PAPER_PINTO_INES_H00227102

Dual Gradient Drilling Inês Sofia C.V. Pinto, ISPG

March, 2016

Copyright 2016 Society of Petroleum Engineers This paper was prepared in the context of the Individual Project

ABSTRACT

Nowadays, most of the accessible reservoirs are depleted, becoming necessary to find a way to recover the

remaining hydrocarbons reserves. Also, challenging reservoirs that cannot be accessed by using conventional

methods can become producible if other techniques are applied. Managed Pressure Drilling (MPD) can be one

of the solutions.

By using this method, the control of the Bottom Hole Pressure (BHP) is improved, which is crucial in fields with

a narrow drilling window. Thus, problems related with well control are mitigated, reducing the Non-Productive

Time (NPT) and increasing safety.

In this project four variations of MPD are analysed and it is given more emphasis to the DGD technique which is

the main subject of this project. This method refers to offshore drilling operations where the drilling fluid

returns are not done by using the riser. It is applied when a single fluid causes the wellbore pressure to exceed

the formation pressure, resulting in loss of circulation.

One of the main benefits of DGD is the reduction in the number of casing strings which implies a saving in both

material cost and rig time. Moreover, this allows to have higher production tubing diameters.

Regarding the application of DGD methods, two case studies, not related to each other, are analysed. Although,

both cases compare the conventional drilling with DGD, the final objectives are different. No real data about

deep offshore were provided or possible to obtain. Hence, values were assumed to perform these studies.

INTRODUCTION

World energy demand is continuously increasing. However, nowadays, most of the accessible reservoirs are

depleted. For that reason, there is a necessity of improvement in the technology to recover the remaining

hydrocarbons reserves and to explore new and challenging reservoirs. Consequently, it is crucial to find a way

of exploring reservoirs that would not be economically feasible by using conventional drilling methods:

Managed Pressure Drilling (MPD) can be one of the solutions to overcome this problem.

Conventional drilling methods, namely Overbalanced Drilling (OBD) and Underbalanced Drilling (UBD) are

predominantly concerned with the formation fluid influx and well control during the drilling operation.

Therefore, a drilling window between pore pressure and fracture pressure must be defined. A safety margin

and overbalance (static or dynamic) must be considered as well. If the mud gradient used is less than the pore

pressure gradient then an influx of formation fluids can occur leading to a kick and, in the worst case scenario,

a blowout. On the other hand, if the fracture pressure is exceeded, formation fracture may occur leading to

drilling fluid losses and, in the worst case scenario, loss of well control.

When planning a drilling program, it is important to keep in mind that the Bottom Hole Pressure (BHP)

difference increases with the depth. For example, comparing the BHP by using two mud densities, 8 ppg and

9.5 ppg, it is noticeable that the overbalance increases with depth, Figure 1. Moreover, the higher the mud

density is, more significant will be the difference in BHP.

In the example below, the difference of BHP values is about 1400 psi at 18,000 ft. This is very important when

planning the mud program to ensure that the fracture pressure is not exceeded.

2 Inês Sofia C. V. Pinto SPE

Figure 1 - Comparison of BHP by using different mud densities.

The OBD method has been the method of choice for the majority of wells drilled since the early 20th

century

(Elliot, et al., 2008) and it uses a mud gradient higher than the pore pressure gradient but lower than the

formation fracture pressure gradient. This means that when drilling fluid is circulated down the drillstring and

up the annulus, the Equivalent Circulating Density (ECD) is greater than the pore pressure but smaller than the

formation fracture pressure. On the other hand, the UBD method is focused on preventing drilling fluid loss

into the formation. Thus, the hydrostatic head of the drilling fluid is intentionally designed to be lower than the

pore pressure of the formations that are being drilled. The hydrostatic head of the fluid may naturally be less

than the formation pressure or it can be induced by adding different substances to the liquid phase of the

drilling fluid, such as natural gas, nitrogen or air.

The ECD can be interpreted as the density of a fluid, which in static conditions and at a depth of interest

produces the same pressure as a given drilling fluid in dynamic conditions (Kartevoll, 2009).

ECD management is critical to control the well. This is particularly important when drilling through zones with a

narrow Pore Pressure (PP) / Fracture Gradient (FG) window. ECD can be calculated using the following

equation:

ECD = MW + Pd / (0.052 TVD)

Where MW is the mud gradient [ppg], Pd is the annulus frictional pressure drop at a given circulation rate [psi],

TVD is true vertical depth [ft] and 0.052 is a unit conversion factor (Drilling Engineering, HWU, 2014).

Although being the most applied techniques, conventional drilling methods have some drawbacks. In OBD the

most relevant of them is its dependence of multiple casing strings to prevent fluid losses into the formation. In

deep offshore wells, the drilling window can be so small that becomes mandatory to set a big number of casing

strings even before reaching the target formation. As a result, a well with a too small diameter to

accommodate the necessary production tubing can be obtained, invalidating the economic feasibility of the

well (Elliot, et al, 2008). In UBD method, where ECD is maintained below the pore pressure, fluids from exposed

formations are allowed to flow into the wellbore and in the worst case scenario a kick can occurs. Besides,

when drilling long reach wells, pressure associated challenges are encountered, such as wellbore instability and

well control problems.

In order to overcome all of these problems and challenges, MPD was developed. This technique is primarily

used to drill wells that should not be drilled by using conventional techniques, either OBD or UBD, such as in

rigs where it is not possible to use flaring, or while drilling through high-permeability formations.

However, in wells with sufficiently large drilling pressure windows, pressure losses can be controlled by

changing drilling fluid’s properties and their flow rates and rates of penetration (Elliot, et al, 2008).

Figure 2 shows the behaviour of the MPD technique, comparing with OBD and UBD methods.

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Figure 2 - Comparison of OBD, UBD and MPD behavior. Adapted from ADS.

In OBD method, the resultant BHP is above the pore pressure and below the formation fracture pressure,

whilst in UBD method, it is used an ECD below the pore pressure but greater than pressure required to

maintain wellbore stability. The MPD method uses a combination of mud gradient, back pressure and dynamic

circulating pressures to dynamically maintain the bottom hole pressure inside the drilling window. By using this

technology, it is possible to have a precise control of the BHP, keeping it within the drilling pressure window

(Elliot, et al, 2008). In this way, projects that were not possible to develop employing conventional methods,

can be drilled with MPD.

MANAGED PRESSURE DRILLING

MPD uses a combination of techniques to mitigate the risks and costs associated with drilling operation by

managing the open hole pressure profile whilst drilling. These techniques include controlling backpressure,

fluid density, fluid rheology, annular fluid level, circulating friction and hole geometry in any combination

(Hannegan, 2005) to maintain a bottomhole pressure above pore pressure but below fracture pressure.

According to IADC, MPD is an adaptive drilling process to increase the control of the annular pressure profile

throughout the wellbore and if it used as a primarily means of operation, it represents a proactive approach to

the drilling operation.

When using this technique, a mud gradient less than that of pore pressure gradient is used and the additional

pressure to maintain overbalance is provided from the dynamic annular pressure loss (when circulating). A

backpressure is created by closing a surface choke.

As is it possible to observe in Figure 3, the use of backpressure reduces the difference between hydrostatic

pressure and formation fracture pressure, without increasing the mud gradient.

Figure 3 - Pressure vs. Depth graph, highlighting the backpressure. Adapted from Elliot, et al, 2008.

Analysing this graph it is possible to see the difference between hydrostatic pressure and formation fracture

pressure without applying backpressure (interval 1) and applying backpressure (interval 2).


With the rig pumps on, the pressure equation in a closed circulation system is:

BHPDynamic = ΔPStatic + PAFP + PBP(Dynamic)

Where ΔPStatic is the drilling fluid hydrostatic pressure, PAFP is the annulus frictional pressure (AFP) created by

the circulating drilling fluid and PBP is the surface backpressure applied to the annulus by pressure control

equipment connected to the wellhead (Rehm, et al, 2008).

In a closed system, the backpressure term, PBP, is always present during a connection and sometimes, while

drilling. Equation 2 is applied when mud is circulating. Under static conditions, when the rig pumps are off,

PAFP = 0 and this equation becomes:

BHPStatic = ΔPStatic + PBP(Static)

With the purpose of adjusting the annular pressure profile between the pore pressure and the formation

fracture pressure, it is possible to use a mud gradient statically underbalanced. It can be brought back in

balance by applying a surface backpressure, that would then be reduced slightly once circulation begins. While

in conventional drilling the static and dynamic pressures are always different, in MPD techniques, they can be

equal.

In accordance with the MPD subcommittee of IADC, MPD can be separated into two categories: reactive and

proactive. MPD is reactive when the well is firstly designed for conventional drilling, but the equipment is

rigged up to quickly react to unexpected pressure changes. It is an enhanced form of passive well control to

help manage unexpected downhole pressure. Proactive MPD is used to mitigate drilling hazards and to reduce

Non-Productive Time (NPT) such as drilling fluid changes, casing and open hole programs. In this case the

equipment is rigged up to actively alter the annular pressure profile (Rohani, 2011).

MANAGED PRESSURE DRILLING TECHNIQUES

As reported by Arnone (Arnone & Vieira, 2009), there are four recognized variations of MPD:

Constant Bottomhole Pressure (CBHP);

Mud Cap Drilling (MCD);

Return Flow Control Drilling (RFC) or HSE Method;

Dual Gradient Drilling (DGD).

It is possible to combine several variations on the same prospect and it is expected that these combinations

become more frequent in prospects where drilling operations become more difficult to perform (Aadnoy, et al,

2009).

OPERATIONAL CONSIDERATIONS

Before choosing what type of drilling method will be applied, an accurate planning program must be

performed. In the case of MPD being the best technical and economic choice it is necessary to select which

method is the most appropriate for each case. As reported by Nauduri (Nauduri, et al.,2010), even with all the

advances in science and technology as well as the huge availability of equipment and expertise, the industry

still needs a Candidate Identification Mechanism (CIM)/Candidate Selection Model (CSM) exclusively developed

for MPD and its applications, considering the technical and economic aspects of a given project. Therefore, a

MPD CIM created by petroleum industry and the Petroleum Engineering Research Program at Texas A&M

University (TAMU) was described by Nauduri (Nauduri, et al.,2010). It provides a tool that takes into account

the available engineering data and determines if MPD is the best solution for a given project. Besides being an

important and interesting topic, it is not in the scope of this work and it will not be developed.

Similarly to all drilling operation methods, MPD also carries a set of risks. Due to its complexity, a detailed

planning containing the description of all risks at each stage of the MPD operation, plans to mitigate those risks

and contingency action plans, usually starts earlier when comparing with conventional drilling. This planning

should include a review of a number of parameters that will be mentioned below (Rehm, et al, 2008).

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DUAL GRADIENT DRILLING

Drilling in deep water is a challenging operation and one of the principal issues regarding this procedure is the

typical low fracture gradients and shallow abnormal pressure. It is quite common to find margins between the

fracture gradient and the required mud that are inferior to 1 ppg (Advanced Drilling Techniques, 2006). DGD

method is used when a single fluid causes the wellbore pressure to exceed the formation pressure, resulting in

loss of circulation (Rohani, 2011).

DGD refers to offshore drilling operations where the drilling fluid returns are not done by using the riser. These

returns can be dumped at the seafloor (pump and dump), which is not permitted in all jurisdictions and it is

only advisable for top sections, or returned to the rig through return lines (riserless muds return) (Rehm, et al,

2008).

As its name suggests, Dual Gradient Drilling (DGD), uses a combination of two mud gradients, i.e., the

hydrostatic gradient in the wellbore is composed by two different parts. In the upper portion of the wellbore,

above the fluid interface, a lighter fluid that can be a liquid or a gas fills the annulus from the Rotary Kelly

Bushing (RKB) down to the fluid interface depth. This fluid interface can be placed at the seafloor or above it.

At the lower part, a heavier mud that always lies between pore pressure and fracture pressure is used, Figure

4. By using fluids with different densities it is possible to manage the BHP to obtain a pressure profile that

better fits the drilling window (Sui & Nygaard, 2015).

Figure 4 - Principle of Dual Gradient Drilling. Adapted from Advanced Drilling Techniques, 2006.

In the conventional drilling method, the gradient in the wellbore is always relative to the rig, i.e., the mud

column is hydraulically continuous from the bottomhole to the surface, which corresponds to the blue line in

the figure above.

In DGD method, it is possible to control the BHP in static and dynamic ways, decreasing it, shown by the red

line. On the upper portion of the well, the seafloor pump reduces the imposed pressure, while the higher

density mud below the seafloor achieves the necessary bottomhole pressure (BHPDGD) to control the formation

pore pressure (Rehm, et al, 2008). The pressures can be underbalanced inside the cased hole or riser but in the

open hole, it must always use an overbalanced drilling. This underbalance is possible to achieve by reducing the

mud gradient used in the upper section to a value inferior to the seawater density or adjusting the cut point to

a point below the seafloor (Advanced Drilling Techniques, 2006).

DGD APPROACHES AND SYSTEMS

There are different DGD methods available although their main operating principles are similar. DGD can be

applied to drill top-hole sections before setting the BOP or after BOP installation. Post-BOP techniques can be

performed by pumping drilling fluid back to surface through subsea pumps. The pumps can be located at

seabed (seabed pumping) or suspended above it (mid-riser pumping). Another technique consists in diluting

returns by injecting a lighter fluid usually just above the BOP stack.


In the diagram present in Figure 5, the active DGD systems are presented, in accordance with Cohen (Cohen, et

al., 2011).

Figure 5 - IADC DGD Approaches and Systems. Adapted from Cohen, et al., 2011.

ADVANTAGES OF DGD

By obtaining a pressure profile that better fits the drilling window, Dual Gradient Drilling method presents a set

of benefits. The most relevant of them are explained below.

Reduction of casing strings From an economical perspective, this is one of the main benefits of DGD. A reduction of casing strings implies a

saving in both material cost and rig time. Primary cement capabilities are also improved (Advanced Drilling

Techniques, 2006).

A DGD approach resides in the effective mud gradient at the previous casing shoe being inferior to the effective

mud gradient at the drilling depth. If the casings setting depths are not limited by the mud gradient of the

previous casing shoe, it is possible to eliminate casing points and therefore to reduce casing strings, allowing to

have higher production tubing diameters (Advanced Drilling Techniques, 2006).

By obtaining a pressure profile that fits better inside the drilling window it is possible to reach higher depths

before setting the casing, Figure 6. This is critical, not only from a time and cost perspectives, but also because

it allows using larger production casing and tubing.

Figure 6 - Goal of DGD method. Adapted from Advanced Drilling Techniques, 2006.

By eliminating casing points, the hole size at the end of the section increases which can be crucial in deeper

wells. The production casing must be large enough to run subsea safety valves in the annulus between the

production casing and production tubing. This last must have a sufficient diameter to achieve or even increase

the planned hydrocarbons production, which will increase the early income and hence the profit. Another

important aspect of the increased wellbore diameter is that in some situations it is possible to convert an

exploration well into a production well. By converting exploration wells a high value can be added to a project.


This alteration is a very important subject for oil companies mainly in deep and ultra-deep offshore, where the

well cost is extremely high.

Lower deck space and loads are needed

There is also a major problem associated with conventional riser systems in deep water. The deeper the water

is, more marine riser joints are needed to be loaded onto the vessel, resulting in a reduction of deck space as

well as bigger concerns about loading capacity limitations. Besides that, to fill up these risers, a huge quantity

of drilling fluid is necessary. For example, to fill 10,000 ft of 19 ½’’ I.D. riser, about 3700 bbl of mud is required.

This is not only highly costly but the volume of mud can be excessive for the storage capacity of the rig (Rehm,

B. et al, 2008).

Easier to manage pressure control

When using conventional drilling, the hydrostatic pressure at the bottomhole can only be safely modified by

changing the mud density. To achieve this, it is necessary to circulate out all the mud volume that is in the

annulus and prepare a new mud. When drilling a well at 16,500 ft this operation takes a minimum of 3 hours.

Mud density increasing is a common procedure in conventional drilling to adjust the changes in formation

pressure. By using DGD, the BHP can be modified by varying the fluid interface depth. Thus, it is faster to

change the BHP allowing a more accurate pressure control, since the fluid interface in the riser can be

continuously adjusted making it possible to eliminate the friction pressure loss. Consequently, it is possible to

keep the BHP constant which make it easier to drill in a narrow mud window (Gaup T., 2012).

Improved kick and loss detection

The fluid level in the riser is continuously monitored. Unexpected modifications in the fluid interface depth and

the consequent changing in subsea pump rates gives indication of drilling fluid losses or influx of formation

fluids. Thus, by using DGD, it is faster to detect these problems allowing to take safety measures quickly.

ROP increasing

DGD can compensate the friction pressure by reducing the mud density level inside the riser. By maintaining

the BHP constant, the ECD can be kept below fracture pressure. Therefore, the ROP can be increased, reducing

the drilling time and therefore the costs.

CHALLENGES OF DGD

In compliance with Gaup (Gaup, 2012) and Saptharishi (Saptharishi & Deendayal, 2012), some of the limitations

of DGD includes:

Equipment

New equipment and technology might need to be developed before fully taking advantage of the DGD system.

Most of equipment applied in this method is placed in the subsea, making it more complicated to repair or

even to do the maintenance. A set of control lines are used to control the subsea equipment and they can

become tangled due to sea currents. This can create problems affecting the equipment functionality (Gaup T.,

2012).

Risk of Riser Collapse

When using nitrogen to decrease the mud density above the fluid interface, it is necessary to determine the

collapse loads of the riser. The outside hydrostatic pressure created by the seawater must not exceed the

collapse resistance of the riser considering that it is full of gas (Gaup T., 2012).

Conservative Industry

The oil and gas industry, and particularly the drilling industry, is often considered to be conservative. Although

new ideas arise frequently, it is difficult to implement new technologies in this well stablished market. Safety

and productivity are the most important factors in this industry and usually the risk of applying new

technologies is too high to compensate for the possible profit (Gaup, T., 2012).


In agreement with Gaup (Gaup, 2012), despite of its higher CAPEX requirements when comparing to

conventional drilling more companies are starting to use this method. Following this trend, more equipment is

expected to be ordered, making production costs decline for higher produced hydrocarbons volumes. This can

motivate other companies to start using the DGD method. In addition, some tax systems give incentives for

CAPEX expenditure which can act as a motivation factor as well.

As stated by Redden (Redden, 2010), one reason that explains why DGD technology has not been applied as a

common practice in the early 2000s was the contracts period. At that time, rig contracts had a time span of 12

to 18 months which allowed to drill two or three wells, taking into account the slower daily rates employed at

that time comparing to what is common practice today. Nowadays, rig contracts have a longer duration, 4 to 5

years, allowing a higher investment in technology and making DGD more attractive. Obviously, the current

uncertainty in oil price contributes for the delayed implementation of this technology.

Well Control Procedures for Dual-Gradient Drilling

As reported by Rehm (Rehm. et al, 2008), the industry has expressed concern about DGD well control due to its

complexity, stating that it will be more difficult to implement and therefore is less safe than conventional deep

water well control. However, as stated by Rehm (Rehm. et al, 2008), this is not true. They claim that it is

different but with the controls installed into the DGD equipment, the well control is improved in several ways.

In DGD well control all the primary kick indicators of conventional drilling such as the increasing of flow rate

and pit volume, flowing well with pumps shut off and improper hole fill up during trips are applicable.

However, some of them are enhanced. For example, the seafloor pump is used as a positive displacement

meter and is much more accurate than a “Flo-Show”. When a kick occurs, the seafloor pump rate increases to

keep a constant inlet pressure. The increasing of frictional pressure in the return line is detected by the seafloor

pump outlet pressure gauge. If the pump is set to operate at a constant rate, the inlet pressure will increase

when a kick occurs (Rehm, B. et al, 2008).

Another advantage in DGD well control is the relatively small volume in the return line compared to the marine

riser. As the quantity of mud to be displaced is inferior, the bottoms up time decreases making the cuttings and

gas come up faster and pore pressure indicators are detected earlier (Rehm, B. et al, 2008). In the same

manner than conventional drilling methods, these are kick indicators and to verify that a kick is actually

occurring, a flow check must be performed.

CASE STUDIES

Two case studies, not related to each other, are presented. Both compare the conventional drilling method

with DGD technique but with different objectives. The first case demonstrates how much the maximum

horizontal drilling length can be increased when applying DGD. The second case shows the possibility of casing

strings reduction comparing to conventional drilling.

Case Study 1 – Increasing of Horizontal Drilling Length

The aim of this practical case is to determine the difference of the maximum horizontal length that a well with

the same characteristics and layout can reach by using conventional drilling method and DGD technique with

gas injection.

For the sake of clarity, the well was considered to be vertical until reach 10,000 ft and horizontal from this

point on, not considering the Kick-Off Point (KOP) and the Buildup Rate (BUR). Nevertheless, in the schematic

illustration of this case study a demonstrative curvature is represented.

Data description

Although no data was provided, it was possible to obtain values to perform this case study. Despite not being

able to release the information source, this data represents a typical real situation. In the table below are

shown all the values assumed during this exercise.


Table 1 - Data summary.

Depth of seafloor 3,500 ft

Planned depth of the horizontal section of the well 10,000 ft

Mud density 9.5 ppg

Pore pressure gradient 0.48 psi/ft

Fracture pressure gradient 0.52 psi/ft

Friction pipe loss 0.089 psi/ft

Friction annular loss 0.024 psi/ft

Pressure at seafloor after gas injection 1,300 psi

Data limitation

Since no values regarding the economical perspective were possible to obtain, the discussion and economic

impact evaluation cannot be performed from a quantitative point of view. However, it is important to mention

that this would be a very interesting analysis that could be done as future work.

Data limitation Since no values regarding the economical perspective were possible to obtain, the discussion and economic

impact evaluation cannot be performed from a quantitative point of view. However, it is important to mention

that this would be a very interesting analysis that could be done as future work.

Methods

Before calculate the maximum horizontal distances for both cases, a table of pressures determination is

presented below, considering the following expression:

Hydrostatic Pressure = ρ x Constant x Depth

To determine the maximum horizontal distance that is possible to reach when applying the DGD technique, it is

assumed that gas is injected at the seafloor and the pressure above the fluid interface drops to 1,300 psi.

Results

Determination of the maximum horizontal distance by using conventional drilling

Knowing that the hydrostatic pressure at bottomhole is 4,940 psi and the frictional annular loss is 240 psi, the

total pressure at bottomhole is calculated at 5,180 psi.

Thus, the difference between the fracture pressure and the bottomhole pressure is 20 psi.

Assuming that the friction annular loss is constant (0.024 psi/ft), it is possible to obtain the horizontal distance

that can be drilled until reach the fracture pressure. By applying a simple relation, a distance of 833 ft is

obtained.

Determination of the maximum horizontal distance by using DGD

Assuming that gas is being injected at the seafloor and the hydrostatic pressure ate seabed after the gas

injection drops from 1,729 psi to 1,300 psi, how far is it possible to drill horizontally?

In order to reply to this question, it is necessary to calculate the frictional annular loss between the drill bit and

the seafloor formations:

Hydrostatic pressure between the TD TVD and the seafloor + ΔPannulus + Pgas = FP ↔

↔ 9.5 x 0.052 x (10,000 – 3,500) + ΔPannulus + 1,300= 5,200 ↔

↔ ΔPannulus = 689 psi

Assuming that the friction annular loss is constant (0.024 psi/ft) and applying the same relation as before it is

possible to determine the total length that is possible to drill: 28,708 ft.

To determine the maximum horizontal distance, it is necessary to subtract the vertical length between the TD

TVD and the seafloor (6,500 ft), and therefore, it is possible to drill 22,208 ft.

Figure 7 shows a comparison of the maximum horizontal length drilled by using conventional drilling (orange)

and DGD – gas injection (green).

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Figure 7 - Schematic representation of the well trajectory and maximum horizontal length drilled by Conventional Methods and DGD – gas injection.

Discussion and Economic Impact

By changing the drilling method from conventional to DGD it is possible to increase the maximum horizontal

length from 833ft to 22,208ft. This has a huge impact in extended reach wells. Since it is possible to drill longer

wells, the necessity of drilling more wells reduces or even disappear. Besides the cost of a single well increases

due to its extension, the total cost of the prospect development and production decreases considerably.

Case Study 2 – Reduction of Casing Strings

This study has the objective of investigating the effect of DGD on the operational costs. According to this

purpose, a well casing program is planned by using conventional drilling. The results are then compared with

the casing program of a well located exactly at the same position, simulated by using DGD method.

Data description

As mention before, in the scope of this work, no real data about deep offshore was provided. Thus, all the

values used in this case study are hypothetical. PP and FG curves had to be manually built point by point to

define the drilling window, Figure 8. The curves behaviour is based on the practical case presented in Peker,

2012. However, the reasoning is valid for any set of real data.

Figure 8 - Drilling window definition.

Data limitation Since there is not actual data it is not possible to make an exhaustive comparison between conventional drilling

and DGD technique, essentially in the economic point of view.

Methods

To compare the number of casing strings applied in both drilling techniques, a water depth of 6,200 ft is

assumed. It is considered that the Top Of Reservoir (TOR) is located at 12,100 ft and the Oil Water Contact

(OWC) at 15,000 ft.

Also, mud densities used to drill each hole section are defined, except for conductor casing that is driven. Since

the drilling window is very narrow near the seafloor a mud of 8.8 ppg is defined to drill the first section. In the

next sections, the mud density is increased ensuring that fracture pressure is not exceeded.

To determine the number of casing strings a straight line corresponding to a determined mud gradient is drawn

from the surface until it intercepts the fracture pressure gradient line. At this point, a casing shoe is set. This

procedure is repeated with higher mud densities until reach the TD TVD.


The criteria to define these values were:

6,200 ft water depth: it is generally accepted that DGD is applicable in water depths greater than 5,000 ft;

Mud density: use a mud density which allows to run a casing string as longer as possible, ensuring an

overbalance of 200 psi and not exceeding the fracture pressure according with what was already discussed

regarding drilling window limits.

Results

Conventional Drilling

By applying these methods, in conventional drilling, the well would have 8 casing strings, Figure 9.

Figure 9 - Casing setting depths using Conventional Drilling.

Table 2 presents the casing program and the mud density used to drill each hole section.

Table 2 - Casing Program for Conventional Drilling.

Bit size [in] Casing O.D. [in] Casing Section Casing Type Shoe Depth [ft] Mud Density [ppg]

Driven 36 Conductor Casing 6,300 Sea water ≈ 8.7 ppg

30 24 Surface Casing 6,888 8.8

22 20 Intermediate Casing 7,216 9.0

17 1/2 16 Intermediate Casing 7,872 9.2

14 3/4 13 3/8 Intermediate Casing 8,528 9.5

12 1/4 10 3/4 Intermediate Liner 9,512 10.5


6 1/2 5 1/2 Production Liner 14,432 12.5

DGD method

In order to design the casing program applying DGD method, it was used seawater as drilling fluid to drill the

upper portion of the wellbore. Regarding the lower part, it was assumed the same criteria used in conventional

drilling. As shown in Figure 10, in this case the lines corresponding to mud gradients are designed from the

seabed until the TD TVD.

Figure 10 - Casing setting depths using DGD.


Table 3 presents the casing program and the mud density used to drill each hole section.

Table 3 - Casing Program for DGD.

Bit size [in]

Casing O.D. [in]

Casing Section Casing Type Shoe Depth

[ft] Mud Density

[ppg]

Driven 30 Conductor Casing 6,300 Sea water ≈ 8.7 ppg

26 20 Surface Casing 7,225 8.8

17 1/2 14 Intermediate Casing 8,528 10.2


8 1/2 7 Production Liner 13,120 14.3

Discussion and Economic Impact

By comparing Figures 9 and 10, it is evident the reduction of casing strings in DGD method. While in the first

case, 8 casing strings are necessary to ensure the well stability, in the second approach, only 5 casing strings

are required. Moreover, the Outside Diameter (O.D.) of the conductor casing is larger in conventional drilling

(36´´) which implies a higher cost. Besides that, the final diameter is larger in DGD method. In conventional

drilling, the final O.D. is 5 1/2 ´´, while in DGD method is 7´´. Assuming the same casing grade for both cases, 26

lb/ft, the Inside Diameter (I.D.) is respectively 4.548´´ and 6.276´´. This represents a huge difference when

choosing the production tubing size. The economic feasibility of the well can be affected, if the diameter of the

production tubing is too small.

Therefore, by applying DGD method it is expected a cost saving not only because less material is needed but

also due to drilling time decreasing. As stated in Advanced Drilling Techniques, 2006, DGD has the potential to

reduce costs over 50% and for each casing point that is eliminated, 4 to 6 days of rig are saved plus the cost of

hole evaluation, casing and logging. Considering that a day work has a cost of $18,500 (PSAC, 2015), by applying

DGD method it is possible to have a reduction up to $330,000 (37.5%) just taking into account the daily rig cost.

RISKS AND MITIGATIONS

The drilling operation involves a higher cost and a significant percentage is attributed to losses of drilling

equipment and drilling fluids. Despite being unlikely to perform a drilling operation without finding any

problem, by managing drilling risks it is possible to identify and control incidents that may arise. The risk index

is given by the multiplication of the impact by the likelihood as it is shown in table below.

Table 4 - Risk Index. Adapted from personal notes.

During the field development planning phase, all risks and hazards should be addressed. Risks must be

identified and the appropriate mitigation measures need to be in place.

Also, compliance to all company and regulatory HSE should be ensured. Preferably, the selected systems

should be passive, low maintenance and inherently safe as far as practicable (Chaudhury and Whooley, 2014).

CONCLUSIONS

The DGD is an unconventional drilling technique which allows to control the BHP in static and dynamic ways.

The hydrostatic gradient in the wellbore is composed by two different parts: in the upper section a lighter fluid

fills the annulus from the RKB down to the fluid interface depth and at the lower part a heavier mud is used. By

applying fluids with different densities it is possible to manage the BHP obtaining a pressure profile that better

fits the drilling window.


Regarding the economic aspect, despite this method requires a higher CAPEX, if applied in the right situations it

can bring significant cost savings. This economic success is achieved not only due to time-dependent causes but

also by other factors such as casing strings reduction, drilling fluid savings and enhanced HSE.

Concerning the application of DGD methods, although no real data are applied, the benefits of using DGD

technique in wells with a considerable water column are noticeable. In case study 1, the increasing of the

maximum horizontal distance is very significant. While using conventional drilling it is only possible to drill 833

ft, by applying DGD with gas injection this length increases to 22,208 ft. Regarding the case study 2, where the

objective is the number of casing strings reduction by the of application of DGD method, it is possible to

eliminate 3 casing strings with the benefit of increasing the final diameter. Even though, this study is based in

hypothetic values, it is important to mention that in case of analysing real data, a Leak Off Test (LOT) must be

conducted below each casing shoe to determine the fracture pressure of the formation.

SUGGESTIONS FOR FURTHER WORK

DGD techniques are still being developed and it is becoming increasingly important for the future of drilling

engineering. It is of the utmost importance to optimise its application and for this reason as future work, it is

proposed to perform a detailed study of the operation timeline when applying DGD, considering all the

procedures and equipment involved and the necessary hardware.

It is suggested to analyse a set of wells drilled with DGD technique and create a database to define a model to

be used in the industry. This will allow the optimisation of drilling operations as well as the possibility of

integration of this technology with other techniques. This could be performed in the context of a PhD program.

ACKNOWLEDGMENTS

This project was developed in the context of the Master of Science in Petroleum Engineering from Heriot-Watt

University, provided by ISPG and Galp. The author would like to express her acknowledgement to Galp all the

staff involved, for the opportunity to take part on this Master’s Program.

NOMENCLATURE

BHP Bottom Hole Pressure

BUR Buildup Rate

CAPEX Capital Expenditure

CBHP Constant Bottom Hole Pressure DGD Dual Gradient Drilling

ECD Equivalent Circulating Density

FG Fracture Gradient IADC

International Association of Drilling Contractors KOP Kick-Off Point

MPD Managed Pressure Drilling MCD Mud Cap Drilling NPT Non-Productive Time OBD Overbalanced Drilling

PP Pore Pressure

RFC Return Flow Control

TAMU Texas A&M University UBD Underbalanced Drilling


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