Copyright 2006, Offshore Technology Conference This paper was prepared for presentation at the 2006 Offshore Technology Conference held in Houston, Texas, U.S.A., 14 May 2006. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference 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 where and by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Subsea field developments are generally recognized as having lower recovery factors than fields developed by fixed installations. To increase the recovery factor from subsea developed reservoirs, new technologies that will reduce the costs of infill drilling and allow for more cost effective well interventions, must be developed. One potential technology is Through Tubing Rotary Drilling (TTRD). However, for the industry to perform extended reach TTRD from existing subsea producers using floating rigs, the way we manage pressure must be re-evaluated. TTRD combined with Managed Pressure Drilling (MPD) will be the key technologies needed to achieve the low cost, high performance drainage points.

This paper describes several MPD methods that can be combined with TTRD and how these methods can be classified, evaluated and applied. Specific results from theoretical simulations will show how two different MPD methods can be used to drill longer departure drainage points than with conventional pressure control. Successful TTRD is believed to produce low cost drainage points for a fraction of the cost of a new subsea well. Introduction Some of the reasons behind the lower recovery factors from subsea developed reservoirs are:

1. Reduced accessibility to the well for interventions, repair and workover purposes

2. Lack of cost efficient well intervention tools and methods

3. High cost of new wells for infill drilling purpose 4. Escalating tangible costs and dayrates of Mobile

Offshore Drilling Units (MODU) Effective well spacing and well placement in the producing

reservoir is recognized as requirements for optimum reservoir

drainage. The ability to access bypassed oil and gas reserves in mature fields has been gaining more and more attention in recent years. Mature fields have huge reserves that lie in multiple isolated pockets that would be uneconomic to produce using new wells. This may particularly be the case in subsea fields in deeper waters where the soaring dayrates for mobile offshore drilling units (MODU) will make the minimum economical reserve requirements hard to find.

Through Tubing Drilling (TTD) is a method that eliminates the need for expensive conventional (new) wells or sidetracks. Avoiding drilling the transport distance down to the reservoir reduces the costs significantly. In addition, the re-use of the in-place completion equipment saves time for removing the old completion, time for running the new completion and CAPEX of the new completion.

Coiled Tubing Drilling (CTD) has been the preferred and dominating TTD technique from fixed installations. However, when a drilling rig is available, the use of jointed pipe and rotary drilling operations has gradually become the more attractive option. The main advantage of using TTRD is the ability to rotate the drillpipe which improves hole cleaning, drilling mechanics, and ultimately increases the reach capability. Thus an obvious potential application of TTRD is infill drilling to access new reserves in subsea wells.

TTRD in subsea fields faces several challenges. Many are associated with the narrow annulus between the production bore and the drillpipe, and to the variable formation pressures and lower fracture strengths in depleted formations. Another of the industrys concerns of TTRD is the potential for wear/damage of the tubing and downhole safety equipment.

Subsea TTRD operations are at the present in its infancy. Subsea TTRD has been performed in horizontal 7 in. monobore completions on the Norwegian continental shelf by Norsk Hydro on the Njord field and by Statoil on the Norne field. These operations have been conducted using a conventional drilling riser package, consisting of a 21 in. marine riser and a 18 3/4 in. subsea blowout preventer (BOP) package. Several new tools and procedures have been developed to protect key elements in the completion string and in the subsea christmas tree. However, this conventional riser and BOP set-up will significantly increase the challenges of incorporating MPD technologies with the TTRD concept. This paper will describe some of the options available and the pros and cons for these concepts of MPD in subsea TTRD.

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Managed-Pressure Drilling; Techniques and Options for Improving Efficiency, Operability, and Well Safety in Subsea TTRDB. Fossli, Ocean Riser Systems AS, and S. Sangesland, O.S. Rasmussen, and P. Skalle, Norwegian U. of Science and Technology

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Subsea TTRD Challenges Equivalent Circulating Densities A major challenge in both on- and offshore TTRD operations is the problem related to Equivalent Circulation Density (ECD). High annular pressure losses, resulting in high ECDs can lead to lost circulation and differential sticking. The small annular space can also cause high surge pressures or increase the risk of swabbing in a kick when tripping (localized ECD effect). The optimum safe trip speed must be predicted from surge and swab calculations. Pipe protectors might be prohibited because they lead to an even higher ECD. However, selecting smaller drillpipe to reduce ECD effects is not necessarily an option as only slight changes of drillpipe ID will significantly change the standpipe pressure, which in turn may limit circulation rates1. At desired circulation rates, exceeding the mud pumps pressure rating might occur in long deviated wells. For these reasons TTRD circulation rates are much lower than in conventional drilling.

In slim hole horizontal drilling operations, the percentage of solids content in the drilling fluid might be higher than in conventional drilling (> 20 %). This will influence rheology and consequently both hydrostatic and dynamic pressures, further aggravating the situation.

Also, a MODU is also exposed to heave. Today, most rigs have an active/passive motion compensator built into the crown block or drawwork that reduce heave-induced pipe movement. However, when making connections, the drillstring/casing is suspended from the rotary table and the string will then follow the rigs movement. Hence, pressure changes caused by pipe movements can result in alternating surge and swab effects that results in fluctuating bottomhole pressures.

Hole Cleaning Hole cleaning in TTRD wells is a balance between competing technical and operational needs. Hole cleaning can be achieved through mechanical methods (pipe rotation) or efficient hydraulics. The effect of drillpipe rotation can reduce the formation of cuttings bed by as much as 80 %2. If significant cuttings beds are allowed to accumulate inside the completion during TTD operations, the drillstring and/or BHA can become stuck or packed off inside the completion. This can lead to increased bottomhole pressure, mud losses and formation damage, and can ultimately lead to the loss of the well.

In todays high-angle wells, barite sag is a well recognized phenomenon. Barite sag occurs due to settling of the weighting agent when circulation is stopped and results in undesirable fluctuations in mud weights3. This can cause problems such as lost circulation, reduced wellbore stability, well control events, and stuck pipe incidents4,5.

When the drillstring is not rotated, for example, while performing oriented drilling, the cuttings cleaning efficiency is greatly reduced. To improve cleaning, either higher circulating rates and/or mechanical aids are required. A BHA oscillator could be helpful in increasing the amount of cuttings bed disturbance1. A 3-3/8 in. commercially-available agitator will oscillate the BHA at 26 Hz at a flow rate of 500 lpm (120 gpm). However, the tradeoff is that the pressure drop across the agitator is 26-35 bars, which may be prohibitive in some operations.

Drilling Fluids Selection The rheology of the drilling fluid must be designed carefully for TTRD operations. There are two conflicting design requirements:

Low ECD (achieved through low viscosity) Low solids settling tendency (achieved through high

viscosity) Two major drilling fluid service companies have solved these

requirements differently, but the results are the same; by applying weight material with small particle size both rheology and sagging tendency have been improved compared with conventional mud systems 6,7. Formate mud, where density is achieved through soluble salts and not through solids is an attractive alternative but its high cost may limit its application 8.

Hole Stability In depleted reservoirs, pore pressures may have dropped significantly causing the overlying shale to become unstable. Also, in these reservoirs, the fracture pressure will be reduced while the pore pressure remains virgin in overlaying and interbeded shale and sealed sand pockets. The mud weight must be kept as low as possible to avoid fracturing caused by high ECD, yet high enough to maintain borehole stability. Figure 1 shows typical pressures in a depleted North Sea reservoir.

Figure1. Typical predicted pore and fracture pressures in a horizontal well at 2859 m TVD.

Well Control (Downhole Considerations) Slim well openhole annular capacities are typically 2-3 liters per meter. The surge and swab pressures are high and it is therefore important to note that:

More than 25 % of the blowouts in drilling result from pressure reduction in the borehole directly due to swabbing when pulling pipe.

Excessive surge pressure can cause lost circulation problems both during drilling operation and during running of casing/liners into the hole.

A one m3 influx would, because of the small annular capacity, evacuate 300500 m of hole, which in many cases is more than the entire openhole. Kick detection and accurate kick volume measurements are therefore paramount.

The critical difference between conventional well control and slimhole well control practices is in the handling of annular pressure loss and its potential impact on wellbore integrity. Conventional well control methods rely on the assumption that at the selected slow pump circulation rate, the annular pressure loss is significantly reduced or negligible. The annular pressure loss in slimhole drilling, even at slower kill rates, is considerably higher than in conventional wells.

Measured Lithology Pore and Fracture Depth (m) equivalent mud density (SG)

0.8 1.55 1.61 1.80 1.90

4500 5400 5500 -

Sand Shale

Sand (Pristine reservoir)

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Well Control (Subsea and Surface Considerations) When planning TTRD in subsea wells, there are several issues that must be evaluated regarding the marine riser system and surface equipment when considering well control aspects. If a conventional, low-pressure 21 in. marine drilling riser is used, riser boosting will be needed to transport cuttings because of the low circulating rates used. This might hinder the detection of a small influx.

Detecting a small influx though conventional pit gain monitoring or an increase in flow might not be possible even if very accurate boosting volumes are kept. In deep waters, the mud volume in the riser is often several times greater than the annular volume below mudline. For example, with 3 in. drillpipe in 1000 m water depth, the annular mud volume in a 21 in. riser is more than 3 times the annular volume in a well completed with 4000 m of 7 in. tubing and 500 m of openhole.

The use of conventional LP risers with a subsea BOP package will create higher chokeline frictions than HP risers with surface BOPs. In environments with tight tolerances, a surface BOP package might be preferred.

Cementing Operations Cementing operations of slim liners face two important challenges: 1) high ECDs, particularly at the end of the displacement period, and 2) poor mud displacement efficiency that can cause insufficient circumferential cement coverage of the liner.

Liner centralization can reduce these effects, but centralizer selection is limited. Bow centralizers are not used because of excessive running friction forces, thus rigid centralizers are often selected10. The cement slurry must be pumped in laminar flow due to high ECD hence preventing effective displacement of mud and filter cake. Because cementing operations often are difficult, other forms of zonal isolation methods should be considered. One such alternative might be to use swell packers 9 or other forms of external liner/casing packers.

The Role of Managed Pressure Drilling Seven challenges have been briefly discussed above when applying TTRD in subsea wells.

1. High ECDs 2. Hole cleaning 3. Drilling fluid selection 4. Hole stability issues 5. Pore pressure variations 6. Well control issues 7. Cementing and zonal isolation

All of the above issues can be solved or managed with the proper application of Managed Pressure Drilling (MPD) methods and equipment. MPD can be defined as the ability to drill in overbalance with a near constant bottomhole pressure independent of the circulation rate used. Therefore, MPD will be even more applicable to TTRD than in conventional drilling. However, because most methods of MPD so far has been applied to land operations or offshore platforms with dry christmas trees and BOPs, there are special considerations which must be addressed when applying this technology to subsea TTRD. These considerations are particularly related to;

1. Subsea BOP package and the drilling riser 2. Well control and well integrity issues 3. MODU specifications and surface equipment issues

Subsea BOP Package and the Drilling Riser Several issues need to be considered when evaluating the BOP and riser package if MPD technology is to be used. There will be three main options;

1. Low pressure riser 2. High pressure riser 3. Variations of the above or concentric risers

In broad terms, the riser and BOP package will determine what methods of MPD technology that will be applicable.

In general low pressure riser systems will require a full subsea BOP package with high-pressure (HP) kill/choke lines running back to the rig. By choosing this setup, the MPD technologies available will be more limited. Although a surface Rotating Control Device (RCD) might be used in conjunction with a LP riser in certain situations, the potential high pressures that might be encountered in many areas will generally require the RCD to be placed subsea. Chokes might be placed either subsea or at surface.

In general, high pressure riser packages will carry a surface BOP package or a split BOP package (surface and subsea components). The RCD and the chokes in this setup will be placed at surface. Hence, a high pressure riser system will allow for more MPD options to be used.

There could also be considerable economic benefits from utilizing a slim riser and BOP package. When slimming down the riser and BOP package, the ability to handle high pressures also becomes evident. Because most subsea completions have an outside diameter of 7 in. or less, the BOP and riser could be slimmed down to 7 1/16 in. 7 3/8 in. ID. A smaller and lighter riser package would also allow for the use of a less expensive MODU in deeper waters. In addition, the use of a small HP riser would allow for a rapid change from performing conventional drilling operations to underbalanced well interventions, using wireline and/or coiled tubing (CT) equipment.

A concentric riser system is also conceivable. However this will be somewhat more complex to operate and manage with MPD operations.

One particular challenge in TTRD operations is that wireline operations (WL) or CT operations may require full wellhead pressure to be exerted in the riser in preparation for the drilling operations or in the re-completion phase in preparation for production. There will be substantial economical benefits from being able to switch swiftly from underbalanced WL or CT operations to drilling with jointed pipe. Preferably the same riser and BOP package should be used for both underbalanced WL, CT, and drilling activities. When considering the high dayrates for the larger MODUs, this option becomes most attractive. Well Control and Well Integrity Issues Well control issues become particularly important when performing MPD operations from a floating vessel12. Kick detection and control of influx becomes even more challenging in TTRD operations. Hence, well integrity issues are important when choosing both the riser and BOP system and the primary MPD technology to be used. In this evaluation, the type of positioning principle of the MODU and the climatic, met ocean condition and water depth enter into this equation.

Performing MPD operation with a riser margin (RM) is desirable, but not always possible. However, some MPD technologies will make this possible. Normally, a conventional

4 OTC 17798

MPD system with a pressurized HP riser and surface chokes, a riser margin is not obtainable. In order to maintain a riser margin in MPD operations, variations of dual gradient drilling or using the Controlled Mud Cap (CMC) method must be applied.

Another factor to consider is the ability and speed of tripping the drillstring without jeopardizing well integrity, swabbing or loosing returns due to fracturing. It is not uncommon to spend up to 30 % of the total time on trips in TTRD operations. Several MPD methods will require full displacement of heavier mud in the hole to avoid the requirement for stripping/snubbing. Stripping pipe in TTRD operations should be avoided for several reasons: 1) Significant incremental time, 2) risk of losing well integrity (less barriers) and 3) extra wear on the on the RCD.

Several methods of MPD will allow for fast introduction of sufficient trip margin without having to circulate the entire annulus volume to a heavier fluid (and subsequent need to circulate out the heavier fluid prior to resuming drilling). Some of these methods will also allow for faster tripping than with conventional pressure control.

Kick or flow detection from the reservoir has been addressed earlier. There are significant differences on how this can be achieved with the different MPD methods.

How influxes are handled depends on the capability of the MPD system to handle annular pressures losses and the ability of the MODU equipment to handle various volumes of gas. In some cases of large inflow volumes, which may occur during underbalance drilling (UBD) operations, bullheading might be the only option. Although bullheading formation influx is an option, it is usually found to be detrimental to subsequent reservoir productivity, thus should be avoided.

MODU Specifications and Surface Equipment Issues In severe cases of flow due to underbalance, bull heading might be the only alternative. This will depend upon the MPD methods ability to control annular pressure in the well and the MODUs ability to handle large amount of gas and/or whether the rig has a 4 phase separation package installed.

For TTRD operations, Dynamic Positioned (DP) MODU will normally be favored. One reason for favoring DP is avoiding anchor handling among pipeline and production related installations on the seabed. A second issue is the time saved with using DP MODU. TTRD operations will normally take less time than drilling and completing a conventional subsea well, hence the mean time between rig moves will decline. Several days with anchor handling can easily neutralize the effect of lower dayrates with an anchored MODU compared to a DP MODU. The downside of DP is the higher requirements on well integrity and in relation to riser/BOP equipment, to compensate for accidental drive offs or drift offs.

MPD Classification and Evaluation of Options and Methods An approach to classification for MPD for subsea TTRD has been suggested as illustrated in Table 1. There are 3 main categories;

1. Closed systems (CS) 2. Open systems (OS) 3. Independent systems (IS)

Table 1 shows the variations for the different systems and how the different methods relate to the different riser and BOP

options, rig positioning methods, and how they may impact important well control and operational issues.

The closed and open categories of MPD systems can be divided into 2 main groups;

1. Systems requiring a HP riser system with surface/or split BOPs (HP)

2. Systems utilizing a LP marine riser system and subsea BOPs (LP)

Although some MPD methods might be used within both main system categories (CS or OS) and both riser groups, they seem to fall naturally into either the HP or LP riser category. One exception here is the Controlled Mud Cap (CMC) system which includes a RCD, but the system will always perform as an open system even though it will generally operate with the RCD in closed position.

The third category (IS) includes systems that are independent of whether it is used in open or closed systems and independent of riser and BOP concepts. These methods can be divided into downhole systems such as ECD reduction tools or surface systems such as Continuous Circulation Devices. However, they are not true MPD methods by definition since the bottom adjusting annular pressures dependent on the circulation through the drillstring. Because they are independent of all other categories or groups, these methods can be used as a supplement to the other MPD systems. These methods have therefore been included in the Table 1 for comparison.

The MPD methods evaluated for subsea TTRD are; 1. Pressurized riser systems with a near surface RCD and

surface chokes 2. Low pressure riser systems with a subsea RCD 3. Systems with a riser restriction device and subsea mud

pumping 4. System for controlling mud level in the riser (Low Riser

Return System -LRRS) or (Controlled Mud Cap - CMC) 5. Systems for riser gas lift 6. Secondary annulus circulation method 7. Dual gradient systems 8. Continuous Circulation device 9. Downhole ECD reduction device The methods that have been classified and evaluated are not

exhaustive. (A schematic diagram of the different methods is included in Figure 7 in appendix) There will be other methods or combinations of the methods listed above. Most of these methods are described and discussed in different papers included in the reference list 11-23.

Included in the evaluation (Table 1) is also how the different methods relate to the positioning system for the MODU. For example, if a pressurized riser with a surface RCD is used on a DP vessel, a station keeping event could trigger a serious well control situation such as a blow-out if the subsea BOP did not cut the drillstring and seal the wellbore. Moreover the riser content would also discharge to the sea. To illustrate this in Table 1, the cells under each category and groups have been color coded. In this example because of the potential risks, the use of a pressurized riser from a DP MODU has been color coded red due to the potential risks. Thus, it will probably not be the preferred method in many areas. An anchored MODU might be preferred, although using a pressurized riser might be questioned by some operators for the safety reason mentioned above. This method is

OTC 17798 5

therefore color coded yellow. The pressurized riser method will however be most suitable when used on jack-up rigs and is hence color coded green for this option.

Several important operational and well control issues that have been addressed earlier in this paper are included in the Table 1. A qualified judgment has been made as to how the different options of MPD relates to and handles these issues.

Example Cases

To show the importance of managing pressures during TTRD operations, two typical example subsea wells will be used for illustration. Two MPD methods for TTRD have been compared to a conventional pressure control method. A conventional system is shown in Figure 2.

Figure 2: Conventional pressure control w/ Subsea BOP

The Controlled Mud Cap (CMC) or Low Riser Return System (LRRS) concept is illustrated in Figure 3 (Method F shown in Table 1). It consists of a slim HP riser with an outlet to a subsea pump located in a separate conduit from the riser section. This pump is used to pump the return fluid from the well back to the drilling unit and thereby creating a lower interface between the mud and gas/air. The method allows for the fluid level (virtual flow line) in the drillpipe/riser annulus to be adjusted up or down in a controlled manner, thereby managing the annulus pressure profile and hence compensate for the ECD.

Figure 3: MPD Controlled Mud Cap (LRRS) & HP-riser w/ split BOP

The other method to be investigated is the use of a HP riser and a RCD with a surface choke on the annulus side as shown in Figure 4. Controlling the choke pressures will allow the operator to manage the annulus pressure profile and hence compensate for the ECD (Method A shown in Table 1). Normally pressure drop

through surface lines has to be accounted for when choosing mud weight and choke pressure, but for simplicity this issue is not considered in the case.

Figure 4: MPD HP riser / Surface BOP & w/RCD + Choke pressure

Case 1 A typical directional drilled subsea well in a severely depleted reservoir located in 380 m of water will be used in Case 1. The drillstring consists of 3 in. drillpipe, BHA, and 5-7/8 in. bit. The well is completed with a 7 in. production tubing (6.1 in. ID) tied into a 7 in. liner. The exit point for the drainhole sidetrack in the 7 in. liner is located at 2562 m TVD, 5500 mMD. From this point a horizontal well is drilled. The maximum pore pressure gradient in the depleted reservoir is 1.00 SG. Locally the pore pressure can be lower than 1.00 SG and the fracture pressure is estimated to be minimum 1.10 SG and maximum 1.20 SG in these intervals.

In conventional drilling, the mud weight is increased typically five points (0.05 SG) above the expected pore pressure to allow for a riser margin.

Using the CMC method there is no need for any margin as the mud column can easily be adjusted to compensate for swab or surge pressures during tripping. Because this method uses a heavier than conventional mud weight with a low level in the riser, a positive riser margin normally exists. The pressure inside the riser at seabed is substantially lower than the seawater on the outside, hence a riser disconnect would increase the bottom hole pressure if the subsea BOP did not seal. A positive riser margin of 9.6 bars is achieved using a mud weight of 1.05 SG.

For the pressurized riser system, a lighter than conventional mud weight is used with a choke pressure applied on surface. Using this method, it is not possible to achieve a riser margin or a trip margin. A riser disconnect would potentially cause an underbalance of 21.4 bar in the horizontal section with a mud weight of 0.904 SG. The choke pressure of 22.8 bars was chosen so that it balances out the friction pressure and the pressure contribution from the cuttings when pumping at 700 LPM. Also, the entire mud in the hole must be displaced with higher density mud to avoid stripping drillstring during trips.

One advantage of TTRD operations compared to coil tubing drilling is the ability to drill long openhole sections. However, high ECD will create substantial pressure difference between the toe of the openhole section compared to the pressure at shoe or casing/liner window. If the formation fracture pressure does not

Pore pressure Fracture pressure

Mud gradient Static

Mud gradient Dynamic

Mud pumpChoke manifold

Mud Tank

ECD

Subsea BOP

BOP + RCD

Sea water gradient

Mud gradient Dynamic

Mud gradient Static

Choke manifold Mud pump

Lift pump

Mud Tank

Fracture pressure

ECD

Subsea BOP

BOP+ RCD

Pressure

Mud pump

Choke- & kill lines Subsea BOP Mud line

Sea water gradient

Pore pressure

Mud gradient Static

Mud gradient Dynamic

Choke manifold Mud Tank

Fracture pressure

ECD

6 OTC 17798

increase with depth, as may be the case for horizontal wells, the length of the hole will be limited unless the ECD can be managed. It is recognized that the drilling length for all systems will be maximized when the pressure at the tubing exit point is kept constant close to balance with the pore pressure. As shown in Figure 5, the pressure along the section to be drilled increases due to pressure loss, and the drilling length is limited by the fracture gradient of the formation.

Figure 5: Example - Case 1

Table 2 illustrates potential openhole drilling lengths for the

three options, based on a mud flow rate of 700 LPM. Three different levels of fracture pressure have been used to allow for uncertainties. The results clearly show how MPD allows for a longer reach to be achieved as illustrated in Figure 5. Using conventional methods it is not possible to drill at all if the depleted reservoir has a mud window of only 0.1 SG, whereas a drainhole length of approximately 4300 m is possible, from a hydraulic point of view, by applying MPD technology.

Other factors determining the maximum drilling length is the torque required to rotate the drillpipe. The limitation is generally the MUT. In this example the 3 in. DP has a MUT of 16,530 Nm. Rotating the string in the main bore requires 8089 Nm based on a friction factor of 0.15. Depending on the formation and the lubricating properties of the mud, the friction factor in the drainhole determines the possible drilling length from a mechanic point of view. In this case, the MUT will be exceeded after drilling about 3100 m of open hole.

It can be extracted from Table 2 that if the pressure gradient is 1.20 SG the potential drilling length could be increased from 2244 m with conventional methods to 8877 m with the two selected MPD methods, from a hydraulic point of view. However, the MUT of the drill string will be exceeded earlier so the added possible drilling length is ultimately about 3100 m using a friction factor of 0.25 for the open hole.

It can be seen that the fracturing pressure is the limiting factor for the conventional method, while the MUT is the limiting factor using the MPD methods in this case, but because the MPD technologies can accept additional ECD, a larger drillpipe with higher MUT could be selected. This would also lower the pump pressure, hence allowing for longer sections to be drilled. The drillpipe can thus be optimized with respect to long reach, which might not be an option with conventional pressure control.

Case 2

A subsea well in 330 m water depth is completed with a 7 in. monobore production tubing. A kick-off point in the 7 in. liner is planned at approximately 4500 m MD and 2859 m TVD.

The area around the kickoff depth is depleted and weak (Pore pressure gradient 0.8 SG and fracture pressure gradient 1.61 SG). However, it is required to drill into an undepleted reservoir compartment at 5500 m MD with a fracture gradient of 1.8 SG and a pore pressure gradient of 1.55 SG as illustrated in Figure 6.

Figure 6: Example - Case 2

With conventional pressure control, a mud weight of 1.60 SG

is required to balance the pore pressure and provide kick margins. This mud weight is not high enough to provide riser margin (A heavier mud with a riser margin would have exceed the fracture pressure even without circulation). Even with a very thin mud, circulation will create enough frictional pressure to break the formation at the heel. As a result, when using the conventional method, it is not recommended to drill into this reservoir pocket in one operation. Potential alternatives would be to set additional liners or use solid expandable technology.

With MPD methods this section could be drilled without exceeding the mud/ECD window. For the RCD w/ choke concept, a mud weight of 1.50 SG is selected. In order to remain in over balance (6 bar), a choke pressure of 20 bar is used (static conditions). With a circulation rate of 700 LPM, the choke valve is completely open. In this case, the pressure will decrease slightly in the heel of the open hole section and there will be a point located in the horizontal section which will remain at the same pressure as under static condition. A riser margin will not be achievable with this low mud weight.

For the CMC concept, a mud weight of 1.64 is selected in order to maintain riser margin. The static mud column is located 150 m above the riser outlet. Reducing the mud column height above the pump outlet in the riser allows for sufficient reduction in bottom hole pressure. The equivalent mud density is kept within the mud weight window along the entire hole section. Table 3 in Appendix summarizes the results.

Conclusions Subsea TTRD has the potential of being an important contributor for improving the recovery from subsea developed fields. However, subsea TTRD requires close planning and considerations in order to achieve this goal. Particular circumstances due to downhole conditions, environmental and met ocean conditions, governmental regulations, well control and well integrity issues, etc, requires new technologies, methods and procedures to be developed. There is however, little doubt that MPD holds the key to success in order for TTRD to realize its fullest potential.

OTC 17798 7

Subsea TTRD with MPD technology performed from a floating rig faces several challenges not encountered on fixed platforms. These are particularly related to well control and well integrity issues. The drilling riser and BOP arrangement as well as station keeping methods also enter into the equation when evaluating the MPD methodologies that can be used.

Example cases indicate that the problem of high ECD combined with low mud window is a challenge in TTRD. MPD technologies can overcome or reduce this challenge. Further it has been shown that;

- MPD technology will in some cases be a pre-requisite for any drilling to be performed.

- MPD methods can allow for longer drainholes to be drilled.

- Where drillstring torsion strength or pumping pressure is the limiting factor, MPD may be used to increase the drillpipe size and hence drill longer sections.

- MPD allows depleted reservoirs to be drilled with less over pressure, and allows the bottom hole pressure to remain close to constant during drilling, i.e., the method allows drilling of reservoirs with little margin between pore pressure and fracture pressure.

- In general, some MPD technologies may allow for the producing interval to be drilled at balance or slightly underbalanced safely, which may reduce formation damage and hence increase the productivity and recovery from the reservoirs.

- Open HP riser MPD systems seems to have the greatest potential in subsea TTRD

References

1. Reynolds, H. and Watson, G.: String Design and Application in Through-Tubing Rotary Drilling (TTRD), SPE 81096 paper presented at the Latin American and Caribbean Petroleum Engineering Conference, held in Port-of-Spain, Trinidad, 27-30 Apr. 2003

2. Sanchez R.A., Azar J.J., Bassal A.A., Hart G., Martins A.L.: The Effect of Drillpipe Rotation on Hole Cleaning During Directional Well Drilling, SPE/IADC paper 37 626, presented at the SPE/IADC Drilling Conf., Amsterdam (4 6 March, 1997

3. Saasen A.: Sag of Weight Materials in Oil Based Drilling Fluids, IADC/SPE 77190, presented at the IADC/SPE Asian Pacific Drilling Technology, Jakarta, 9-11 September 2002

4. Bern P.A., van Oort E., Ebentoft H., Surdo C., Zamora M., Slater K.: Barite Sag. Measurement, Modelling, and Management, SPE 47784, presented at the IADC/SPE Asia Pacific Drilling Technology Conference, Jakarta, 1998

5. Dye W., Mullen G., Gusler W.: Drilling Processes: The Other Half of the Barite Sag Equation, SPE 80495, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 15-17 April, 2003

6. Fimreite, G., Asko, A., Massam, J., Taugbol, K., Omland, T.H., Svanes, K., Kroken, W., Andreassen, E. and Saasen, A.: Invert Emulsion Fluids for Drilling Through Narrow Hydraulic Windows, IADC/SPE paper 87128, presented at the IADC/SPE Drilling Conference, Dallas, 2-4 March 2004

7. Franks, T. and Marshall, D.S.: Novel Drilling Fluid for Through-Tubing Rotary Drilling, IADC/SPE paper 87127 presented at the IADC/SPE Drilling Conference, Dallas, 2-4 March 2004

8. Saasen A., Jordal O.H., Burkhead D., Berg P.C., Lklingholm G., Pedersen E.S., Turner J., Harris M.J.: Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,

IADC/SPE 74541, presented at the IADC/SPE Drilling Conference, Dallas, 26-28 February, 2002

9. Kleverlaan, M., Van Noort, R.N. and Jones, I.: Development of Swelling Elastomer Packers in Shell E&P, Presented at the SPE/IADC Drilling Conferance, Amsterdam, 23-25 February 2000

10. Queirs, J.G.R., Vidick, E. and Cochran, J.: Through Tubing Rotary Drilling and Its Associated Cementing Challenges: A North Sea Experience, SPE paper 83955 presented at Offshore Europe 2003, Aberdeen, 2-5 September 2003.

11. Fontana, P. and Sjoberg, G.: Reeled Pipe Technology for Deepwater Drilling Utilizing a Dual Gradient Mud System, paper SPE 59160, presented at the 2000 IADC/SPE Drilling Conference, New Orleans Louisiana, 23-25 February 2000.

12. Fossil, B. and Sangesland, S.: Managed Pressure Drilling for Subsea Applications; Well Control Challenges in Deep Waters, SPE/IADC paper 91633, presented at the 2004 SPE/IADC Underbalanced Technology Conference and Exhibition Houston, 11-12 October 2004

13. Hannegan D.: Pressure Drilling in Marine Environments - Case Studies, SPE/IADC 92600, 2005.

14. Hermann R.P., Shaughnessy J.M.: Two Methods for Achieving a Dual Gradient in Deepwater, SPE/IADC 67745, 2001.

15. Smith, K.L, Gault, A.D., Witt, D.E., Weddle, C.E.: SubSea Mudlift Drilling Joint Industry Project: Delivering Dual Gradient Drilling Technology to Industry, SPE 71357, 2001.

16. Bern, P.A, Armagost, W.K., Bansal, R.K.: Managed Pressure drilling with the ECD Reduction Tool, SPE 89737, 2004.

17. Schubert, J. J., Juvkam-Wold, H.C., Weddle, C.E.: Alexander, C.H., HAZOP of Well Control Procedures Assurance of the Safety of the SubSea Mudlift Drilling System, SPE/IADC 74482, 2002.

18. Eggemeyer, J.C., Akins, M.E., Brainard, R.R., Judge, R.A., Peterman, C.P., Scavone, L.J., Thethi, K.S: SubSea MudLift Drilling: Design and Implementation of a Dual Gradient Drilling System, SPE71359, 2001.

19. Scubert, J.J., Juvkam-Wold, H.C., Choe, J.: Well Control Procedures for Dual Gradient Drilling as Compared to Conventional Riser Drilling, SPS/IADC 79880, 2003.

20. Choe, J., Schubert, J.J, Juvkam-Wold, H.C.: Analyses and Procedures for Kick Detection in Subsea Mudlift Drilling, IADC/SPE 87114, 2004.

21. Sangesland, S., Fossli, B.: Low Riser Return and Mud-Lift System, Proc.At XIV Deep Offshore Tech.Conf., New Orleans, 2002.

22. Childers, M.:Surface BOP, Slim Rise or Conventional 21-Inch Riser - What is the Best Concept to Use, SPE/IADC 92762, 2005.

23. Brander, G., Magne, E., Newman, T., Taklo, T., Mitchell, C.: Drilling in Brazil in 2887m Water Depth using a Surface BOP system and DP vessel, IADC/SPE 87113, 2004.

Nomenclature

BHA Bottom Hole Assembly BOP Blow Out Preventer CAPEX Capital Expenditure CHP Closed High Pressure CLP Closed Low Pressure CMC Controlled Mud Cap CS Closed System CT Coiled Tubing CTD Coiled Tubing Drilling DP Drill Pipe

8 OTC 17798

DP Dynamic Positioning ECD Equivalent Circulation Density FPG Fracture Pressure Gradient GPM Gallons Per Minute HP High Pressure ID/OD Inner Diameter / Outer Diameter IS Independent Systems LP Low Pressure LPM Litre Per Minute LRRS Low Riser Return System MD Measured Depth MODU Mobile Offshore Drilling Unit MPD Manage Pressure Drilling MUT Make Up Torque MW Mud Weight OHP Open High Pressure OLP Open Low Pressure OS Open Systems PPG Pore Pressure Gradient PWD Pressure While Drilling RCD Rotating Control Device RCH Rotating Control Head RM Riser Margin SG Specific Gravity TTD Through Tubing Drilling TTRD Through Tubing Rotary Drilling TVD True Vertical Depth UB Under Balanced WARP Weight Agent Reduced Particles WL Wire Line

OTC 17798 9

Table1: Methods and options for MPD (TTRD in Subsea wells)

CLOSED SYSTEMS (CS) OPEN SYSTEMS (OS) INDEPENDENT SYSTEMS (IS) Riser & BOP

Arrangements HP RISER (CHP) LP RISER (CLP) HP RISER

(OHP) LP RISER (OLP) Surface (Note 1)

Downhole (Note 1)

Managed Pressure Drilling (MPD) Methods

(No.)

Surface RCH and

choke valve

(A)

Gas Lift in Riser

2)

(B)

Sec. Annulus

Circ. 3)

(C)

Subsea Mud Lift-

Dual Gradient

(D)

Subsea RCH and subsea choke

(E)

Controlled Mud Cap

(Low Riser

Return System)

(F)

Riser Pump w/ annular Restr.

(G)

Sec. Annulus

Circ. 3)

(H)

Surface Continuos Circulation

Device

(I)

Downhole ECD

Reduction Device

(J) DP

Anchored

MO

DU

Jack-up

Riser Margin

Trip Margin

Kick detection

Gas Handling

Swiftness of well control

Drill longer sections?

Total ECD management

Ability to perform TTRD UB operation

Feat

ures

Ability to perform UB

CT/WL operation

NA

NA

System use is either not possible, or NO time/cost/safety benefits can be readily realized, or Systematic Risks/Challenges cannot be overcome

with current technologies/procedures Combination of Feature/MODU option and MPD system is not recommended

System use is possible and time/cost/safety benefits can be realized. Systematic Risks/Challenges exist, but can be overcome with proper application or current technologies/procedures in some but not all cases

Combination of Feature/MODU option and MPD system possible in some but not all cases as long all concerns are addressed System use is readily applicable and time/cost/safety benefits can be realized. Minimal or no Systematic Risks/Challenges exist that are not

addressed by the System design and the application of proper procedures Combination of Feature/MODU option and MPD system is acceptable

Notes:

1) The independent systems may be used in combination with several of the other MPD concepts. 2) Injection point at Subsea BOP level or downhole through secondary annulus or parasitic string. 3) Injection point at Subsea BOP level through booster-line or through downhole secondary annulus.

10 OTC 17798

Table 2: Comparing maximum achievable drilling lengths while using LRRS, RCH & Choke or conventional method Case 1

Potential added horizontal drilling length from kick off point (700 LPM)

Case 1 Pore Pressure Gradient 1.00 CMC - LRRS

(MW 1.05 SG) RCD + Choke

(MW 0.904 SG + 22.8 bar choke pressure at static condition )

Conventional (1.05 SG)

Fracture (SG)

ECD Length

(m)

Torque** Length

(m)

Pump* pressure

(bar)

ECD Length

(m)

Torque** Length

(m)

Pump* pressure

(bar)

ECD*** Length

(m)

Torque Length

(m)

Pump* pressure

(bar) 1.10 4319 3174 364 4319 3043 372 - 3174 - 1.15 6598 3174 438 6598 3043 439 35 3174 261 1.20 8877 3174 511 8877 3043 506 2244 3174 332

* Conventional mud pumps are normally rated for 345 bars (5000 psi). MPD methods could cater for using 4 in. DP. ** Torque is the limiting factor for the drilling length with MPD. A 4 in. high strength DP would increase the drilling length *** With conventional pressure control ECD is the limiting factor

Table 3: Comparing annular pressures static and dynamic Case 2

Equivalent densities (700 LPM) Case 2 Pore Pressure Gradient 1.55

Dynamic ECD (SG) Method MW (SG)

Static Pressure window

(SG)

Window Fault Bottom Hole

Pump Pressure

@ Bottom

(bar) Conventional 1.60 1.600 1.669 1.688 1.698 325 CMC-LRRS 1.64 1.554 1.535 1.568 1.578 286

RCD + 20 bar Choke

pressure at static

condition

1.50 1.571 1.568 1.586 1.596 315

OTC 17798 11

Figure 7: Schematics of methods and options for MPD (TTRD in Subsea wells)

Conventional

Systems with a riser restriction device and

mud bypass pump

(G)

Low pressure riser systems with a

subsea RCD

(E)

Systems with a subsea mud

lift

(D)

System for riser gas lift

(B)

Secondary annulus

circulation method

w/ LP Riser

(C)

Controlled Mud Cap System for controlling mud level

in the riser (LRRS)

(F)

HP riser systems

with a near surface RCD and surface chokes

(A)

Secondary annulus

circulation method

w/ HP Riser

(H)

SS Tree

BOP Component

Rotating Control Device

LP Riser

HP Riser

Pump

Choke/Kill Lines Production Casing/Tubing

Drillstring and Bit

Riser Restriction Device

Relative Fluid Density Representations Low Density High Density Air Water Mud Mud (or gasified)

Not to Scale

Grey Components are

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