SPE/IADC 163455

Casing Design for Dual Gradient Wells Andre J. Cantrell, SPE, Cherokee Offshore Engineering, and Mingqin Duan, SPE, Chevron

Copyright 2013, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 57 March 2013. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright.

Abstract When planning dual gradient wells, it is important to understand the details of dual gradient drilling (DGD) operations and the resulting loads exerted on the casing strings in the wellbore. Standard casing design loads for conventionally drilled wells must be modified so that they apply to dual gradient drilling, and there are additional load cases specific to DGD that must be considered. This paper outlines those factors that should be accounted for in dual gradient casing design as compared to conventional deepwater casing design, including:

Internal and external pressure profiles for typical deepwater casing design load cases for drilling and production strings.

Additional load cases that should be considered for dual gradient drilling, such as running/cementing casing with an air gap in the string and tension/collapse combined loading when running in the hole.

Application of dual gradient pressure profiles to worst-case discharge load cases. Annular pressure buildup analysis for dual gradient wells. Negative test magnitudes and procedures.

While the dual gradient casing design loads are generally less severe than the corresponding load cases considered in conventional deepwater casing design, there are instances in which this does not hold true. Additionally, the collapse loads can be much greater than conventional due to the u-tube that exists during dual gradient operations. A thorough understanding of dual gradient operations is required to conduct a proper, diligent casing design that ensures a safe and efficient well plan and execution. Introduction There are several variations of dual gradient drilling (DGD) systems currently being employed in deepwater drilling. Recent interest in this technology has been driven by three main factors. First, the ability to restore riser margin exists with some of the dual gradient systems, so that kill weight mud is always in the wellbore, even in the event of a disconnect, drift off, or drive off. Second, if the dual gradient system is a closed system, then field practice has shown that kick detection is significantly improved (Nas 2011) when compared to conventional deepwater drilling operations. It is worth noting here that not all DGD systems are a truly closed system, and so this benefit is not obtained. Third, some improvement in drilling efficiency may ultimately be realized if the dual gradient pressure profiles and pressure management capabilities can reduce lost circulation non-productive time, prevent some wellbore stability troubles, and eliminate any of the numerous casing strings (particularly the contingency drilling strings) that are often required in deepwater wells. These benefits, and others, have been described in detail in prior literature (Smith et al 2000). This paper specifically discusses casing design load cases for wells drilled with a subsea mudlift pump, which has been field proven during a joint industry project (Eggemeyer et al 2001). The mudlift pump is comprised of six diaphragm chambers that are in various stages of filling with and discharging mud. The pumps control system manages the fill and discharge cycles as needed to maintain a constant pressure at the mudlift pump inlet. This inlet pressure is normally maintained approximately equal to seawater hydrostatic pressure, but a subsea rotating head can be run to allow for rapid changes in pressure as required (e.g. the inlet pressure may be increased to control pressure on a squeezing salt section). The pump takes

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mud returns from the wellbore and displaces them up a mud return line on the riser, while the fluid in the riser bore itself is a static fluid column with a density equivalent to seawater. This means that hydrostatic pressure on the wellbore is only a function of the mud weight below the mudline the pressure at the mudline is always maintained approximately equal to seawater hydrostatic pressure. The nature of this dual gradient system requires a systematic approach to casing design, in which the assumptions governing many standard load cases must be examined and validated. Consideration must be given to the different pressure profiles that exist in dual gradient drilling, plus the operational practices of working with a two-fluid system. This paper discusses the following considerations that must be accounted for in a dual gradient casing design.

Internal pressure profiles for burst loads, which is the driving force to burst the casing. Pressures for DGD are generally equal to or lower than the equivalent single gradient pressure profile.

External DGD pressure profiles for burst loads, which provides resistance to the internal pressure that is attempting to burst the casing. This external pressure is generally equal to or lower than the equivalent single gradient pressure profile, meaning there may be less resistance to burst in the DGD case.

External pressure profiles for collapse loads. In most cases the external pressure, which is the driving force for collapse, is lower in dual gradient drilling. However, there is a specific case in which this does not hold true.

Internal pressure profiles for collapse loads, which provide resistance to collapse. A collapse situation generally occurs when the internal pressure of the casing drops below some allowable threshold (e.g. the mud level in the well drops more than 500ft during a lost circulation event). Specific attention must be given to the unique situation in DGD of having two separate fluid systems 8.6ppg riser fluid and weighted DGD mud to maintain during a lost circulation or cementing scenario that would generally drive a collapse load.

Load cases that are specific to dual gradient drilling. Situations in which the well is converted from a dual gradient to single gradient well, and vice versa, must be accounted for. In addition, there are some potentially severe cases that result from the operational requirements of managing a two fluid system when running and cementing casing. These load cases can be significant when running large OD casing strings or contingency drilling liners, such as expandables.

Considerations for worst-case discharge loads. These load cases are often very severe and can be the limiting factor in any given casing design. The external pressure profiles typically used in these analyses are very different for dual gradient wells.

Consideration for annular pressure buildup analyses. Magnitudes of pressure buildup are not drastically different, but mitigations may be different for the dual gradient and single gradient load cases.

How to conduct a negative test when one is required, and an appropriate test pressure magnitude. The typical test value used in conventional operations (simulating a loss of mud hydrostatic in the riser) is obviously not applicable to the dual gradient case, since the riser will already be filled with fluid that has a density equivalent to seawater hydrostatic.

Dual Gradient Pressure Profiles Prior to understanding how a dual gradient casing design is different from a conventional design, it is necessary to define the operating parameters of dual gradient drilling with a subsea mudlift pump. This is imperative given the variety of dual gradient and managed pressure drilling systems currently being explored in deepwater. Dual gradient drilling with a subsea mudlift pump provides the opportunity to maintain kill weight mud in the wellbore from the mudline down and a pressure approximately equal to seawater hydrostatic at the mudline (Smith 2000). While the MLP inlet pressure can be increased above seawater hydrostatic to combat various drilling problems encountered, especially wellbore stability issues, the well will generally be flow checked with the inlet pressure at seawater hydrostatic prior to coming out of the hole with a drilling assembly. It should also be noted that the MLP is different from some other dual gradient systems in that the mudline pressure can never drop below seawater hydrostatic. The pump requires a pressure slightly greater than seawater hydrostatic to feed the pump so that mud can fill one side of the chamber while seawater exits the other side of the chamber.

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Therefore the mudline pressure is approximately equal to seawater hydrostatic pressure:

0.052 ..............................................1 The reduction in hydrostatic pressure at the mudline in DGD compared to SGD is then:

0.052 , ....................................2 Example: A well in 10,000 of water was planned to be drilled conventionally with a 15.2ppg mud weight at TD. Instead it is drilled using DGD with a subsea mudlift pump, resulting in approximately 3,400psi less pressure at the mudline (using an 8.6ppg density for seawater). The pressure at any point below the mudline can then be calculated as:

0.052 ,....................................3 The DGD mudlift pump maintains the pressure at the mudline constant, and so constructing any casing design pressure profile begins by starting at the mudline with seawatwer hydrostatic pressure. While the elevation of the pump, mud suction inlets, and rig floor all affect the actual mudline pressure, it is in the tens of psi and can be ignored for the sake of simplicity in casing design and consistency across all rigs and locations. The following sections describe how this standard DGD pressure profile is modified during various operations as an influx, cement, different weight mud, or air replaces the DGD mud in the well or the riser fluid in the riser. Internal Pressure Profiles for Burst Loads The specific burst load cases to consider for a given well design will vary depending on company policy and regulatory requirements. However, for a casing string exposed to drilling loads the internal pressure profile is almost always related to a kick scenario that fills some, or all, of the wellbore with an oil or gas column. A surface pressure is applied to maintain the wellbore pressure greater than some kick intensity. It is important to note that DGD well control is fundamentally identical to conventional well control when using the subsea mudlift pump. The primary objective is to maintain bottomhole pressure above formation pressure, using the DGD mudlift pump to control pressure in a manner that is analogous to using a surface choke to control pressure. Because of this the majority of the burst load cases considered in casing design are still applicable, since most burst load cases are modeling some type of well control event. Pressure profiles may differ, but the assumptions made and the reason for considering the case still exists. A caution should also be noted that not all variations of dual gradient drilling currently being explored maintain this close association to conventional subsea well control policies and procedures. Dual gradient systems without a static riser and a subsea positive displacement pump have very different kick detection, shut-in, and well control procedures. The kick scenarios that may result could be drastically different from the conventional cases described in this paper. Some examples of typical kick scenario burst pressures are:

Gas or Oil Kick A kick of a given size, intensity, and composition is simulated as an internal pressure profile, with an applied surface choke pressure. The parameters are adjusted based on available data for each hole section drilled. For example, an exploration well may be designed to sustain a 100bbl gas kick with an intensity of 2.0ppg, while a development well may only be designed to sustain a 50bbl oil kick with an intensity of 0.5ppg.

Maximum Anticipated Surface Pressure The wellbore is filled, either partially or entirely, with a simulated influx. Typical profiles are a full gas gradient on top of a fractured shoe, or a wellbore that is 50% gas and 50% mud with an applied surface pressure. This load case is often used to define BOP and surface choke manifold test pressure values, and is sometimes used to define casing test pressure values.

Some Fraction of Bottomhole Pressure at Surface Empirical data has shown that surface pressures during a well control event are generally limited to a fraction of the bottomhole pressure. A straight line is drawn from some fixed point downhole (shoe fracture pressure, bottomhole pressure, etc.) to the calculated surface pressure. This load case is obviously independent of the mud weight in the hole, and so if it is used there is no difference between the conventional and DGD load cases.

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For the first two types of load cases, the DGD internal pressure profile will be less than or equal to the SGD internal pressure for the equivalent load case. For the same influx size and bubble expansion, the required surface pressure will be less in DGD. The pore pressure and influx gradients are also fixed, and so the only remaining variable is the mud weight, which is higher in DGD. The higher mud weight will of course result in a greater psi/ft gradient that reduces the casing and surface pressure by a greater amount than would a single gradient mud weight. This comparison is shown in Fig. 1 below.

Figure 1. Comparison of internal pressure profiles with influx in the wellbore. Various other burst load scenarios should be considered based on planned operations, such as casing integrity pressure tests, leakoff tests, and pressures when bumping the plug during a cement job. In general these are less severe than the cases described above, but exceptions do exist, particularly when a nested liner well design is used and surface strings are still exposed when pressure testing deeper liners. External Pressure Profiles for Burst Loads To calculate an effective burst load, the internal pressure profile must be compared to some external pressure that provides a resistance to the casing bursting. There are three cases commonly considered: The first case considered is a pore pressure backup. The external pressure is simply equal to the pore pressure behind the casing. Knowing that the mud will not indefinitely maintain the initial gradient it had when the casing string was set, it is assumed that the pressure at each point behind the casing can degrade to the pore pressure. Of course for this case the external pressure profile is identical for either a single gradient or a dual gradient well design. The pore pressure is not a function of the mud weight pressure profile that exists when the hole section is drilled and the casing is set. The second case often considered is related to the minimum pore pressure in open hole and the base fluid of the mud. For deeper casing strings, it can be overly conservative to simply assume a pore pressure backup, especially if there is a long lap and the previous casing string was set deep. In these instances a backup profile is modeled in which the fluid column has fallen to balance the lowest pore pressure in the open hole, with a base fluid gradient above that point. The fluid gradient is either the base oil gradient for synthetic base mud or the mix water gradient for a water based mud. Once again, there is no difference between the dual gradient and single gradient profiles when using this assumed external pressure profile. The final case to consider is one in which the external pressure that existed when the casing was set still exists when the internal burst pressure profile is applied. This scenario exists when a tie-back string is run, and the annulus is trapped once the tie-back seals at the bottom of the string sting into the liner hanger and the casing hanger seals at the top of the string are set. This can also occur without a trapped annulus in the short term if the mud has good solids suspension properties, or if the annulus will be in an impermeable section (e.g. a long section of clean salt). In this load case it should be apparent that the external pressure resistance in the dual gradient case can be significantly less than that which would exist in a conventional,

Equivalent kick intensity and formation pressure

Equivalent influx gradient

DGD mud provides greater psi/ft reduction.

DGD mud provides lower pressures uphole.

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single gradient case. This is demonstrated in Fig. 2 below.

Figure 2. Comparison of dual gradient and single gradient external pressure profiles with a mud weight backup. The appropriate external pressure profile is then compared to each internal pressure profile to calculate a net burst load. Particularly when the external pressure profile with a mud weight backup is used, the DGD burst pressure calculated may be higher than it would be in a conventional well design. Internal Pressure Profiles for Collapse Loads Any operation that can cause a reduction in the internal pressure of a casing string must be considered as a collapse load case. In conventional operations this generally will only occur if the mud weight is reduced or if the mud level in the string drops (for instance, during a lost returns event). The first load case to be considered, a reduction in mud weight, is simple to model in either the dual gradient or single gradient load case. The obvious difference is that in DGD only the below mudline mud weight is reduced, while the 8.6ppg riser fluid remains constant. This means that any casing near the mudline sees a very small change in pressure only deeper portions of the string see a significant reduction in pressure when the mud weight is reduced. The second load case, a lost returns event, is much more difficult to model in both the conventional and the DGD case. The reduction in internal pressure that can cause a collapse load is a function of how much the fluid level is allowed to fall, if the hole is not kept full of mud, or what the hole is kept full of (e.g. base oil on top of synthetic mud). The well is often lined up on a smaller volume choke or kill line instead of the riser so that fluid volumes can be more accurately monitored, but there is not always time to do this in a severe lost circulation event. A dual gradient system will obviously complicate this second load case, since there can now be three fluids in the wellbore if the hole is not kept full (air gap/riser fluid/DGD mud) or is filled with base oil (base oil/riser fluid/DGD mud). Also, the riser fluid will change annular geometry as it falls below the mudline from either the riser itself or a choke/kill line. This is a complication that does not exist in single gradient, when there is not a gradient interface at the mudline when the lost circulation event begins. An appropriate approach to this potentially complicated situation is to model multiple collapse scenarios. Most wells cannot stand a full evacuation, which is often an unrealistically severe case since wellbore pressures and operational practices prevent a fully evacuated wellbore. Two limited evacuation cases that are more realistic than a full evacuation and are often substituted are:

1. The fluid level falls to balance pore pressure. Once bottomhole pressure equals the minimum pressure in the open hole section, it will be equal to the pore pressure and can fall no further. For dual gradient a simplifying assumption can be made the BOP is shut and the well lined up on the kill line to monitor the wellbore and more accurately measure the volume of fluid lost. This assumption also means that the small amount of riser fluid from the kill line that enters the wellbore below the mudline has an almost negligible effect on the gradient of the fluid below the

Bottomhole pressure is equivalent for the DGD and SGD cases

External pressure (i.e. burst resistance) is less at the mudline in a DGD profile

Mudline

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mudline, so that the gradient of fluid below the mudline can be assumed constant. This is due to the large difference in capacity between the kill line (0.0197bbl/ft for a 4.5in line) and the typical annulus at the mudline (0.299bbl/ft at the BOP down to 0.106bbl/ft inside a string of 13.625in casing). In other words, losing 500psi of hydrostatic in the kill line filled with 8.6ppg riser fluid will let 22bbl of riser fluid fall below the mudline. This 22bbl of riser fluid that was over 1100ft long in the kill line is only a 73ft column in the BOP stack. Even with a very heavy 18.5ppg DGD mud weight, this 73ft column is only equal to a 38psi reduction in hydrostatic below the mudline. This small difference is negligible and within the collapse safety factor generally applied.

2. Some given amount of riser fluid loss (e.g. 1000bbl) is allowed. A second approach is to model a very large, sudden loss in which the well cannot be lined up on the kill line, so that 8.6ppg riser fluid falls from the riser into the wellbore. The pore pressure is neglected and does not limit the amount of the fluid loss. In this case the riser fluid volume below the mudline is not insignificant, and so the reduction in hydrostatic pressure that occurs with riser fluid in the well must be accounted for. This should be considered a limit load that must be operationally understood. In other words, more diligence is required if a small volume (e.g. 200bbl) would cause the casing to collapse than if a large volume (e.g. 1000bbl) can be lost before collapse occurs.

Both of these cases result in an air gap above a column of riser fluid above a column of DGD mud, as shown in Fig. 3. Considered in conjunction, these two collapse load cases will give an indication of whether or not the well can sustain two of the most realistically severe load cases.

Figure 3. Examples of the internal pressure profiles for DGD lost returns collapse scenarios. External Pressure Profiles for Collapse Loads The reduced internal pressures described above are combined with an external pressure profile to create a differential collapse load. For a change in internal pressure, the external pressure used is often conservatively assumed to be the hydrostatic pressure due to mud weight when the casing string was set. Depending on whether the point in the well that required the highest mud weight (due to either pore pressure or wellbore stability) is at TD or somewhere uphole, this external pressure may be higher or lower than conventionally, as shown in Fig. 4 below. These external pressure profiles are combined with the internal pressure profiles described above to generate a net collapse

Air Gap

Riser Fluid Gradient

Mud Weight Gradient

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load. Whether this net load is compared to the casing collapse rating or the full effect of the internal pressure is not considered depends on whether the casing tends to fail in the elastic collapse or plastic collapse region (Klever and Tamano 2004). It is also common practice to consider a bi-axial tension/collapse case, since the collapse resistance of casing is significantly de-rated with applied tensile load.

Figure 4. Effect of depth of interest on the resulting collapse external pressure profile. Having a depth of interest uphole that requires a higher mud weight will result in a greater DGD external pressure and collapse load. A final load case that must be considered is the cementing load case. There are two competing forces that will determine whether the collapse load in a DGD cement job is greater or less than that in a conventional SGD cement job, all other things (TOC, TVD, spacer volume, etc.) being equal. Those two competing forces are:

1. Dual gradient cement and spacer density is closer to the density of dual gradient mud. Therefore, for the same bottomhole pressure with DGD and SGD mud, the increase in pressure due to the cement slurry is less with DGD. For example, consider well in which an 11.0ppg single gradient mud and a 14.5ppg dual gradient mud yield the same bottomhole pressure. Using a typical cement slurry with a weight of 16.4ppg, the increase in external (i.e. collapse) pressure with cement on the backside is 0.2808psi/ft in the single gradient case and 0.0988psi/ft in the dual gradient case, a difference of 182psi for every 1,000ft of cement lifted. Even with heavier DGD muds (17-19ppg) the corresponding increase in the weight of the slurry (18-20ppg) results in lower differential pressure than the conventional case.

2. The final stage of the displacement is completed with riser fluid. This will usually leave the casing/landing string with a lower internal pressure than external pressure, since the riser fluid is overdisplaced to a depth somewhere below the mudline on the landing string side. Being underbalanced on the landing string side helps prevent a wet shoe and simplifies hanger/seal assembly setting procedures, but exerts a collapse load on the string at all points below the mud/riser fluid interface in the annulus.

These two factors are generally offsetting, since typical cement jobs are only a few thousand feet of annular fill and the excess riser fluid will usually result in less than a 500psi reduction in internal pressure. Nevertheless these should be considered, particularly for large OD casing strings and expandables that have relatively low collapse ratings. Casing Design Load Cases Specific to Dual Gradient In addition to the standard load cases mentioned above that still exist in dual gradient operations with slightly modified pressure profiles, there are several load cases that are imposed during DGD operations that must be analyzed when designing a dual gradient well. In particular, the casing running and cementing operations are conducted with an air gap, and there is the possibility of needing to swap gradients from dual to single gradient. Either of these operations can result in large magnitude burst or collapse loads. In one instance the dual gradient drilling operation results in a greater tensile load as well. Note: At some point in every hole section the possibility exists for the well to be converted from DGD to SGD, while still maintaining an acceptable margin at the previous casing shoe. However, beyond a certain depth and DGD mud weight, it may not be possible to swap gradients if the margin at the shoe is not sufficient to sustain the column of single gradient mud required to keep mud hydrostatic above the formation pressure. Beyond that depth the mudlift pump must be repaired to continue the hole section or casing must be set at that depth and the cement displaced without use of the pump.

Minimum pressure requirement at 9kft (e.g. for wellbore stability issue)

Minimum pressure requirement at TD (e.g. for increasing pore pressure)

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The additional DGD casing design load cases to be considered are summarized in Table 1 and are described in detail in the following sections of this paper. Load Case Description When to Consider

Burst

Displacement from DGD to SGD

The well is converted to SG after a failure of the DGD equipment. DGD fluid must be circulated out of the well.

Every string. At some point in every hole section the possibility exists for the well to be converted from DGD to SGD, while still maintaining an acceptable margin. Beyond a certain depth (and corresponding DGD mud weight) this conversion may not be possible, since the shoe does have sufficient margin with a column of single gradient mud.

Maximum SGD MW after a DGD to SGD Conversion

Shallow casing strings are drilled in DGD and then the well is converted to SGD for any reason. Pressures near the mudline in SGD are much greater than in DGD.

If a mud weight, rather than pore pressure backup is being used for burst load cases. Mainly a concern for nested liner designs, in which shallow strings (22in and 16in) are not covered up by an intermediate long string (e.g. 13-5/8in or 9-7/8in).

Outrunning the U-Tube while Displacing Cement

When displacing cement with DGD mud, the landing string may be filled to surface due to high friction pressures in the drillstring or annulus.

All strings, but particularly when running hydraulic set hangers and tools that may yield due to the combined weight and pressure-area load generated.

Collapse

Displacement from SGD to DGD

The well is displaced from SGD mud to DGD mud below the mudline (increases internal pressure) and then the riser is displaced from SGD mud to 8.6ppg riser fluid (decreases internal pressure).

Any time the potential exists for a conversion from single to dual gradient.

RIH with Air Gap in the String

After the casing is displaced to mud, there is an air gap inside the string so that the u-tube remains balanced.

Every string, but particularly on large OD strings with low collapse ratings (i.e. 18in and 16in).

Pump Shutdown During a Cement Job

The pumps are shut down for any reason with cement in the string, and the u-tube falls below the original mud level.

Every string, but particularly on large OD strings with low collapse ratings (i.e. 18in and 16in).

Tension

Buoyed Weight with 8.6ppg Fluid

Until the string is at setting depth, the buoyancy factor will be less than a conventional buoyancy factor due to the reduced fluid weight in the riser.

Every string, but particularly those strings that are generally long and heavy (i.e. 16in and 13-5/8in).

Combined Load with Tension and Collapse Load Cases

The DGD casing running and cementing procedure results in several situations in which tensile load is high (due to reduced buoyancy) and collapse load is high (due to the air gap in the string).

Every string.

Table 1. Summary of DGD specific casing design load cases to consider. It is important to understand the operational procedures prior to describing these additional DGD load cases in detail. The next sections describe DGD casing running/cementing and swapping gradients, and the associated casing design loads. Dual Gradient Casing Running and Cementing The method for running and cementing a dual gradient string were previously described by Schumacher et al (2001) in conjunction with the Subsea Mudlift Drilling JIP. While the fundamental steps are still the same, and a close analog to a tophole riserless casing running/cementing operation, some minor changes have been made in the procedures. These changes are mainly a result of the increased use of hydraulically activated running tools, casing/liner hangers, and seal assemblies, as well as the greater string weights that are common today when compared to the JIP over a decade ago. The basic steps of a DGD casing running and cementing operation are:

1. Rig up to run casing.

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2. Run in hole with casing. The pipe will fill with 8.6ppg riser fluid through auto-fill floats. At this point pressures are balanced across the casing, but the buoyancy factor is about 0.87, which is significantly higher than conventional. The tensile load here must be considered when evaluating casing body, connection, running tool, and landing string tensile and slip crushing loads. Example : A string of 16in. 97# casing is run in 10,000ft of water. When the shoe reaches the mudline, the string weight is about 844kips. If the string were run conventionally in a 12.5ppg mud, the string weight would be about 785 kips, or almost 60kips less.

3. When the casing shoe is just above the DGD mudlift pump, displace the string from 8.6ppg riser fluid to weighted DGD mud. The DGD mud column will balance to seawater hydrostatic pressure, leaving an air gap in the casing string. This air gap results in a collapse load on the casing string that must be considered, especially in a combined load situation given the higher tension that exists when this collapse load occurs. This fluid level is referred to in shorthand as Top of Mud, or TOM.

Figure 5. Displacing the casing string from 8.6ppg riser fluid to weighted DGD MW before RIH exerts a collapse load that must be considered in both a uniaxial and bi-axial tension/collapse load case.

4. Contine running in the hole to TD. The pipe will now fill with weighted mud through the auto-fill floats, but the

mud level in the string remains constant at the same balance point of TOM achieved in the previous step.

5. Convert the floats by pumping at the float conversion rate.

6. Circulate as required to condition the mud and clean the hole for the cement job. As the flow rate increases, the TOM level must also change to keep the system balanced. The change in TOM is largely a function of drillstring and annulus friction pressure. At this point it is critical to characterize the u-tube behavior at various circulating rates and calibrate the pre-job cement models. Outrunning the u-tube would put a very high internal pressure on the running tool, which could prematurely set the hanger or put a large pressure-area load on the tool, particularly if the string is not landed out before the cement job.

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7. Pump spacer and cement. This will lower the TOM level as the heavier spacer and cement requires a smaller column of fluid to balance the u-tube at TD. This exerts a larger collapse pressure on the string whether or not it is significant depends on the volume of cement and spacer, the capacity of the casing/landing string, and the tension/collapse ratings of each component of the casing string.

8. Begin displacing cement with DGD mud. The TOM level will gradually rise again in the landing string as the heavy mud is pumped down the casing and up the backside. Throughout this step continued careful monitoring of the u-tube is required.

9. Finish the displacement with 8.6ppg riser fluid. This allows the air gap to be filled with fluid, so that a surface pressure can be monitored for lift pressure and plug bumping, and any activation pressure required for the hanger on the drillstring side can be applied. The volume of riser fluid pumped will generally exceed what is calculated as the capacity to the mudline, so that the landing string is always lighter than the annulus. This prevents a wet shoe if the plug does not hold pressure, but also exerts a collapse load on the casing string.

The steps of the DGD cement job are illustrated in Fig. 6. As shown there can be a large variation in the TOM level throughout the job due to changes in either circulating friction pressures or fluid densities. Both must be considered to ensure the cement job can be safely pumped.

Figure 6. Basic steps of a DGD cement job, with the large variations that can occur in the top of mud level throughout the operation. A cementing simulation that accurately models a DGD cement job is invaluable in predicting the pressure differential at various points in the string (landing string, running tool, transitions in casing size/weight, etc.) throughout the displacement. For the static cases, hand calculations are simple to conduct since the fluid columns on the landing string/casing side must always balance the annulus side, and friction does not alter the pressure profiles or TOM level. Dual Gradient Fluid Displacements Two fluid displacements in particular can result in large pressure variations on the casing string. Both occur when the well is

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being converted to or from a dual gradient well, in the event the entire well is not drilled dual gradient by plan or due to a pump failure. The general procedure for swapping from dual gradient to single gradient is to:

1. Set a packer or casing string.

2. Test the packer/casing against the blind shear rams. The test pressure should be at least as large as the expected pressure that will be seen during the DGD to SGD conversion. This value may exceed the casing test pressure required by regulations or company policy.

3. RIH with a displacement assembly.

4. Begin pumping single gradient mud down the drillstring, taking riser fluid returns at surface. Returns are taken at surface rather than with the DGD mudlift pump, since this conversion would often occur as a result of a pump failure.

5. Pressure on the wellbore increases as the riser is displaced from 8.6ppg riser fluid to DGD mud. This pressure continues to increase until all of the 8.6ppg riser fluid is displaced from the riser and the well is then full of DGD mud above SGD mud. The maximum pressure depends on the relative volume of the riser and wellbore. All other things equal, a larger riser volume results in a lower maximum pressure.

6. Continue circulating until the well is full of SGD mud.

7. Displace the choke and kill lines to SGD mud.

8. Unseat packer or drill out shoe and displace the DGD mud in the open hole or rat hole out of the wellbore. This volume will generally be much smaller than the previous DGD mud volume that was circulated out of the well, and so the resulting pressure increase is minimal. If the volume is large (i.e. the DGD mudlift pump failed with a large open hole section) then this volume might need to be circulated out in stages, but this is generally due to fracture gradient limitations rather than casing burst limitations.

9. Continue operations with the well full of SGD mud. Circulation is now conventional, with the DGD mudlift pump isolated and taking returns up the riser.

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Figure 7. Sequence of a DGD to SGD conversion, with the pump isolated. The maximum pressure on the casing occurs when all of the riser fluid has been displaced from the well. The general procedure for swapping from single gradient to dual gradient is to:

1. Set a packer or casing string.

2. Conduct a negative test on the well by displacing the choke or kill line from single gradient mud to 8.6ppg riser fluid. This is a standard operation, since the well should be able to sustain a displacement to seawater for an evacuation or abandonment without failure.

3. Close a ram or annular to trap the mudline pressure. This is a precaution in the event the displacement of the riser occurs too quickly and the riser cannot be kept full of fluid.

4. Begin circulating the top of the riser with a pit or trip tank filled with 8.6ppg riser fluid.

5. Turn on the DGD MLP, with the inlet pressure set at a value to keep the riser full of single gradient mud.

6. Gradually reduce the DGD MLP inlet pressure setpoint in 50psi increments. The pump will pump single gradient mud while the riser fluid trip tanks top fill the riser with 8.6ppg riser fluid.

7. Once the riser is full of 8.6ppg riser fluid, line up the DGD MLP to take returns from the well. This is a standard lineup for the DGD MLP and is done by isolating the riser and opening up the high-pressure suction to the BOP stack.

8. Displace the well below the mudline from single gradient mud to DGD mud. The displacement starts with single gradient hydrostatic pressure at the mudline. Gradually reduce it to seawater hydrostatic by adjusting the DGD MLP inlet pressure as DGD mud replaces single gradient mud in the wellbore, following a pressure schedule.

Once the well is converted to DGD, the mudline pressure will be at seawater hydrostatic, but the bottomhole pressure will be equal to what it was with single gradient mud prior to the conversion.

SPE/IADC 163455 13

Worst Case Discharge Load Cases Most wells are now required by regulation to pass two very severe load cases that are associated with a worst case discharge. Both assume a blowout in which the well is open to seawater hydrostatic pressure at the mudline and the wellbore below the mudline is entirely filled with formation fluid. The first load case, a flowing wellbore, is a large collapse load that occurs when the BOP is disconnected and seawater hydrostatic exists at the mudline. The internal pressure increases from seawater hydrostatic at the mudline by an amount equal to the pressure gradient of formation fluid times the vertical depth to the point of interest. The pressure gradient can vary from a low gas gradient to a somewhat higher oil gradient both are much less than the mud weight gradient that existed just prior to the worst case discharge event. Friction pressure due to the formation fluid flowing up the wellbore is essentially negligible. This results in a potentially very large collapse load. The second load case, a shut-in wellbore, is a large burst load that occurs when a capping stack is installed to contain the blowout. Once the well is shut-in the mudline pressure increases from seawater hydrostatic to whatever pressure is required to balance the formation pressure in the open hole section that is flowing. The wellbore is filled with formation fluid, and so the pressure decreases at all points above the worst case discharge zone by an amount equal to the influx gradient. This load case is similar to the MASP load case previously mentioned, except that the entire wellbore volume from the mudline down is filled with formation fluid. The internal pressures associated with these load cases are obviously independent of the mud weight and are identical in the conventional and DGD case. The external pressures, however, are not. Various tools exist to evaluate the worst-case discharge cases, and care must be taken to understand the assumptions in the external pressures, as they do not generally apply in a DGD well. For example, if a mud weight backup is used in the burst case, then the external pressure at the mudline is significantly less if the casing string was set in a dual gradient operation. This reduced pressure yields a significantly larger net burst load when considering the shut-in case. Consider the figure below which shows an example of a typical deepwater well design with worst-case discharge sands exposed in the lowermost hole section. The intermediate casing string, generally a 13-5/8in or 14in string, is run as a long string or a liner and then tied back to the subsea wellhead. The external pressure at the mudline, where shut-in loads are the highest with the capping stack installed, is often much less when set with riser fluid in the riser during DGD operations instead of the mud weight that is typically in the riser conventionally.

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Figure 8. Example of difference in external pressure at the mudline when the tie- Back is set with single gradient mud in the riser versus 8.6ppg riser fluid in the riser. External pressures in the flowing load case are more difficult to calculate. It can conservatively be assumed that the external pressure is equal to the fracture gradient. If some other boundary condition is assumed (such as a modeled pressure increase due to temperature changes, the fracture pressure at the previous shoe, or some hydraulic isolation depth, or HID, based on an expected top of competent cement) it should be noted that the pressure profile in DGD from the prevous shoe assuming the shoe fractures down to the the HID will be greater, due to the greater fluid density. This is demonstrated for a common external pressure profile in Fig. 9. The pressure below the HID can be assumed to be pore pressure. However, if the modeled pressure increase due to temperature changes is not high enough to break down the formation at the previous shoe, for the same amount of pressure increase in the annulus, the pressure profile in DGD above the HID will usually be lower, since the DGD pressure profile is generally lower than a conventional pressure profile at all depths above TD, as demonstrated previously in Figure 2.

SPE/IADC 163455 15

Figure 9. Example of a typical external profile for the worst case discharge flowing case. Note that if the shoe is assumed to break down, the net collapse load will be greater in DGD than in a conventional well design. Annular Pressure Buildup in DGD Wells With a subsea wellhead there is no way to bleed annulus pressure once production loads heat the fluid that can be trapped between the surface and intermediate casing strings. This problem, known as annular pressure buildup (APB) is well known and there are various methods to deal with it. There will be very little difference in the magnitude of the annular pressure buildup between a single gradient and dual gradient well design. The magnitude of the pressure increase is very weakly a function of the mud density, which does change with DGD, and a very strong function of parameters that do not change in DGD base fluid compressibility, annular volume, temperature increase from the installed to the production case, the casing size, and casing metallurgical properties (Youngs Modulus and the linear coefficient of thermal expansion, in particular). Typical measures taken to mitigate the effects of annular pressure buildup include prevention of temperature buildup using vacuum insulated tubing (VIT) and relief of pressure buildup with collapsible foam, shrinking fluids, burst discs in the casing, or leaving the annulus open to the formation by keeping the top of cement (TOC) below the previous shoe. The only ones that are affected by a dual gradient pressure profile are the use of burst discs and leaving TOC below the previous shoe. Placement of burst discs is critical in a dual gradient well design, since the starting internal pressure across the burst disc will generally be lower than conventional. This results in a larger pressure buildup prior before it is relieved by the burst disc rupture. An example of this is shown in Fig. 10 below. Once modeling of the annular pressure buildup is completed, the value should be compared to the differential pressure that already exists at the rupture disc and the rupture disc rating to ensure pressure relief occurs before casing fails somewhere else in the wellbore. If a failure would likely result before the rupture disc bursts, the only options for mitigating this problem are to move the burst disc lower in the annulus or to use a rupture disc with a lower rating (i.e. relief pressure).

14,000

16,000

18,000

20,000

10,000 12,000 14,000 16,000

True

Vertical

Depth(

ft)

CollapseinWorstCaseDischargeExternalPressureProfile(psi)

SGDProfileDGDProfileFractureGradient

Both profiles are limited by the fracture gradient at the shoe.

Below the hydraulic isolation depth, both profiles equal pore pressure.

The DGD pressure profile is greater between the shoe and hydraulic isolation depth due to the higher mud weight gradient.

16 SPE/IADC 163455

Figure 10. Differential pressure across an APB relief burst disc in a conventional and a DGD well design. Pressure buildup in an untrapped annulus (i.e. TOC is below the previous shoe) is similar to the case of using burst discs. The APB will be limited bythe fracture pressure at the previous shoe or the weakest point in the uncemented open hole. A larger pressure buildup is expected in DGD before the shoe fractures, since the initial hydrostat pressure at the shoe is lower in DGD. Once the shoe (or some other weak zone) fractures, the collapse load below that point will be greater in DGD because of the higher mud density. Negative Test Pressure Magnitudes and Procedures Prior to displacing the riser to seawater and disconnecting in conventional operations, a negative test is often conducted that simulates the reduction in pressure that will result when the heavy mud in the riser is displaced. This negative pressure test can exceed 5,000psi in deep water depths. In DGD operations the riser is displaced from 8.6ppg riser fluid to 8.6ppg seawater, so there is no reason to conduct a negative test of large magnitude. However, a nominal negative test would be beneficial to confirm that all barriers in the wellbore are capable of holding some pressure from below. For water depths greater than 5,000ft, a negative test of over 500psi can be conducted by simply displacing the kill line from 8.6ppg riser fluid to base oil with a density of approximately 6.5ppg. This is sufficient for a negative test prior to either a temporary evacuation or an abandonment. Note that this places a collapse pressure on any BOP equipment, and collapse ratings must be verified for any sealing elements or gaskets exposed during the negative test. If a larger negative test is required an open-ended assembly must be tripped into the wellbore and displaced to 8.6ppg riser fluid. After displacing sufficient riser fluid down the drillstring to achieve the desired negative test, the test rams on the BOP can be closed and the drillstring monitored for flow. It is apparent that there is a practical limit to the negative test value that can be accomplished this way, since the maximum differential is equal to the reduced pressure that is obtained if the entire depth below the mudline is displaced to 8.6ppg riser fluid. However, this method is sufficient to test all conceivable pressure reductions that the well will be exposed to during normal operations. Example: A 1,000psi negative test is planned to test a 13-5/8in liner top before cutting the mud weight by 2.0ppg to drill the next hole section. An open-ended drillstring is tripped below the mudline about 3,000ft. The string is displaced from 16.0ppg mud to 8.6ppg riser fluid down to a depth approximately 2,600ft, which results in an underbalance on the drillstring of 1,000psi. The test rams are shut, the surface pressure is bled off, and the drillstring is monitored for flow.

SPE/IADC 163455 17

Conclusions Dual gradient drilling with a subsea mudlift pump still requires consideration of many of the standard deepwater casing design load cases, but with a modification to both the internal and external pressure profiles used. Depending on the well design, hole conditions, and operational constraints, the resulting loads in DGD can be more severe than the equivalent conventional load case. A diligent consideration of the unique pressure profiles that exist in DGD is required by the engineer designing the well. In addition to the standard load cases, there are additional burst, collapse, and tensile loads that are imparted on the string during DGD operations due to the unique nature of handling two fluids seawater density fluid in the riser and weighted mud below the mudline. Particularly severe loads can exists when running and cementing casing or when converting a well from DGD back to conventional. The worst-case discharge scenario may still be considered in DGD if required by regulation or company policy. While the internal pressure profile is fixed by the blowout that is assumed to occur, the net loads exerted on the casing string may be different in dual gradient if a mud weight profile is used for the external pressure. Mitigations for APB, particularly in terms of burst disc placement, must account for the lower pressures that will exist near the mudline in a DGD trapped annulus. While the fundamentals of casing design are basic and are very similar whether conducting a DGD or conventional casing design, diligence is required by the engineer designing the well to ensure a robust design. It cannot simply be assumed that because the pressures near the mudline are substantially lower during normal, drilling ahead DGD operations that the loads imparted on the casing will always be lower in a DGD well design. Nomenclature APB : Annular Pressure Buildup BOP : Blowout Preventer DGD : Dual Gradient Drilling HID : Hydraulic Isolation Depth MASP : Maximum Anticipated Surface Pressure MLP : Mudlift Pump MW : Mud Weight MWDGD,ppg : Dual Gradient Mud Weight, in pounds per gallon MWSG,ppg : Single Gradient Mud Weight, in pounds per gallon OD : Outer Diameter P : Pressure PMudline : Pressure at the Mudline RIH : Run in Hole SGD : Single Gradient Drilling SWppg : Seawater Density, in pounds per gallon TD : Total Depth TOC : Top of Cement TOM : Top of Mud TVD : True Vertical Depth TVDBML : True Vertical Depth Below the Mudline VIT : Vacuum Insulated Tubing WCD : Worst Case Discharge WD : Water Depth References Eggemeyer, P.E., Akins, M.E., Braiard, R.R, et al. Subsea Mudlift Drilling: Design and Implementation of a Dual Gradient

Drilling System. Paper SPE 71359 presented at the SPE Annual Technical Conference and Exhibition in New Orleans, Louisiana 30 September 3 October 2001.

Klever, F.J and Tamano, T. A New OCTG Strength Equation for Collapse Under Combined Loads. Paper SPE 90904

presented at the SPE Annual Technical Conference and Exhibition in Houston, Texas 26-29 September 2004. Nas, S. 2011. Kick Detection and Well Control in a Closed Wellbore. Paper SPE 143099 presented at the IADC/SPE

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Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition in Denver, Colorado, USA, 5-6 April 2011.

Schumacher, J.P., Dowell, J.D., Ribbeck, L.R., et al. Subsea Mudlift Drilling: Planning and Preparation for the First Subsea

Field Test of a Full-Scale Dual Gradient Drilling System at Green Canyon 136, Gulf of Mexico. Paper SPE 71358 presentated at the SPE Annual Technical Conference and Exhibition in New Orleans, Louisiana 30 September 3 October 2001.

Smith, K.L, Weddle, C.E., Peterman, C.P., et al. Dual-gradient drilling nearly ready for field test. World Oil. October 2000,

Volume 221, Number 10.