keep them combined. The instability of a gaseated system induces pressure surges. The gas migrates up hole to form a large gas bubble zone while
the fluid falls down the hole to form a solid fluid column below the gas bubble. Pressure surges causes formation damage and wellbore instability problems. Pressure surging can be controlled during drilling by a combination of pipe rotation, velocity, and
surface backpressure held on the return annulus. During drilling, an impressed surface
pressure of 5e15 atmospheres keeps the gas compressed enough that with the upward
flow of fluid, the system stays unsegregated. The injected gas separates during connections when gravity causes the gas to move upward and liquid to displace downward.
The rate of separation depends on the size of gas bubbles and viscosity of the fluid.
Large bubbles move upward faster than small bubbles. This translates into keeping
the well pressurized with the 5e15 atmospheres (70e220 psi) of surface back pressure
to minimize gas bubble size is important. Increased viscosity of the liquid phase slows
down the gas-liquid separation but makes it more difficult to separate gas from liquid at
the surface as well as increasing the circulating density (ECD). Such viscosity increase
can be accomplished by adding additives. When these additives are natural, the process
becomes sustainable.
5.3.5.3 Other challenges
Several other factors must be considered. They are:
• Fractures: In presence of large wide fractures, the well fluid displaces into the fractures and
causes a continual low level lost return scenario, which will turn into a low level well kick
on a connection. The source of this problem is gravity displacement of the drilling fluid
and flow back when the pump is turned off.
• Imbibition: Capillary forces within the reservoir can cause fluid imbibitions, where liquids
are imbibed into the reservoir even though the wellbore is underbalanced. To minimize the
fluid imbibition, annulus pressure should be less than formation pressure by the value of
capillary pressure, and the liquid drilling phase should be the nonwetting phase of the
reservoir. Imbibition can be measured from cores in the laboratory.
• Periodic kill: It may be required unless the pipe is stripped/snubbed in and out or a
downhole valve is used. Going overbalanced to kill the well can damage the formation or
be ineffective due to lost circulation.
• Corrosion is a problem associated with the use of air because of oxygen introduction in hot
downhole environment.
• Surface fires and explosion can occur if hydrocarbons are presented with oxygen.
• Vibration of drillstring occurs because aerated drilling fluid does not support the pipe fully
as in the case of conventional drilling fluids.
• Friction factor is sometimes higher in aerated fluids compared to conventional fluids, thus
resulting in increased torque and drag.
• Proper hole cleaning might be a problem in aerated drilling fluids resulting in stuck pipe
and increase pressure drop.
5.3 Underbalanced drilling
427
5.3.6 Equipment for underbalanced drilling
For an underbalanced drilling process to be effective, following components have to be
optimized (Lyons et al., 2016):
Surface Stack Blowout Preventer (BOP). The use of a surface stack BOP configuration in
floating drilling is performed by suspending the BOP stack above the waterline and using
high-pressure risers as a conduit to the sea floor (in offshore applications).
Expandable Drilling Liners. EDLs can be used for several situations. Future advances may
allow setting numerous casing strings in succession, all of the exact same internal diameter.
The potential as a step change technology for optimizing drilling costs and mitigating risks is
phenomenal.
Rig Instrumentation. The efficient and effective application of weight to the bit and the
control of downhole vibration play a key role in drilling efficiency. Excessive WOB applied
can cause axial vibration, causing destructive torsional vibrations. Casing handling systems
and top drives are effective tools.
Real-Time Drilling Parameter Optimization. Downhole and surface vibration detection
equipment allows for immediate mitigation. Knowing actual downhole WOB can provide
the necessary information to perform improved drill-off tests.
Bit Selection Processes. Most bit vendors are able to use the electric log data (sonic, gamma
ray, resistivity as a minimum) and associated offset information to improve the selection of
bit cutting structures. Formation type, hardness, and characteristics are evaluated and
matched to the application needs as an optimization process.
5.3.7 Underbalanced drilling fluid perforation system
In underbalanced drilling, gas-based perforating fluids are used. The drilling fluid system
involves aerated (air, nitrogen, and so on) low-density completion fluids, which are further
divided into foam completion fluid, microfoam completion fluid, and so on in accordance
with the gas proportion and the type and density of polymer and additive. Microfoam
completion fluid was first used in the completion operation of a depleted reservoir in the
Lake Maracaibo area, in Venezuela. Microfoam is not single gas bubbles accumulated
together, but a microbubble network that can resist or mitigate the invasion of liquid into
the reservoir (Renpu, 2011). The original application involved heavy oil reservoirs. In general,
the microfoam volume can be up to 8%e14%.
This type of perforating fluid was developed to meet the requirements of completion and
workover of oil and gas wells of low-pressure fractured reservoirs, heavy oil reservoirs, lowpressure strong water-sensitive reservoirs, low-pressure, low-permeability reservoirs, reservoirs that easily have serious leakage, depleted reservoirs, and offshore deep-water wells.
Its features include low density, low filtration loss, and good effectiveness of oil and gas
reservoir protection. The types, preparation methods, and advantages and disadvantages
of various perforating fluids are listed in Table 5.2.
5.3.8 Benefits of underbalanced drilling
The reasons for underbalanced drilling can be broken down into three main categories:
TABLE 5.2 Types and advantages of various perforation fluids.
Subtype
Application
range
Advantage
Disadvantage
Drilling-in
reservoir,
perforating,
and well
killing
Adjusting performance of original drilling
fluid, such as adding clay- stabilizing agent,
fluid loss additive, and temporary plugging
agent, and increasing cationic concentration.
Mainly including polymer-type drilling
fluid, polymer/lime-type drilling fluid,
lignocarbonate drilling fluid, and CaCO3type drilling fluid.
Simplicity, low cost, low degree
of formation damage by
polymer-type drilling fluid,
higher degree of formation
damage to high- permeability
reservoir than that to lowpermeability reservoir
High solids
content, possibly
higher degree of
formation
damage
Solid-free clean
salt water
Perforating and
well killing
Inorganic salt þ day- stabilizing
agent þ viscosifying fluid loss
additive þ pH adjusting
agent þ corrosion inhibitor
Good reservoir protection
effectiveness, adjustable density
(1.07e2.3 g/cm3)
Slightly poor
suspension,
filtering
required, easily
corroded
Low-solids
temporary
pluggingtype killing
fluid
Acid-soluble
killing fluid
Oil-soluble
killing fluid
Water-soluble
killing fluid
Perforating
and well
killing
Temporary plugging-type bridging
agent þ viscosifying agent acid-soluble
bridging agent: carbonate oil-soluble
bridging agent: resin, bitumen
water-soluble bridging agent: salt particle
American formulation:
CaCO3 þ HEC þ temporary plugging
agent þ XC
Strong inhibiting effect, enabling
temporary plugging, core
permeability recovery up to
80%e90%
Corresponding
plugging
removal
measure
required
Polymertype
perforating
fluid
Polymer þ
surfactant
High water
saturation
reservoir and
reservoir
easily water
blocked
Formulation: viscosifying fluid loss
additive þ surfactant þ salt þ solids
Backflow of liquid enters
reservoir easily
Cationic
polymer
Water- sensitive
reservoir
Viscosifying fluid loss additive þ claystabilizing agent þ surfactant
Inhibiting clay swell, high
recovery of permeability
Mainly gas
reservoir or strong
water- sensitive
reservoir
Bentonite þ CaCl2 þ gas
condensate þ sulfonyl
Preventing liquid from entering
reservoir, easiness of induced
flow
Water-based Modified
drilling fluid
Oil-in-water
emulsion
5. Advances in managed pressure drilling technologies
Preparation
428
Type
Oil-based
Gas-based
Low- pressure
reservoir or
reservoir with clear
information
No damage to reservoir
Dirty
Water- sensitive
Water-in-oil
emulsion and
reservoir
micellar solution
Water þ oil þ surfactant/alcohol
Solubilizing water
Expensive
Foam
Microfoam
Low-pressure
reservoir
or deep-water
well
Water þ surfactant þ water soluble
clay- stabilizing agent
Water þ surfactant þ water-soluble
clay-stabilizing agent þ polymer
Low density, having energizing
effectiveness, ease of backflow,
no damage to reservoir
Poor stability,
matching
equipment
required
Nitrogen
Super-overbalanced Commonly used in combination with acidperforating
based perforating fluid
and testing
operations
Having energizing effectiveness,
ease of backflow, favoring
removal of skin damage
Liquid nitrogen
truck and
matching
equipment
required
Hydrochloric
acid
system
Acetic acid
system
Super-overbalanced
perforating,
combined
perforating and
acidizing
Enabling removal of damage in
perfor-ations and in vicinity of
wellbore
Pay attention to
flowback
Water þ hydrochloric acid/acetic
acid þ clay- stabilizing agent þ
demulsifying agent þ corrosion
inhibitor þ chelating agent
5.3 Underbalanced drilling
Acid-based
Crude oil
or diesel oil
From Renpu, W., 2011, Advanced Well Completion Engineering, third ed., Elsevier.
429
430
5. Advances in managed pressure drilling technologies
FIGURE 5.28
Value addition through underbalance drilling. From Rehm (2012).
• Minimizing pressure-related drilling problems
• Reducing formation damage and enhancing productivity
• Reservoir characterization while drilling
Fig. 5.28 shows the reasons behind an underbalanced drilling operation. As can be seen
from this figure, each of these categories relates to monetary gains with long-term consequences. Recent efforts involve using underbalanced drilling to characterize the reservoirs
while drilling. Productive features in the reservoir can be identified while drilling; well trajectories and well lengths can be optimized to increase reservoir productivity and to identify
potentially productive horizons in the reservoir. This has been discussed in previous
chapters.
The following are some of the benefits of underbalanced drilling:
-
Increased Penetration Rate
Increased Bit Life
Reduced Differential Sticking
Minimize Lost Circulation
Improved Formation Evaluation
Reduced Formation Damage
Reduced Probability of Differential Sticking
Earlier Production
Environmental Benefits
5.3 Underbalanced drilling
431
- Improved Safety
- Increased Well Productivity
- Less Need for Stimulation
5.3.8.1 Reservoir protection
UBD is considered a drilling method to protect the reservoir by reducing formation damage during the operation. Although original impetus of UBD was reducing mud loss, which
is an immediate safety issue, the most significant benefit of UBD is in keeping the reservoir
integrity intact.
A well-designed UBD operation reduces or eliminates problems associated with solid and
fluid invasion into the formation such as pore plugging, phase trapping, clay reaction, fluid
incompatibility, and the formation of emulsions. UBD does not eliminate all sources of formation damage. Therefore, the main benefit from the UBD operation is the reduction of formation damage attributable to solids and fluid invasion.
5.3.8.2 Reduction or elimination of lost circulation
The original impetus of UBD was reduction or elimination of lost circulation. For decades
of 1960 and 1970s, the most important applications of UBD were dedicated to alleviating lost
circulation problems. It was only in later decades, other applications emerged as the benefits
of UBD came to light.
5.3.8.3 Elimination of differential sticking
Differential sticking occurs in an open hole when any part of the pipe becomes embedded
in the mud cake. When this happens, sticking can result because the pressure exerted by the
mud column is greater than the pressure of the formation fluids on the embedded section.
In permeable formations, mud filtrate will flow from the well into the rock and build up a
filter cake. If the mud hydrostatic pressure is higher than formation pressure, the problem
does not occur, because a pressure differential, created across the filter cake, is in fact
negative.
5.3.8.4 Increase in rate of penetration
In a formation with a very low rate of penetration, UBD can generally be applied to
improve penetration rate. In drilling with three-cone bits, higher bottomhole pressure holds
cuttings down against the bottom of the wellbore (chip hold-down pressure). This process
can be helped with UBD, which reduces the time for the removal of debris and cuttings.
Fig. 5.29 shows how underbalance drilling can improve ROP in general. These data are reported by Fattah et al. (2011).
In underbalanced drilling, ROP is increased due to the disappearance of chip hold-down
effect. So the normal trend includes an increase of the ROP resulted from a decrease in the
hydrostatic pressure of drilling fluid as compared with the pressure of the formation when
drilled by UBD. This effect is shown in Fig. 5.37.
The actual scenario is more complete than a simple dependence on differential pressure.
For instance, other factors, such as concentration of cuttings, flow rate, drill bit type, also
play a role. It is no surprise that both optimal ROP (vs. pressure drop) and continuously
increasing ROP for increasing pressure differential have been observed (Fattah et al., 2011).
432
5. Advances in managed pressure drilling technologies
FIGURE 5.29
Improvement in ROP with underbalanced drilling.
5.3.8.5 Extension of bit life
With UBD, there is increase in ROP. However, the drilling rate increase is not as pronounced with PDC or dragtype bits because of their different cutting effects. In general,
the roller cone bit life increases in UBD than conventional drilling. In UBD the bit is exposed
to less stress and low-solids nonabrasive mud. Also, UBD increases the ROP, leading to lower
weight on bit (WOB) during the entire drilling process for the same ROP. This makes way for
higher bit life. Longer bit life in combination with greater ROP leads to reduced number of
drill bits and trip time to change the bit, thus improving the overall economics of the
operation.
5.3.8.6 Reservoir evaluation
As pointed out earlier, UBD provides one with an excellent opportunity to gather formation data as reservoir fluids are produced soon after encountering the productive zone. During underbalanced drilling, pay zones can be detected immediately after penetrating the
formation by measuring and observing fluid at the wellhead or after the separator. Formation
fluid can be monitored at the surface to identify and study pay zones. Single or multirate
drawdown tests are achievable during drilling operation for well test purposes to estimate
reservoir productivity.
Before mobilizing or selecting equipment, it is essential that the correct reservoir candidate
is selected, as well as the correct well and the correct way to drill underbalanced. One of the
complexities of underbalanced drilling is ensuring that all the issues associated with drilling
and flowing a well simultaneously are understood.
This scenario changes somewhat with horizontal sections of the horizontal well. Due to friction loss, the wellbore pressure at the toe of the well becomes higher than at the heel. This loss
cannot be compensated with additional gas because gas would not further reduce the hydrostatic pressure in the horizontal section. In a long and flat well, a simple decision has to be
made whether the pressure is going to be controlled at the heel or at the toe of the well. There
is a practical limit on how long a lateral can be drilled and remain underbalanced.
5.4 Western desert oil field area
433
FIGURE 5.30 UBD plan. From Fattah, K.A., El-Katatney, S.M., Dahab, A.A., 2011, Potential implementation of
underbalanced drilling technique in Egyptian oil fields, Journal of King Saud University - Engineering Sciences, 23(1), 49e66.
Fattah et al. (2011) compiled field data on selected fields. Table 5.3 shows the savings in
total rig days and cost for conventional versus underbalanced drilling wells in Iran (originally
reported by Roving and Reynolds, 1994). It is clear that big savings in drilling cost were
realized.
Fattah et al. (2011) reported significant cost savings with UBD. The cost savings ranged
between $90,000 and $110,000 for 8-1/2 in. hole section and between $170,000 and
$190,000 for the 6-1/2 in. hole size (Table 5.4). A total of approximately $1.4 MM has been
saved (drilling only) and about $1 MM (overall), for the five wells drilled.
Based on these results, the following UBD program was proposed by Fattah et al. (2011).
The selected example includes drilling through the reservoir section, which consists of two
production formations (Belayim and Kareem formation from Miocene age). The reservoir and
formation characteristics are given in Tables 5.5e5.7.
The selected reservoir can be drilled by underbalanced drilling technique and the proposed UBD program is given in Table 5.8.
5.4 Western desert oil field area
The selected example includes drilling through the reservoir section, which consists of
Alam El Buieb formation of Cretaceous age. The lithology of this formation is sandstone
434
TABLE 5.3
5. Advances in managed pressure drilling technologies
Drilling time and cost savings for 8-1/200 hole section drilled underbalanced conditions.
Real cost
Well
Clean cost (just drilling)
Days
K$
Days
K$
1
27
1171
27
1171
2
25.7
1146.3
24.4
1114
3
30.4
2125.3
21.6
1771.9
4
19.3
1360.1
17.6
1230.8
5
31.9
2215.7
16.7
1629.3
6
23.3
1058.5
22.4
1035
7
31.4
1385.1
23
1005.6
8
21.6
1241.5
17.8
989.9
9
20.7
899.1
17.2
667.4
10
34.1
1551.6
30.3
1300.1
26.5
1415.4
21.8
1191.5
1
20.5
1652
14.8
1395.6
2
19
1458
13.7
1243.5
3
21.2
1998.6
16.5
1541.5
4
17.8
1193.6
15.7
728
5
12.9
597
12.2
553.9
Average
18.3
1379.8
14.6
1092.5
00
8-1/2 holedconventional
Average
00
8-1/2 holedunderbalanced
with depleted reservoir pressure 1600 psi, reservoir temperature 219 F, porosity 19%, permeability 200 md, GOR 95 SCF/STB, 41.7 API gravity of oil, and there is no H2S concentration.
The selected reservoir can be drilled by underbalanced drilling technique as given in Table 5.8.
Fig. 5.31 shows the operating window, multiphase fluid injection of western desert oil field
area.
5.5 Nile delta oil field area
The selected example includes the reservoir section, which consists of one production formation (Qawasim from Miocene age). It has a sandstone lithology with reservoir pressure
435
5.6 Comparison of MPD and UBD
TABLE 5.4
Drilling time and cost savings for 6-1/200 hole section drilled underbalanced conditions.
Total cost
Well
Days
Drilling cost
K$
Days
K$
00
6-1/2 holedconventional
1
9
886.6
9
886.6
2
11.8
591.8
11.8
591.8
3
20.7
1186.4
18.1
4
29.6
1596.7
17.8
5
33.5
2074.1
20
6
21.9
928.1
19.7
779.9
7
19.1
995.5
17.8
938.3
8
14.1
778.5
11.8
650.6
9
16.4
800.8
16.4
800.8
19.6
1093.2
15.8
878.5
1
7.4
507.8
6.6
471.9
2
24
1664.6
11.9
998.9
3
22.4
1804
17.2
1057.7
4
14.8
545.1
10.8
387.57
5
9.5
580.6
9
560.6
15.6
920.4
11.1
695.3
Average
1082
644.7
1531.9
00
6-1/2 holedunderbalanced
Average
3800 psi, reservoir temperature 185 F, GOR 1100 SCF/STB, average porosity 25%, average
permeability 400 md, gravity of oil 50 API, and there is no H2S concentration. Fig. 5.32 shows
the operating window, flow drilling operation for the Nile delta field.
The selected reservoir can be drilled by underbalanced drilling technique as given in
Table 5.9.
5.6 Comparison of MPD and UBD
MPD and UBD are both unconventional drilling techniques. Historically, several authors
put these two techniques under the same heading, citing operational differences as the cause
for using different names. However, MPD and UBD serve different purposes, utilize different
methodologies, fluids and equipment (Malik and Aljubran, 2018). As such, the techniques are
436
TABLE 5.5
5. Advances in managed pressure drilling technologies
Gulf of Suez reservoir characteristics.
Parameter
Belayim
Kareem
Pressure
1500 psi
1700 psi
Temperature
180 F
190 F
Gaseoil ratio (GOR)
15e17 SCF/STB
20 SCF/STB
Porosity (md)
18%e20%
20%e22%
Permeability
200 md
500 md
API0 gravity of oil
20e23
20e30
H2S concentration
No
No
TABLE 5.6
Gulf of Suez formation characteristics.
Formation
Lithology
Top (m)
Thickness (m)
Hammam Faraun
Shale-sand
2160
35
Ferran
Shale-sand
2195
140
Sidri
Mainly sand
2335
65
Babaa
Anhydrite
2400
15
Kareem
Limestone
2415
195
Pore pressure (psi)
Belayim
1500
1700
different in their applications, including differences in operational strategies and implementation. The primary definition of UBD and MPD are:
• UBD is a technique that typically uses a multiphase drilling fluid to drill in depleted formations to enhance production.
• MPD is primarily a technique that uses a single-phase drilling fluid to control equivalent
circulating density (ECD) or dynamic mud weight (MW) without adding any weighting
material to the drilling fluid. The main purpose of any MPD operation is to work on issues
that can be the cause of heavy MW or high ECDs. By doing so, it improves the overall efficiency of the operation, leading to a significant amount of savings in both time and cost.
Malik and Aljubran (2018) selected 10 differences in order to highlight the differences between these two drilling methods. In this section, their findings are presented.
5.6.1 Industry-recognized definitions
Underbalanced Drilling is expected to:
• Enhance production from a depleted formation;
5.6 Comparison of MPD and UBD
TABLE 5.7
437
Underbalanced drilling design parameters for Gulf of Suez area.
Rig modification
• No essential modifications to be made on the rig to suit UBD operations
• The substructure has to be high enough to allow Rotating Control Head (RCH) to be
installed on top of the hydril
Well plan
• As shown in Fig. 5.30
Drill string design • Use a 500 DP and 500 HWDP on 6-3/400 DC
BHA
• The BHA consists of 6-1/200 mud motor and MWD to drill 8-1/200 hole
• An 8-1/200 bit size of 3 13/3200 nozzles
Drilling fluid
selection
• The deviated section will be drilled using an oil-based mud and a membrane nitrogen
generation circulating system
A-liquid phase
• Drilling fluid is native crude oil with density 7.6 ppg (0.91 S.G. or 20 API)
• Liquid flow rates were selected to achieve a drawdown from the reservoir pressure
B-gas phase
• Nitrogen was selected as the injection gas
• Nitrogen will be obtained from the surrounding air and generated onsite
Operating
envelope
• A minimum drawdown at the bit of 100 psi is required to ensure adequate underbalanced
conditions in the well
• Using 300 gpm and more than 2400 scfm of Nitrogen will provide maximum 100 psi
drawdown from the expected reservoir pressure
• In case the real reservoir pressure will result below the expected value, then the liquid
injection rate should be reduced increasing the risk for a hole cleaning issue
Hole cleaning
• Minimum annular liquid velocities in deviated holes of 210 ft/min when crude oil is used
as the drilling fluid to ensure that the drilled cuttings are effectively removed from the
wellbore
• A wiper drilling trip will help clear the problem of hole cleaning
Motor
performance
• The motor should be suitable for oil/nitrogen two-phase application
• A maximum Equivalent Liquid volume through the motor of 600 gpm was used as
reference
• A pressure loss of 800 psi between downhole motor and MWD was considered
• The motor should not have a bypass valve on top of it
Production
sensitivity
• As more reservoir fluids (oil and gas) introduced into the wellbore, the Bottom Hole
Circulating Pressures (BHCP) will decrease
• BHCP will therefore be controlled by increasing liquid injection and/or decreasing nitrogen
injection, based on real-time BHCP data from the MWD tool
• BHCP could also be controlled with surface backpressure
• choking will be necessary in stabilizing the circulating system during and after drill string
connections
Data acquisition
• The software for the rig data acquisition has to be able to interface with the UBD
equipment software
Completion
• The well can be completed with barefoot completion technique, or installing a slotted liner
completions
438
5. Advances in managed pressure drilling technologies
TABLE5.8 Underbalanced drilling design criteria for western desert area.
Rig modification
• No essential modifications to be made on the rig to suite UBD operations
• The substructure has to be high enough to allow Rotating Control Head (RCH) to be
installed on top of the Hydril
Well plan
• As shown in Fig. 5.43
Drill string design • Use 500 DP, 500 HWDP and 6.500 DC
BHA
• No downhole motor used
• An 8-1/200 bit size of 3 13/3200 nozzle size
Drilling fluid
selection
• Based on the pore pressure and formation depth, the reservoir formation is below the
normal pressure regime
• The subnormal pressure requires the use of a multiphase (liquid þ gas) drilling fluid system
in order to obtain on Underbalanced drilling condition
A-liquid phase
• Drilling fluid is native crude oil with density 6.84 ppg
(0.82 S.G. or 41.7 API)
• Liquid flow rates were selected to achieve a drawdown from the
reservoir pressure
B-gas phase
• Nitrogen was selected as the injection gas
Operating
envelope
• It is displayed as the area of the graph between the targets BHCP’s, bound by the
maximum motor throughput, the minimum annular liquid velocity, Fig. 5.40
• Using 300 gpm and more than 2200 scfm of Nitrogen will provide maximum 200 psi
drawdown from the expected reservoir pressure
Hole cleaning
• Depends on several variables such as cutting size and shape; liquid properties; drill string
rotation; liquid velocities; flow regime, etc.
• Minimum vertical annular liquid velocities of 180 ft/min when crude oil is used as the
drilling fluid to ensure that the drilled cuttings are effectively removed from the wellbore
Hydraulic
modeling
• Using a multiphase hydraulic simulator, the required underbalanced drilling parameters
could be evaluated in detail
• Graphs can be created to incorporate the limiting factors of minimum annular liquid
velocity required for hole cleaning and the desired BHCP range
Pressure while
drilling
• When the maximum gas volume fraction (GVF) inside the drill pipe is bellow, 20%
conventional mud pulse tools (MWD/LWD/PWD) can be used
• Otherwise, electromagnetic transition tools have to be used in order to obtain downhole
data real time
Data acquisition
• The software for the rig data acquisition has to be able to interface with the UBD
equipment software
Completion
• The well can be completed with barefoot completion technique, or installing a
slotted lined
5.6 Comparison of MPD and UBD
FIGURE 5.31
439
Operating window, multiphase fluid injection of western desert oil field area.
• Gain rate of penetration (ROP);
• Prevent formation damage.
Typically, UBD operations have a drawdown at the sandface, meaning DP will be negative
where formation pressure will be higher than pressure inside the wellbore.
Managed Pressure Drilling is aimed at:
• Improving performance of a drilling operation by avoiding issues that exist due to a heavy
MW or high ECDs.
or
• Allowing more control on ECD without increasing the MW, allowing formations to be
drilled that have a narrow window between the pore pressure and fracture pressure.
Under MPD, ROP is simply a bonus but not the goal. Drilling with MPD creates a slightly
overbalanced pressure than the pore pressure as in the case of conventional drilling.
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FIGURE 5.32
Operating window, flow-drilling operation for Nile delta oil field area.
5.6.2 Drilling fluid
Typically, UBD allows a multiphase flow mixture to lighten the density of the fluid,
creating a low ECD at the sandface, resulting in a lower hydrostatic head of drilling fluid
below the sandface pressure. Due to a pressure differential, influx is taken while drilling.
All MPD operations are single-phase drilling fluid operations. The traces of gas found in
an MPD operation are similar to a conventional drilling operation where the well is filled
with background gas.
Once drilling commences, the added friction will slightly overbalance the formation
pressure. The surface applied choke pressure (SACP) helps maintain a constant bottomhole
pressure while drilling or when drilling is halted for any other operation.
Besides an increase in ROP, the only common theme between UBD and MPD techniques is
a lightweight drilling fluid for which the static hydrostatic head will always be lower than the
formation pressure.
This confirms that, at any given time, flow from the reservoir is imminent for as long as
there is an active perm near the wellbore, which is also called near-wellbore permeability.
In the case of UBD, production gain from the reservoir is the target. In MPD, this is not
the goal.
5.6 Comparison of MPD and UBD
441
FIGURE 5.33 As shown in the figure placing the nozzles in the center (white circle) of the bit and rotating them
90 degree (points radial outward i.e., the nozzle axis parallel to the arrows) so that the fluid will flow around the bit
profile as shown by the blue arrows (black arrows in printed version). This is one possible PDC bit design that matches
the DUBD requirements.
5.6.3 Tier-based system
A tier-based system is a great way to elaborate on the equipment spread for different UDT
techniques.
Neither UBD nor MPD are limited to a single application. The equipment suite changes
with the type of application, even though the technique remains the same.
A tier-based system, therefore, allows the engineer to accurately predict the correct type
and amount of equipment needed at the drill site.
The following is the tier-based system detail.
5.6.3.1 Underbalanced drilling
UBD is divided into seven tiers:
Tier-1: SPI low head drilling
Tier-2: TPI DPI with WBM/OBM w/N2/CH4
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5. Advances in managed pressure drilling technologies
FIGURE 5.34 Optimization of nozzle.
Tier-3: TPI DPI with Foam
Tier-4: TPI CCI system
Tier-5: SPI N2 Gas
Tier-6: TPI System (Parasite String) w/N2 or CH4
Tier-7: TPI with CT unit
SPI e Single Phase Injection
TPI e Two Phase Injection
CT e Coiled Tubing
5.6 Comparison of MPD and UBD
FIGURE 5.35
FIGURE 5.36
FIGURE 5.37
Various types of aeration.
DUBD configuration.
Reorientation of nozzle direction.
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5. Advances in managed pressure drilling technologies
Proposed UBD program in Nile Delta area.
Rig modification
• No essential modifications to be made on the rig to suite UBD operations
• The substructure has to be high enough to allow Rotating Control Head (RCH) to be
installed on top of the Hydril
Drill string design • Use a 500 DP, 500 HWDP and 6.500 DC
• An 8-1/200 bit size of 3 13/3200 nozzles
BHA
• The BHA consists of 6-1/200 PDM mud motor and MWD to drill 600 hole
• If MWD signal is not observed, use electromagnetic MWD tools
Drilling fluid
selection
• Water-based fluid (flow-drilling operation)
• Drilling fluid is water with density 8.75 ppg (1.05 S.G.)
• Liquid flow rates and surface choke backpressure were selected to achieve a drawdown
from the reservoir pressure
Operating
envelope
• It is recommended to pump at least 400 gpm of liquid phase to avoid any operational
problem related with hole cleaning
• The drawdown is 200 psi to prevent wellbore collapse
Motor
performance
• A maximum equivalent liquid volume through the motor of 600 gpm was used as
reference
• A pressure loss of 800 psi between downhole motor and MWD
was considered
Hole cleaning
• Minimum annular liquid velocities in deviated holes of 180 ft/min to ensure that the
drilled cuttings are effectively removed from the wellbore
• A wiper trip will help clear the hole cleaning problem
Tripping
• Some type of snubbing device can be used, or a downhole isolation valve can be installed
• Balancing the well for trips seemed the simplest and least expensive method
Data acquisition
• The software for the rig data acquisition has to be able to interface with the UBD
equipment software
Completion
• The well can be completed with barefoot completion technique, or installing a slotted lined
5.6.3.2 Managed pressure drilling
MPD is divided into three tiers:
Tier-1: Gas knock-out system
Tier-2: Semi auto choke system
Tier-3: Fully auto choke system, including backpressure pump or any other high-end tool,
such as Microflux or Non-Stop Driller.
5.6.4 Candidate screening
Candidate screening is a filtering process to match the particular UDT to the problem faced
by the well section. A detailed screening allows the engineer to identify the right technique
and, most importantly, the correct spread of equipment. The comparison below highlights
a generic screening result for these two techniques.
5.6 Comparison of MPD and UBD
445
5.6.4.1 Underbalanced drilling
• UBD is an excellent candidate for depleted formations, especially when production
enhancement is the target.
• UBD is and has been applied in formations with the following characteristics:
e Depleted formations for production enhancement;
e Formation damage prevention;
e Storage or injector wells;
e Depleting nuisance zones, such as high-pressure, low-volume gas pockets in top-hole
sections;
e Real-time formation evaluation (single point production test or drawing productivity
index while drilling);
e Lost circulation zones;
e Tombstone rock drilling in intermediate hole section.
5.6.4.2 Managed pressure drilling
• Due to its zero influx policy, MPD can be applied in sections that are prone to lost circulation, areas where stuck pipe is an issue, or in HPHT reservoirs to avoid NPT, mainly in
the form of high MW or ECDs.
• To date, 70% of MPD wells have needed ECD control to avoid reaching fracture gradient
or creating drilling-induced fractures. Therefore, most MPD today revolves around ECD or
pseudo-MW control without increasing any solids in the mud to create the same effect of
ECD as created by a weighted mud.
• A few cases have also seen a reduction in casing strings by controlling ECD at the sandface.
Once the desired TD is reached, the casing is landed to secure the section without adding
any additional strings.
• MPD has also seen a great value in HPHT wells, where longer open holes are able to be
drilled, which were not possible with the traditional way of increasing MW to control the
formation pressure.
In summary, UBD is primarily concerned with production enhancement from depleted reservoirs. MPD works with issues that are related to high MWs and ECDs that result in shorter
wellbore length, challenging windows between pore and fracture gradient or areas where lost
circulation is induced due to dilation of near-wellbore fractures. The Bottom Hole Circulating
Pressure throughout an MPD operation remains slightly above the pore pressure.
5.6.5 Drilling mud
Drilling mud is simply a non-Newtonian fluid that can be either single or multiphase. Conventional drilling deploys only a single-phase mud system, whereby unconventional drilling
can have either single phase or a mixture of gas and liquid.
5.6.5.1 Underbalanced drilling
• Only Tier-1 UBD deploys a single-phase drilling fluid system.
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5. Advances in managed pressure drilling technologies
• All other tiers of UBD operations employ dual or multiphase drilling fluids. The gaseous
phase is nitrogen (an inert gas) or methane, or production gas, which works in harmony
with both water-based mud (WBM) and oil-based mud (OBM).
5.6.6 Managed pressure drilling
• MPD works in the same way as conventional drilling, meaning it has only a single-phase
fluid, which could be either WBM or OBM.
• MPD does not employ any gas injection. The only gas that is present during the MPD
operation is the gas from the formation, the same as background gas in conventional
drilling.
Note that the only similarity in terms of drilling fluid between UBD and MPD is a light
MW such that, at static conditions, the hydrostatic head of the drilling fluid will always be
less than the formation pressure. It is also interesting to note that plastic viscosity and yield
point is less dominant in UBD than in an MPD operation. Hole cleaning in a UBD well is
more dependent on velocities than yield point, while the reverse is true for MPD.
5.6.7 Drillstring and well construction design
The well construction consists of both open hole and casing. The construction of a well
drilled conventionally versus a well that is subjected to a UDT differs mainly in the form
of hole sizes and the number of possible casing strings. Usually, a UDT well will have fewer
casing strings than a conventionally drilled well. The reasons for that are not going to be discussed here. However, a comparison of drillstring and well construction is given below to
clearly distinguish between these two techniques.
5.6.7.1 Underbalanced drilling
• The drillstring in a UBD well is equipped with additional float subs that are required for
string depressurization. This is an additional feature that is not found in any other string
design. The depressurization of the string is necessary before connection.
• A conventional mud-pulse telemetry’s signal is doped by the presence of nitrogen
gas inside the drillstring, due to a two-phase mixture. Note that conventional mudpulse tools require a single phase in the string for the signal to reach the receiver on
surface.
• Almost all UBD operations will have the casing on top of the formation that will be subjected to this technique. This is done to ensure well control integrity and to avoid exposing
long open-hole sections, which may pose a threat due to a multiphase fluid mixture at their
faces.
5.6.7.2 Managed pressure drilling
• MPD does not have any special requirement for a drillstring. All MPD operations employ
the same drillstring configuration like a conventional well.
• One of the applications of MPD is to reduce casing strings by controlling the nuisance of
trouble zones. Many operators have utilized the technique to save on casing costs. This
5.6 Comparison of MPD and UBD
447
does not mean this will always be the case. Depending on the type of application and formation pressure, a drilling engineer decides on the best possible scenario for arranging
his/her casing strings.
5.6.8 Footprints on location
Footprints-on-location is the area that is occupied by the surface equipment. UBD and
MPD equipment both bypass the conventional mud loop, devising a new route for the
well returns through their equipment. In both cases, it is considered a closed-loop circulation
until the return fluid is directed to the shale shakers.
5.6.8.1 Underbalanced drilling
A typical UBD setup would require:
•
•
•
•
•
•
•
Rotating control device (RCD) with an emergency shutdown valve;
Compressors with AC units;
Nitrogen production units (NPU);
High-pressure (HP) 2/3 stage boosters;
HP choke manifold (manual or variable chokes);
3/4 phase horizontal separation with either a parallel or built-in sample catcher unit;
Flare line (other than the flare line downstream of the poorboy degasser).
5.6.8.2 managed pressure drilling
A typical MPD setup includes:
• RCD;
• HP choke manifold (semi or full auto chokes). The auto chokes in an MPD operation are
pivotal to allow a constant Bottom Hole Circulating Pressure (BHCP)/ECD regime at the
sandface;
• A vertical separator of 125 psi working pressure (min);
• In some cases, the downstream flowline from the choke manifold is tied into the rig’s
poorboy degasser.
In summary, the equipment requirement for UBD and MPD is entirely different, even
though both techniques are closed loop or pressurized until the auxiliary separation unit,
which is part of the package. UBD consists of units that are also responsible for the nitrogen
gas generation; this alone raises the footprint onsite. Therefore, the overall UBD operations
cost is higher than for MPD. One has to pay a minimal amount for auto chokes, but the overall cost of MPD operations does not exceed UBD costs.
5.6.8.3 Drilling methodology
Drilling methodology deals with the way drilling is conducted in a well section. MPD and
UBD each serve a different purpose when they are being utilized in any formation. UBD is
mainly known for production enhancement from depleted formations, whereas MPD is utilized in areas where MW control is the main purpose or where the pore pressure and fracture
gradient window is a challenge and cannot be controlled by conventional mud control.
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5. Advances in managed pressure drilling technologies
5.6.8.4 Underbalanced drilling
• Drilling fluid is energized using nitrogen gas, which helps in creating a drawdown at the
sandface. The multiphase mixture or injection of gas into a single-phase liquid (WBM or
OBM) helps to reduce the density of the fluid, hence the resulting ECD. This allows a pressure drawdown at the sandface, leading to a production gain while drilling.
• Due to gaseous mixture, the fluid is taken at surface and separated at the P tank, where gas
and liquid phases go into their separate streams.
5.6.8.5 Managed pressure drilling
• Single-phase fluid similar to conventional drilling is used in MPD. The pseudo-MW or the
ECD is controlled using an auto-choke system on the surface. The returned fluid from
the annulus is trapped at the choke, which creates backpressure, which is felt through
the length of the well. The drilling is continued until TD is reached.
• The premise of MPD in terms of BHCP is to keep the BHCP/ECD slightly above the pore
pressure at all times. In other words, a positive drawdown at the sandface will be treated
as critical in an MPD operation.
5.6.9 Well control strategy
Conventional well control is straightforward, where certain indications must be fulfilled
for the well control process to take place. UDT equipment is not designed for well controld
many in the industry are unaware of this fact. In the event of any well control situation, the
UDT system is bypassed to make way for conventional well control. As a result, the well control procedure in any UDT operation is not different from conventional well control. The
design of the well control process and initiation will differ in both MPD and UBD operations.
5.6.9.1 Underbalanced drilling
The well control (WC) matrix in a UBD operation has high production rates measured in
MMscfd, which when encountered on surface, alters the position of the choke and, therefore,
the choke or wellhead pressure.
• Due to a high flow rate operation, the changes in the wellhead pressure directly affects the
dynamic rating of the RCD. Therefore, the WC matrix in a UBD operation is based on a
large volume of gas or liquid compared with an MPD operation.
5.6.9.2 Managed pressure drilling
• High flow rates in an MPD operation negate the purpose of MPD. The WC matrix for an
MPD operation relies on very small influxes, and many vendors prefer to have 2 bbl as
their baseline. This means that for any pressure/volume/temperature gain that is 2 bbl,
conventional well control will have to be deployed.
• Changes in the SACP are almost negligible due to these small influxes, unlike in a UBD
operation.
5.6.10 Annulus return flow measuring devices
Measuring devices for annulus return flow in any drilling operation work are based on
whether there is a change in the volume of the flow. This is typically true for the equation
5.7 Novel technologies
449
of continuity Q ¼ Av where if Q ¼ K, then A1v1 ¼ A2v2, confirming that the pump rate for
any given hole section remains constant and volume pumped in V1 equals volume return
from the well V2. If V1 s V2, then it is either a gain or loss of fluid from the formation.
The measuring devices in UDTs have attracted a lot of attention recently. Here is how
they differ in the case of MPD and UBD.
5.6.10.1 Underbalanced drilling
• Throughout a UBD operation, V2 > V1 in order for the operation to be called true UBD.
This is mainly true for depleted reservoirs that have been selected for production
enhancement.
• Incoming flow rate is critical in a UBD operation due to a complex mix of nitrogen, drilling
fluid, reservoir gas or oil, or, in some cases, water. Therefore, a separator with a device that
can separate out these phases and measure them separately will be key to tracking production rates.
• Generally, all separators are equipped with a Daniel orifice meter that measures the
incoming gas rate. The liquid rate is measured using the amount of volume that is shipped
from the separator to the tank farm region on an hourly or as per need basis.
5.6.10.2 managed pressure drilling
• For a true MPD operation, V1 ¼ V2 at all times. This also shows that MPD works to control
any influx or any damage near the wellbore that can cause propagation of fractures that
can lead to lost circulation.
• Due to MPD being slightly overbalanced or balanced with the pore pressure, a Coriolis
flow meter is now part of the package to measure changes in flow rates and density.
• In the event of any change in return volume, the autochoke has to be adjusted to apply
backpressure that would allow the system to turn into a safe mode and would eradicate
the problem of any gain or loss.
• Notice in the above, the Coriolis flow meter is not designed to read separate flow rates.
Rather, it measures the overall volume or density change.
It is clear from the above comparison that MPD and UBD are two different UDTs. The
application of one can neither be called the other, nor merge into the other. The few similarities between these techniques can be seen in the form of a light MW or an RCD (or rotating
head) installed above the BOP, an operational barrier during any UDT operation. Knowing
the correct application of these techniques would help engineers identify well sections prone
to these techniques. The correct identification of these two techniques would also help to
select the right equipment that will avoid spending unnecessary cost toward the operation.
5.7 Novel technologies
OBD is synonymous with slow, ineffective, unsustainable, but inexpensive way of drilling
a petroleum well. As such, much effort has been spent on devising UBD and others that
would improve ROP and minimize formation damage, lost circulation, and others. This
came with a cost, leading to developing cost-efficient alternatives, which are as universally
applicable as OBD operations. One of the areas of innovations has been the process called
Dynamic Underbalanced Drilling (DUBD) as named by El-neiri (2017).
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5.7.1 Dynamic underbalanced drilling (DUBD)
In DUBD a pressure drop at the environ of the bit, below and around, is created that is
restored to normal pressure above the bit and such conditions require some minor modifications to the design of drill bit. Thus at the zone located below and around the bit underbalance conditions are dominated while the rest of the hole is overbalanced.
In DUBD, the underbalance is not created by low fluid density as in UBD but by fluid velocity. Drilling fluid exits bit nozzles with high velocities and according to general energy
equation (or Bernoulli equation) the pressure will drop. When one type of energy increases
(or decreases) in a closed system, one or more types of energies must decrease (or increase)
so that the total of all energies remains the same. Thus, increasing fluid velocity will increase
fluid kinetic energy, and this will lead to a decrease in pressure (elastic potential energy) only
because elevation (elevation potential energy) is the same for that point (depends on elevation), so increasing velocity will decrease pressure at the same point by an amount proportional to the square of fluid velocity, but this does not occur while drilling because of the
following effect.
In OBD the nozzles are generally directed downward to provide high impact force and
high bit hydraulic horsepower for hole cleaning. But this orientation causes the drilling fluid
to hit the bottom of the hole perpendicularly or near perpendicular. So the velocity at the bottom of the hole is reduced to zero (the fluid hits the formation and stops the flow in the
reverse direction) at the formation being drilled. This converts all the kinetic energy to pressure thus increasing pressure at the formation and reducing ROP. In order to utilize the high
velocity, in DUBD the nozzle orientation and size are changed. Bit profile is changed also so
that the fluid exits the nozzles parallel to the formation so the pressure is reduced.
The DUBD simply utilizes the very high fluid velocity caused by the used nozzles to lower
the pressure to create an underbalanced zone below and around the bit. When the fluid then
enters the larger area in the annulus above the bit, velocity is greatly reduced, so pressure
rises again (Figs. 5.33e5.37).
This pressure drop is the amount of pressure reduced below normal mud pressure at the
bottom of the hole. If this technique is used with light fluids as that used in UBD the reduction in pressure may cause pressures near atmospheric at bottom of the hole. This leads to
higher penetration rates than that in normal UBD techniques.
They determined the amount of pressure drop for a given mud weight by the fluid velocity. Fluid velocity is controlled by flow rate or nozzle size. So, not only a modification of
nozzle orientation is required, but also nozzle size modification may be required. Bit profile
is modified to allow the modifications of nozzle and to keep velocity high without decreasing
fluid velocity considerably. The number of changes available in design is too many, but the
same basis must be maintained.
Some benefits gained by this technique:
• Higher ROP that will reduce drilling time and costs as follows
• Higher ROP means lower drilling days so cost is lowered
• Higher ROP means lower open hole time so lower mud losses, hole problems, and formation damage.
Reservoir data can be obtained while drilling. These data include:
Reservoir permeability (effective permeabilities).
5.7 Novel technologies
451
Reservoir pressure
Fluid types
Fluid distribution and saturation
Extended bit life
Better hole cleaning
Increase reserve
Can be used in almost all cases.
5.7.2 Drilling with recycled gas
Drilling petroleum wells with air, natural gas, carbon dioxide, and nitrogen has been in
existence since the in 1950s (Angel, 1957). This technology is synchronized with UBD. As discussed in previous sections, UBD is marked with many advantages and, as such, has been
applied to many applications. Of late, low permeability gas reservoirs and coal bed methane
pay zones have been added to this fold (Cai et al., 2016). However, problems with UBD
continue to linger and there is much room for improvement (Zhu et al., 2010). Meanwhile
drilling with gas continues to be operational. For this application, natural gas or pure nitrogen gas is preferred to drilling over air as it is inert and noninflammable (Cai et al., 2016).
Unfortunately, nitrogen gas as the drilling fluid is not sustainable, mainly because of its
high cost. More recently, purified nitrogen has been shown to be an environmental hazard
with poor global efficiency (Islam, 2020). Shunji et al. (2012) discussed the possibility of using
recycled gas for drilling purposes. However, the drilling design and operation scheme of drilling with return gas are quite different from conventional gas drilling. The main characteristics of this technology is that the gas returned from the wellbore is purified by a separation
and filtration system, and then injected back into the wellbore instead of being discharged
directly. Fig. 5.38 illustrates a sketch of the recycling gas drilling system at surface. The
work gas from the gas supplier can be nitrogen gas from a small N2 generator, natural
gas, or tail gas. The work gas fed to the compressors and booster is injected into the well
through the standpipe.
The operation starts as soon as the gas volume and pressure in the well is sufficiently high.
The gas stream returned to the surface goes through three stages of separation to remove
solids and liquids. The purified gas is led to the suction end of the compressors and recycling.
Because the return gas is reused, only a small amount of make-up gas is needed from the gas
supplier for the requirement of the wellbore extension and possible gas leakage.
The components of the recycling gas drilling system are further described as follows (Fig.
5.38):
(1) Gas supplier: The gas supplier can be a small nitrogen generator, natural gas pipeline, or
CO2 pipeline. In most applications, a small-size nitrogen generator with on-site membrane separation is feasible and cost-effective.
(2) Compressors and boosters: These are standard equipment currently used in gas drilling
operations. The suction end of the compressors can be modified to adapt to the recycling
gas drilling system.
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5. Advances in managed pressure drilling technologies
(3) Inertial separator: This is the first stage separation that removes a great quantity of large
drilling cuttings of greater than 0.1 mm and liquids by means of inertial force. The output
nitrogen stream is fed to next separator for further separation.
(4) Cyclone separator: This is a second-stage separator that removes cuttings of greater than
7 mm and liquid using centrifugal force. The outlet nitrogen gas is fed to the next separator for purification.
(5) Precision filter: This is the last stage separation, comprised of a fiberglass filter element
that removes all particles greater than 1 mm by filtration and aggregation.
(6) Discharge system: This is a specially designed system that discharges cuttings and liquids
with minimal loss of work gas.
Islam (2020) showed how each of the above components can be rendered sustainable by
replacing with natural substitute or waste material. For instance, consider the scenario of
enhanced gas recovery with the aim of using any waste gas for drilling or for reinjection.
Fig. 5.39 shows the schematic of the enhanced gas recovery scheme. As can be seen in this
figure, the flue gas typically is processed in order to capture high-quality CO2. However, purification of CO2 does not need to be carried out as the effluent is slated for reinjection. Islam
(2020) showed that purification with expensive and toxic solvents actually increases the footprint of the process, thereby, defeating the purpose of environmental sustainability.
FIGURE 5.38 Sketch of the recycling gas drilling system.
5.7 Novel technologies
FIGURE 5.39
Schematic of a self-sustained gas generator scheme.
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