29_subseaTTRD

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Managed Pressure Drilling; Techniques and Options for Improving Efficiency,Operability and Well Safety in Subsea TTRD.Børre Fossli, Ocean Riser Systems AS, Sigbjørn Sangesland, Norwegian University of Science and Technology, OlveSunde Rasmussen, Norwegian University of Science and Technology, Pål Skalle, Norwegian University of Science andTechnology

Copyright 2006, Offshore Technology Conference

This paper was prepared for presentation at the 2006 Offshore Technology Conference held inHouston, Texas, U.S.A., 1–4 May 2006.

This paper was selected for presentation by an OTC Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, 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 ofthe Offshore Technology Conference, its officers, or members. Papers presented at OTC aresubject to publication review by Sponsor Society Committees of the Offshore TechnologyConference. Electronic reproduction, distribution, or storage of any part of this paper forcommercial purposes without the written consent of the Offshore Technology Conference isprohibited. 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 whereand by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX75083-3836, U.S.A., fax 01-972-952-9435.

Abst ractSubsea field developments are generally recognized as havinglower recovery factors than fields developed by fixedinstallations. To increase the recovery factor from subsea

developed reservoirs, new technologies that will reduce the costsof infill drilling and allow for more cost effective well

interventions, must be developed. One potential technology isThrough Tubing Rotary Drilling (TTRD). However, for theindustry 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 PressureDrilling (MPD) will be the key technologies needed to achievethe low cost, high performance drainage points.

This paper describes several MPD methods that can becombined 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 beused 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 anew subsea well.

IntroductionSome of the reasons behind the lower recovery factors from

subsea developed reservoirs are:1. Reduced accessibility to the well for interventions,

repair and workover purposes2. Lack of cost efficient well intervention tools and

methods3. High cost of new wells for infill drilling purpose4. 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 reservoirdrainage. The ability to access bypassed oil and gas reserves inmature fields has been gaining more and more attention in recentyears. Mature fields have huge reserves that lie in multipleisolated pockets that would be uneconomic to produce using newwells. This may particularly be the case in subsea fields indeeper waters where the soaring dayrates for mobile offshore

drilling units (MODU) will make the minimum economicalreserve requirements hard to find.

Through Tubing Drilling (TTD) is a method that eliminatesthe need for expensive conventional (new) wells or sidetracks.Avoiding drilling the “transport distance” down to the reservoirreduces the costs significantly. In addition, the re-use of the in-

place completion equipment saves time for removing the oldcompletion, time for running the new completion and CAPEX ofthe new completion.

Coiled Tubing Drilling (CTD) has been the preferred anddominating 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 attractiveoption. The main advantage of using TTRD is the ability torotate the drillpipe which improves hole cleaning, drillingmechanics, and ultimately increases the reach capability. Thusan obvious potential application of TTRD is infill drilling toaccess new reserves in subsea wells.

TTRD in subsea fields faces several challenges. Many areassociated with the narrow annulus between the production boreand the drillpipe, and to the variable formation pressures andlower fracture strengths in depleted formations. Another of the

industry’s concerns of TTRD is the potential for wear/damage ofthe tubing and downhole safety equipment.

Subsea TTRD operations are at the present in its infancy.Subsea TTRD has been performed in horizontal 7 in. monoborecompletions on the Norwegian continental shelf by Norsk Hydroon the Njord field and by Statoil on the Norne field. Theseoperations have been conducted using a conventional drillingriser 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 thecompletion string and in the subsea christmas tree. However,this conventional riser and BOP set-up will significantly increasethe challenges of incorporating MPD technologies with the

TTRD concept. This paper will describe some of the options


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available and the pros and cons for these concepts of MPD insubsea TTRD.

Subsea TTRD ChallengesEquivalent Circulating Densities

A major challenge in both on- and offshore TTRD operations isthe problem related to Equivalent Circulation Density (ECD).

High annular pressure losses, resulting in high ECDs can lead tolost circulation and differential sticking. The small annular space

can also cause high surge pressures or increase the risk ofswabbing in a kick when tripping (localized ECD effect). Theoptimum safe trip speed must be predicted from surge and swabcalculations. Pipe protectors might be prohibited because theylead to an even higher ECD. However, selecting smallerdrillpipe to reduce ECD effects is not necessarily an option as

only slight changes of drillpipe ID will significantly change thestandpipe pressure, which in turn may limit circulation rates

1. At

desired circulation rates, exceeding the mud pumps pressurerating might occur in long deviated wells. For these reasonsTTRD 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 inconventional drilling (> 20 %). This will influence rheology andconsequently both hydrostatic and dynamic pressures, furtheraggravating the situation.

Also, a MODU is also exposed to heave. Today, most rigshave 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 issuspended from the rotary table and the string will then followthe rigs movement. Hence, pressure changes caused by pipemovements can result in alternating surge and swab effects that

results in fluctuating bottomhole pressures.

Hole CleaningHole cleaning in TTRD wells is a balance between competingtechnical and operational needs. Hole cleaning can be achievedthrough mechanical methods (pipe rotation) or efficienthydraulics. 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 becomestuck or packed off inside the completion. This can lead toincreased bottomhole pressure, mud losses and formationdamage, and can ultimately lead to the loss of the well.

In today’s 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 undesirablefluctuations in mud weights3. This can cause problems such aslost 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 circulatingrates and/or mechanical aids are required. A BHA oscillatorcould be helpful in increasing the amount of cuttings beddisturbance1. 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 agitatoris 26-35 bars, which may be prohibitive in some operations.

Drilling Fluids SelectionThe rheology of the drilling fluid must be designed carefully forTTRD operations. There are two conflicting design requirements:

• Low ECD (achieved through low viscosity)

• Low solids settling tendency (achieved through highviscosity)

Two major drilling fluid service companies have solved theserequirements differently, but the results are the same; by

applying weight material with small particle size both rheologyand sagging tendency have been improved compared withconventional 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 application8.

Hole StabilityIn depleted reservoirs, pore pressures may have droppedsignificantly causing the overlying shale to become unstable.Also, in these reservoirs, the fracture pressure will be reducedwhile the pore pressure remains virgin in overlaying andinterbeded shale and sealed sand pockets. The mud weight must

be kept as low as possible to avoid fracturing caused by highECD, yet high enough to maintain borehole stability. Figure 1shows typical pressures in a depleted North Sea reservoir.

Figure1. Typical predicted pore and fracture pressures in ahorizon tal 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 thereforeimportant to note that:

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

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

A one m3 influx would, because of the small annular capacity,evacuate 300–500 m of hole, which in many cases is more thanthe entire openhole. Kick detection and accurate kick volumemeasurements are therefore paramount.

The critical difference between conventional well control andslimhole 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

Measured Litho logy Pore and FractureDepth (m) equivalent mud density (SG)

0.8 1.55 1.61 1.80 1.90

4500

5400

5500 -

Sand

Shale

Sand (Pristinereservoir)

the selected slow pump circulation rate, the annular pressure loss


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is significantly reduced or negligible. The annular pressure lossin slimhole drilling, even at slower kill rates, is considerablyhigher than in conventional wells.

Well Control (Subsea and Surface Considerations)

eral issues

a small influx though conventional pit gainmo

ewil

Cementing Operationsof slim liners face two important

r centralization can reduce these effects, but centralizersel

The Role of Managed Pressure Drillingsed above when

lection

ns

l isolationAll anaged with the proper

ser

pment issues

Subs a BOP Package and the Drilling Riser

aluating the BOP

riser

or concentric risersIn b rmine what

uire a fullsub

ressure riser packages will carry a surfaceBO

able economic benefits fromutil

r thiswil

hallenge in TTRD operations is that wirelineope

ell Control and Well Integrity Issuesarly important when

When planning TTRD in subsea wells, there are sevthat must be evaluated regarding the marine riser system and

surface equipment when considering well control aspects. If aconventional, low-pressure 21 in. marine drilling riser is used,

riser boosting will be needed to transport cuttings because of thelow circulating rates used. This might hinder the detection of asmall influx.

Detectingnitoring 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 theannular volume below mudline. For example, with 3½ in.drillpipe in 1000 m water depth, the annular mud volume in a 21in. riser is more than 3 times the annular volume in a wellcompleted with 4000 m of 7 in. tubing and 500 m of openhole.

The use of conventional LP risers with a subsea BOP packagl create higher chokeline frictions than HP risers with surface

BOPs. In environments with tight tolerances, a surface BOP package might be preferred.

Cementing operationschallenges: 1) high ECDs, particularly at the end of the

displacement period, and 2) poor mud displacement efficiencythat can cause insufficient circumferential cement coverage of theliner.

Lineection is limited. Bow centralizers are not used because of

excessive running friction forces, thus rigid centralizers are oftenselected

10. The cement slurry must be pumped in laminar flow

due to high ECD hence preventing effective displacement of mudand 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 otherforms of external liner/casing packers.

Seven challenges have been briefly discusapplying TTRD in subsea wells.

1. High ECDs2. Hole cleaning3. Drilling fluid se4. Hole stability issues5. Pore pressure variatio6. Well control issues7. Cementing and zonaof the above issues can be solved or m

application of Managed Pressure Drilling (MPD) methods andequipment. MPD can be defined as the ability to drill in

overbalance with a near constant bottomhole pressureindependent of the circulation rate used. Therefore, MPD will beeven 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 treesand 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 ri2. Well control and well integrity issues3. MODU specifications and surface equi

e

Several issues need to be considered when evand riser package if MPD technology is to be used. There will be

three main options;1. Low pressure2. High pressure riser3. Variations of the aboveroad terms, the riser and BOP package will dete

methods of MPD technology that will be applicable.

In general low pressure riser systems will req sea BOP package with high-pressure (HP) kill/choke lines

running back to the rig. By choosing this setup, the MPDtechnologies available will be more limited. Although a surfaceRotating Control Device (RCD) might be used in conjunction

with a LP riser in certain situations, the potential high pressuresthat might be encountered in many areas will generally require

the RCD to be placed subsea. Chokes might be placed eithersubsea or at surface.

In general, high pP 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 consider izing a slim riser and BOP package. When slimming down

the riser and BOP package, the ability to handle high pressuresalso becomes evident. Because most subsea completions have an

outside diameter of 7 in. or less, the BOP and riser could beslimmed down to 7 1/16 in. – 7 3/8 in. ID. A smaller and lighterriser package would also allow for the use of a less expensiveMODU in deeper waters. In addition, the use of a small HP riserwould allow for a rapid change from performing conventionaldrilling operations to underbalanced well interventions, usingwireline and/or coiled tubing (CT) equipment.

A concentric riser system is also conceivable. Howevel be somewhat more complex to operate and manage with

MPD operations.One particular crations (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 CToperations to drilling with jointed pipe. Preferably the same riserand 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.

WWell control issues become particul performing MPD operations from a floating vessel

12. Kick

detection and control of influx becomes even more challenging in

TTRD operations. Hence, well integrity issues are importantwhen choosing both the riser and BOP system and the primary


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MPD technology to be used. In this evaluation, the type of positioning principle of the MODU and the climatic, met oceancondition and water depth enter into this equation.

Performing MPD operation with a riser margin (RM) isdes

ppingthe

of

suf

the reservoir has been addressedear

e capability of theMP

MODU Specifications and Surface Equipment Issuesg might

ositioned (DP) MODU willnor

MP Classification and Evaluation of Options and Methods

been suggested as illustrated in Table 1. There are 3 maincategories;

pendent systems (IS)

Tabl or the different systems and howthe to the different riser and BOPopti d how they may impact

th surface/or split

P marine riser system and subsea

Althoug methods might be used within both mainsyst

fall nat ither the HP or LP riser category. One

ncepts. These methods can be divided intodow

iser

5. r riser gas lift

7. vice

ed and evaluated are not

exh t e different methods isincluded in Figure 7 in appendix) There will be other methods or

com

rized riser with a surface RCD is used on a

DP

irable, but not always possible. However, some MPDtechnologies will make this possible. Normally, a conventionalMPD system with a pressurized HP riser and surface chokes, a

riser margin is not obtainable. In order to maintain a riser marginin 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 tri drillstring without jeopardizing well integrity, swabbing or

loosing returns due to fracturing. It is not uncommon to spend upto 30 % of the total time on trips in TTRD operations. SeveralMPD 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 severalreasons: 1) Significant incremental time, 2) risk of losing wellintegrity (less barriers) and 3) extra wear on the on the RCD.

Several methods of MPD will allow for fast introduction

ficient trip margin without having to circulate the entireannulus volume to a heavier fluid (and subsequent need to

circulate out the heavier fluid prior to resuming drilling). Someof these methods will also allow for faster tripping than withconventional pressure control.

Kick or flow detection fromlier. There are significant differences on how this can be

achieved with the different MPD methods.

How influxes are handled depends on thD system to handle annular pressures losses and the ability of

the MODU equipment to handle various volumes of gas. Insome cases of large inflow volumes, which may occur duringunderbalance drilling (UBD) operations, bullheading might be

the only option. Although bullheading formation influx is anoption, it is usually found to be detrimental to subsequentreservoir productivity, thus should be avoided.

In severe cases of flow due to underbalance, bull headin be the only alternative. This will depend upon the MPD methods

ability to control annular pressure in the well and the MODUsability to handle large amount of gas and/or whether the rig has a

4 phase separation package installed.For TTRD operations, Dynamic Pmally 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 withusing DP MODU. TTRD operations will normally take less time

than drilling and completing a conventional subsea well, hencethe mean time between rig moves will decline. Several days withanchor handling can easily neutralize the effect of lower dayrateswith an anchored MODU compared to a DP MODU. The

downside of DP is the higher requirements on well integrity andin relation to riser/BOP equipment, to compensate for accidental

drive offs or drift offs.

DAn approach to classification for MPD for subsea TTRD has

1. Closed systems (CS)2. Open systems (OS)3. Indee 1 shows the variations f different methods relate

ons, rig positioning methods, animportant well control and operational issues.

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

1. Systems requiring a HP riser system wiBOP’s (HP)

2. Systems utilizing a LBOP’s (LP)h some MPD

em categories (CS or OS) and both riser groups, they seem to

urally into eexception here is the Controlled Mud Cap (CMC) system whichincludes a RCD, but the system will always perform as an opensystem even though it will generally operate with the RCD inclosed position.

The third category (IS) includes systems that are independentof whether it is used in open or closed systems and independent

of riser and BOP conhole systems such as ECD reduction tools or surface

systems such as Continuous Circulation Devices. However, theyare not true MPD methods by definition since the bottomadjusting annular pressures dependent on the circulation throughthe drillstring. Because they are independent of all other

categories or groups, these methods can be used as a supplementto the other MPD systems. These methods have therefore beenincluded 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 chokes2. Low pressure riser systems with a subsea RCD3. Systems with a riser restriction device and subsea mud

pumping4. System for controlling mud level in the riser (Low R

Return System -LRRS) or (Controlled Mud Cap - CMC)Systems fo

6. Secondary annulus circulation methodDual gradient systems

8. Continuous Circulation de9. Downhole ECD reduction device

The methods that have been classifi

aus ive. (A schematic diagram of th

binations of the methods listed above. Most of these methodsare described and discussed in different papers included in thereference list

11-23.

Included in the evaluation (Table 1) is also how the different

methods relate to the positioning system for the MODU. Forexample, if a pressu

vessel, a station keeping event could trigger a serious wellcontrol situation such as a blow-out if the subsea BOP did not cutthe drillstring and seal the wellbore. Moreover the riser contentwould also discharge to the sea. To illustrate this in Table 1, the

cells under each category and groups have been color coded. Inthis example because of the potential risks, the use of a


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pressurized riser from a DP MODU has been color coded red dueto the potential risks. Thus, it will probably not be the preferredmethod in many areas. An anchored MODU might be preferred,

although using a pressurized riser might be questioned by someoperators for the safety reason mentioned above. This method istherefore color coded yellow. The pressurized riser method willhowever 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 theTable 1. A qualified judgment has been made as to how thedif

RDfor

PD methods for TTRD have been compared

to

w/ Subsea BO

The Controlled Mud Cap C) or Low ReturnSystem (LRRS) concept is illustrated in Fig (Method F

outlet ta s

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

and hoke the annulus side as shown inFigure 4. Controlling th essures will allow the operator

to manage the annulus pressure profile and hence compensate forthe EC ethod A shown in Tabl y pressure dropthrough ace lines has to be accounted for when choosing mudweight and choke pressure, but for simplicity this issue is not

considered in t .

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

CaseA typ ea well in a severely depleted

reservoir located in 380 m o be used in Case 1. Thedrillstrin ts of 3½ in. drillpipe, B 5-7/8 in. bit.

The well is completed with a 7 in. produ ing (6.1 in. ID)tied into a 7 in. liner. The exit point for the d idetrack inthe 7 in. liner is located at 2562 m TVD, 550 is point a h tal 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 isestimated to be minimum 1.10 SG and maximum 1.20 nthese intervals.

In conventional drilling, th ight is increased typicallyow

g the CMC method there is no need for any margin as the

The other method to be investigated is the use of a HP risera RC

ferent options of MPD relates to and handles these issues.

Example CasesTo show the importance of managing pressures during TT

ope ations, two typical example subsea wells will be used r illustration. Two M

a conventional pressure control method. A conventionalsystem is shown in Figure 2.

Figure 2: Conventional pressure control

(CMP

Riser ure 3

shown in Table 1). It consists of a slim HP riser with an oubsea pump located in a separate conduit from the riser

section. This pump is used to pump the return fluid from thewell back to the drilling unit and thereby creating a lowerinterface between the mud and gas/air. The method allows forthe fluid level (virtual flow line) in the drillpipe/riser annulus to be adjusted up or down in a controlled manner, thereby managingthe annulus pressure profile and hence compensate for the ECD.

D with a surface c one choke pr

D (M e 1). Normall surf

he case

1ical directional drilled subs

f water willg consis HA, and

tubctionrainho e sl0 mMD. From th

orizon

SG i

e mud wefive points (0.05 SG) above the expected pore pressure to all

for a riser margin.Usin

mud column can easily be adjusted to compensate for swab orsurge pressures during tripping. Because this method uses aheavier than conventional mud weight with a low level in theriser, a positive riser margin normally exists. The pressure insidethe 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 marginof 9.6 bars is achieved using a mud weight of 1.05 SG.

For the pressurized riser system, a lighter than conventionalmud 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 anunderbalance of 21.4 bar in the horizontal section with a mudweight of 0.904 SG. The choke pressure of 22.8 bars was chosenso that it balances out the friction pressure and the pressurecontribution 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.

Pore pressure

Fracture pressure

Mud gradient

Static

Mud puChoke manifold

Mud gradient

Dynamic

mpMud Tank

ECD

BOP + RCD

Subsea BOP

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

Mud line

Sea water

gradient

Pore pressure

Subsea BOP

Mu

Sta

d gradient

tic Mud gradient

D namic

Choke manifold Mud Tank

Fracture pressure

ECD


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One advantage of TTRD operations compared to coil tubingdrilling 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 orcasing/liner window. If the formation fracture pressure does notincrease with depth, as may be the case for horizontal wells, thelength of the hole will be limited unless the ECD can be

managed. It is recognized that the drilling length for all systemswill be maximized when the pressure at the tubing exit point is

kept constant close to balance with the pore pressure. As shownin Figure 5, the pressure along the section to be drilled increasesdue to pressure loss, and the drilling length is limited by thefracture gradient of the formation.

Figure 5: Example - Case 1

Table 2 illustrates potential openhole drilling lengths for thethree options, based on a mud flow rate of 700 LPM. Three

different levels of fracture pressure have been used to allow forunc rtainties. The results clearly show how MPD allows for alonger reach to be achieved as illustrated in Figure 5. Usingconventional methods it is not possible to drill at all if thedepleted reservoir has a mud window of only 0.1 SG, whereas a

drainhole length of approximately 4300 m is possible, from ahydraulic 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 generallythe MUT. In this example the 3½ in. DP has a MUT of 16,530 Nm. Rotating the string in the main bore requires 8089 Nm

of 0.15. Depending on the formation

and the lubricating properties of the mud, the friction factor in thedrai

3100 musi

ressure control.

Ca

pleted reservoir

com

e

based on a friction factor

nhole determines the possible drilling length from a

mechanic point of view. In this case, the MUT will be exceededafter drilling about 3100 m of open hole.

It can be extracted from Table 2 that if the pressure gradientis 1.20 SG the potential drilling length could be increased from

2244 m with conventional methods to 8877 m with the twoselected MPD methods, from a hydraulic point of view.

However, the MUT of the drill string will be exceeded earlier sothe added possible drilling length is ultimately about

ng 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 limitingfactor using the MPD methods in this case, but because the MPD

technologies can accept additional ECD, a larger drillpipe withhigher MUT could be selected. This would also lower the pump pressure, hence allowing for longer sections to be drilled. Thedrillpipe can thus be optimized with respect to long reach, whichmight not be an option with conventional p

se 2A 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 unde

partment at 5500 m MD with a fracture gradient of 1.8 SGand a pore pressure gradient of 1.55 SG as illustrated in Figure 6.

Figure 6: Exampl e - Case 2

With conventional pressure control, a mud weight of 1.60 SGis required to balance the pore pressure and provide kickmargins. This mud weight is not high enough to provide riser

margin (A heavier mud with a riser margin would have exceedthe 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 theconventional method, it is not recommended to drill into thisreservoir 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/ chokeconcept, a mud weight of 1.50 SG is selected. In order to remainin over balance (6 bar), a choke pressure of 20 bar is used (static

rate of 700 LPM, the choke valveis completely open. In this case, the pressure will decreaseslig

.Tab

hnologies, methods and

conditions). With a circulation

htly in the heel of the open hole section and there will be a

point located in the horizontal section which will remain at thesame 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 inorder to maintain riser margin. The static mud column is located

150 m above the riser outlet. Reducing the mud column heightabove the pump outlet in the riser allows for sufficient reductionin bottom hole pressure. The equivalent mud density is keptwithin the mud weight window along the entire hole section

le 3 in Appendix summarizes the results.

ConclusionsSubsea TTRD has the potential of being an important contributorfor improving the recovery from subsea developed fields.However, subsea TTRD requires close planning andconsiderations in order to achieve this goal. Particularcircumstances due to downhole conditions, environmental andmet ocean conditions, governmental regulations, well control and

well integrity issues, etc, requires new tec


7/11

OTC 17798 7

pro

rangement as well

as tion keeping methods also enter into the equation whenPD methodologies that can be used.

iting factor, MPD may be used to increase the

ence increase the productivity and

- s to have the greatest

Referen1. R

T 1096 paper p

EA

2. S“ gD ed

a 73. S ing

F sianP 02

4. B ora M.,

SM

P ference, Jakarta, 1998en G., Gusler W.: “Drilling Processes: The Other

6.

7.

8. olm

11. Technology for

12. d Sangesland, S.: “Managed Pressure Drilling for

13. Environments - Case

14.

15. K.L, Gault, A.D., Witt, D.E., Weddle, C.E.: ”SubSea

16. 9737, 2004.

19. H.C., Choe, J.: “Well Control

ADC 79880, 2003.

lling”,

21. s,

22. Inch

23. zil in 2887m Water Depth using a Surface BOP

Nomen

BHA

BO

CA

CHP

CLP Closed Pressure

cedures to be developed. There is however, little doubt thatMPD holds the key to success in order for TTRD to realize itsfullest potential.

Subsea TTRD with MPD technology performed from afloating rig faces several challenges not encountered on fixed platforms. These are particularly related to well control and wellintegrity issues. The drilling riser and BOP ar

staevaluating the M

Example cases indicate that the problem of high ECDcombined with low mud window is a challenge in TTRD. MPDtechnologies can overcome or reduce this challenge. Further ithas been shown that;

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

- MPD methods can allow for longer drainholes to bedrilled.

- Where drillstring torsion strength or pumping pressureis the limdrillpipe size and hence drill longer sections.

- MPD allows depleted reservoirs to be drilled with lessover pressure, and allows the bottom hole pressure toremain close to constant during drilling, i.e., the methodallows 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 slightlyunderbalanced safely, which may reduce formationdamage and hrecovery from the reservoirs.

Open HP riser MPD systems seem potential in subsea TTRD

ceseynolds, H. and Watson, G.: “String Design and Application in

hrough-Tubing Rotary Drilling (TTRD)”, SPE 8resented at the Latin American and Caribbean Petroleum

ngineering Conference, held in Port-of-Spain, Trinidad, 27-30 pr. 2003

anchez R.A., Azar J.J., Bassal A.A., Hart G., Martins A.L.:The Effect of Drillpipe Rotation on Hole Cleaning Durinirectional Well Drilling”, SPE/IADC paper 37 626, present

t the SPE/IADC Drilling Conf., Amsterdam (4 – 6 March, 199aasen A.: “Sag of Weight Materials in Oil Based Drill

luids”, IADC/SPE 77190, presented at the IADC/SPE Aacific Drilling Technology, Jakarta, 9-11 September 20ern P.A., van Oort E., Ebentoft H., Surdo C., Zam

later K.: “Barite Sag. Measurement, Modelling, andanagement”, SPE 47784, presented at the IADC/SPE Asia

acific Drilling Technology Con5. Dye W., Mull

Half of the Barite Sag Equation”, SPE 80495, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition,

Jakarta, 15-17 April, 2003Fimreite, G., Asko, A., Massam, J., Taugbol, K., Omland, T.H.,

Svanes, K., Kroken, W., Andreassen, E. and Saasen, A.: ” InvertEmulsion Fluids for Drilling Through Narrow HydraulicWindows”, IADC/SPE paper 87128, presented at the IADC/SPE

Drilling Conference, Dallas, 2-4 March 2004Franks, 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, 2-4March 2004

Saasen A., Jordal O.H., Burkhead D., Berg P.C., LøklinghG., 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, 20029. 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 February2000

10. Queirós, J.G.R., Vidick, E. and Cochran, J.: “Through TubingRotary Drilling and Its Associated Cementing Challenges: A North Sea Experience”, SPE paper 83955 presented at Offshore

Europe 2003, Aberdeen, 2-5 September 2003.Fontana, P. and Sjoberg, G.: “Reeled Pipe

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.Fossil, B. an

Subsea Applications; Well Control Challenges in Deep Waters”,SPE/IADC paper 91633, presented at the 2004 SPE/IADC

Underbalanced Technology Conference and ExhibitionHouston, 11-12 October 2004Hannegan D.: “Pressure Drilling in Marine

Studies”, SPE/IADC 92600, 2005.Hermann R.P., Shaughnessy J.M.: ”Two Methods for Achieving

a Dual Gradient in Deepwater”, SPE/IADC 67745, 2001.Smith,

Mudlift Drilling Joint Industry Project: Delivering DualGradient Drilling Technology to Industry”, SPE 71357, 2001.

Bern, P.A, Armagost, W.K., Bansal, R.K.: “Managed Pressuredrilling with the ECD Reduction Tool”, SPE 8

17. Schubert, J. J., Juvkam-Wold, H.C., Weddle, C.E.: Alexander,C.H., ”HAZOP of Well Control Procedures Assurance of theSafety 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 MudLiftDrilling: Design and Implementation of a Dual GradientDrilling System”, SPE71359, 2001.

Scubert, J.J., Juvkam-Wold,Procedures for Dual Gradient Drilling as Compared to

Conventional Riser Drilling”, SPS/I20. Choe, J., Schubert, J.J, Juvkam-Wold, H.C.: “Analyses and

Procedures for Kick Detection in Subsea Mudlift DriIADC/SPE 87114, 2004.

Sangesland, S., Fossli, B.: “Low Riser Return and Mud-LiftSystem”, Proc.At XIV Deep Offshore Tech.Conf., New Orlean

2002.Childers, M.:”Surface BOP, Slim Rise or Conventional 21-

Riser - What is the Best Concept to Use”, SPE/IADC 92762,2005.

Brander, G., Magne, E., Newman, T., Taklo, T., Mitchell, C.:”Drilling in Brasystem and DP vessel”, IADC/SPE 87113, 2004.

clature

Bottom Hole Assembly

P Blow Out Preventer

PEX Capital Expenditure

Closed High Pressure

Low


8/11

8 OTC 17798

CM

CS

CT Co

CT

DP

DP

EC

FPGPM Gallons Per Minute

HP High Pressure

Inner Diameter / Outer Diameter

IS Independent Systems

tem

U ng Unit

lling

e

ssure

ice

l Head

g Drilling

otary Drilling

s

C Controlled Mud Cap

Closed System

iled Tubing

D Coiled Tubing Drilling

Drill Pipe

Dynamic Positioning

D Equivalent Circulation Density

Fracture Pressure GradientG

ID/OD

LP Low Pressure

LPM Litre Per Minute

LRRS Low Riser Return Sys

MD Measured Depth

MOD Mobile Offshore Drilli

MPD Manage Pressure Dri

MUT Make Up Torqu

MW Mud Weight

OHP Open High PressureOLP Open Low Pre

OS Open Systems

PPG Pore Pressure Gradient

PWD Pressure While Drilling

RCD Rotating Control Dev

RCH Rotating Contro

RM Riser Margin

SG Specific Gravity

TTD Through Tubin

TTRD Through Tubing R

TVD True Vertical Depth

UB Under Balanced

WARP Weight Agent Reduced Particle

WL Wire Line


9/11

OTC 17798 9

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

CLOSED SYSTEMS (CS) OPEN SYSTEMS (OS)INDEPENDENTSYSTEMS (IS)

Riser & BOP Arrangements

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

(OHP)LP RISER (OLP)

Surface(Note 1)

Downhole(Note 1)

ManagedPressure Drilling(MPD) Methods

(No.)

SurfaceRCH and

chokevalve

(A)

Gas Liftin Riser

2)

(B)

Sec. Annulus

Circ.3)

(C)

SubseaMud Lift-

DualGradient

(D)

SubseaRCH andsubseachoke

(E)

ControlledMud Cap

(LowRiser

ReturnSystem)

(F)

RiserPump w/annularRestr.

(G)

Sec. Annulus

Circ.3)

(H)

SurfaceContinuosCirculation

Device

(I)

DownholeECD

ReductionDevice

(J)

DP

Anchored

M O D U

Jack-up

Riser Margin

Trip Margin

Kick detection

GasHandling

Swiftness ofwell control

Drill longersections?

Total ECDmanagement

Ability toperform TTRDUB operation

F e a t u r e s

Ability toperform UB

CT/WLoperation

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 properapplication 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 notaddressed 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.


10/11

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 po int (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 condit ion )

Conventional(1.05 SG)

Fracture(SG)

ECDLength

(m)

Torque**Length

(m)

Pump*pressure

(bar)

ECDLength

(m)

Torque**Length

(m)

Pump*pressure

(bar)

ECD***Length

(m)

TorqueLength

(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 densit ies (700 LPM)Case 2 – Pore Pressure Gradient 1.55

Dynamic ECD (SG)Method MW(SG)

StaticPressurewindow

(SG)

Window Fault BottomHole

PumpPressure

@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 barChoke

pressure atstatic

condition

1.50 1.571 1.568 1.586 1.596 315


11/11

OTC 17798 11

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

Conventional

Systems with a riserrestriction device and

mud bypass pump

(G)

Low pressure risersystems with a

subsea RCD

(E)

Systems with asubsea mud

lift

(D)

System for riser

gas lift

(B)

Secondaryannulus

circulationmethod

w/ LP Riser

(C)

Controlled Mud CapSystem forcontrolling

mud levelin the riser (LRRS)

(F)

HP risersystems

with a nearsurface RCD and

surface chokes

(A)

Secondaryannulus

circulationmethod

w/ HP Riser

(H)

Pump Relative Fluid DensitySS TreeRepresentations

BOP Component Choke/Kill Lines Low Density High Density

Air Water Mud MudProduction Casing/TubingRotating Control Device (or gasified)

Drillstring and BitLP Riser

Riser Restriction Device Not to ScaleHP Riser

Grey Components are

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29_subseaTTRD