a process used in evaluation of managed-pressure drilling candidates and probabilistic cost-benefit...

8/13/2019 A Process Used in Evaluation of Managed-Pressure Drilling Candidates and Probabilistic Cost-Benefit Analysis

1/13

Copyright 2006, Offshore Technology Conference

This paper was prepared for presentation at the 2006 Offshore Technology Conference held inHouston, Texas, U.S.A., 14 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 tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Offshore Technology Conference, its officers, or members. Papers presented atOTC are subject to publication review by Sponsor Society Committees of the OffshoreTechnology Conference. Electronic reproduction, distribution, or storage of any part of thispaper for commercial purposes without the written consent of the Offshore TechnologyConference is prohibited. Permission to reproduce in print is restricted to an abstract of notmore than 300 words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment 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.

AbstractThe paper will discuss the processes, methods, factors andparameters utilized to evaluate potential candidates using adefined process and simulation methods for the application ofManaged-Pressure Drilling (MPD) technology in wellconstruction operations. The use of MPD technologies caninfluence many wellbore pressure-related drilling challenges,including lost circulation, kicks, wellbore ballooning, tightpore pressure (PP)/fracture pressure (FP) margins, close

tolerance casing programs, wellbore stability problems,shallow water/gas flows, slow ROP, etc. These techniquesmay also enable future well programs that are currentlythought to be conventionally undesignable with singlegradient mud systems.

Potential drilling efficiency benefits may include improvedHSE, drilling with less Non-Productive Time (NPT) or troubletime, improved wellbore stability, reduced mud losses,improved ROP performance and extension of casingseats/fewer casing strings

A process has been applied to evaluate the economics ofcandidate wells for the use of MPD. This evaluation hasincluded the use of a probabilistic Monte Carlo simulation ofthe potential results of the use of MPD and takes into accounttime dependent, cost dependent and performance relatedfactors. The use of other technologies such as wellborestrengthening or wellbore stability technologies in conjunctionwith MPD can also be modeled to look at the overall benefitof use of all applied technologies within the well constructionprocess.

The significance of MPD, in the face of increasing wellconstruction costs around the world, is that these techniquesmay allow step-change reductions in drilling duration and

associated costs. More importantly, MPD may allow thedrilling of wells that cannot be drilled with conventionadrilling processes. MPD technologies may also allowimproved well performance through a more efficientcompletion size and an increase in recoverable reserves.

Managed-Pressure Drilling (MPD)

Managed-Pressure Drilling (MPD) is an advanced form ofprimary well control that many times employs a closed andpressurizable drilling fluid system that allows potentiallygreater and more precise control of the annular wellborepressure profiles than mud weight and pump rate adjustmentsalone. The primary objective of MPD is to optimize drillingprocesses by decreasing non-productive time (NPT) andmitigating drilling hazards in the well construction process.

1

The IADC Managed Pressure Drilling and UnderbalancedOperations Committee defines Managed-Pressure Drilling asMPD is an adaptive drilling process used to more preciselycontrol the annular pressure profile throughout the wellbore

The objectives are to ascertain the downhole pressureenvironment limits and to manage the annular hydraulicpressure profile accordingly. 2

MPD processes employ a collection of tools and techniqueswhich may mitigate the risks and costs associated with drillingwells that have narrow downhole environmental limits byproactively managing the annular hydraulic pressure profileThe techniques used in MPD may include control ofbackpressure, fluid density, fluid rheology, annular fluid levelcirculating friction, and hole geometry, or any combinationsthereof. MPD may allow faster corrective action to deal withobserved pressure variations. The ability to dynamicallycontrol annular pressures facilitates drilling of what mightotherwise be economically unattainable prospects under theconventional drilling process. MPD techniques may be used toavoid formation influx and typically flow incidental to theoperation will be safely contained using an appropriateprocess. 2

Wellbore pressure-related drilling challenges result insignificant NPT within the well construction process. Thewellbore related part of these problems may include loss ofcirculation, kicks, ballooning of the wellbore, drilling in atight PP/FP margins, use of close tolerance casing programswellbore stability problems due to fluctuation and/or cycling

OTC 18375

A Process Used in Evaluation of Managed-Pressure Drilling Candidates andProbabilistic Cost-Benefit AnalysisR.R. Brainard, RRB ENERGY INC.


2/13

2 OTC 18375

of imposed pressure on the wellbore, water/gas flows in theshallower formations below the mudline, slow ROP due tohigh imposed hydrostatic along with ECD overburden andother related problems. Many statistical studies have beencompleted on Operator supplied drilling databases and theytypically demonstrate consistent correlation with respect tothese type of wellbore related problems as compared to the

total NPT areas for concern. Typically wellbore relatedproblems account for between 30% and possibly up to 50% ofthe overall NPT in a typical industry well. With the costs ofwell construction today, industry spends billions of dollars onthese types of wellbore related problems in which MPD mayprovide significant advantages.

Discussion of MPD Portfolio TechniquesTechniques for the provision of MPD to our well constructionoperations are varied throughout the industry and generallycan be categorized into either single gradient or dual/variablegradient technologies (Figure 1). Many of these techniqueshave been practiced for many years in industry, although theymay have never been identified as belonging to the collectionof MPD technologies.

Single Gradient TechnologiesSingle gradient MPD technologies are those wellbore pressuremanagement technologies that utilize a single gradient fluid inconjunction with either surface or downhole pressuremanagement technologies to achieve the desired annularpressure profile.

Surface Pressure Control Technologies may include:

External Riser Rotating Control Diverter (RCD) w/Subsea BOPs

Surface RCD w/ Surface BOPs

Continuous Circulation System

Circulation Friction Control Annular Geometry

Underbalanced drilling w/ RCD

In the case of many Operators, underbalanced drilling may notbe considered a technique within the MPD umbrella oftechnologies, but rather considered outside the bounds ofMPD, distinguished by planned influxes into the wellbore.

Surface/Subsurface Pressure Control Technologies mayinclude:

Subsea RCD w/ Subsea BOPs

Equivalent Circulating Density (ECD) ReductionTool

Dual/Variable Gradient TechnologiesDual or variable gradient MPD technologies are thosewellbore pressure management technologies that utilize twofluids of different densities or a fluid of varying density toprovide the desired annular pressure profile. Again, this isused in conjunction with either surface or downhole pressuremanagement technologies to achieve the desired annularpressure profile.

Surface Pressure Control Technologies may include:

Dual Gradient Drilling (DGD) - Annular NitrogenInjection

DGD - Nitrogen Injection

DGD - Surface Controlled Diluent Injection andSurface Separation

DGD - Surface Controlled Hollow Sphere Injection

Riserless Pump & Dump Subsea RCD Riserless Pump & Dump

Subsea or Downhole Control based technologies may include:

Dual Gradient Drilling - Mudline/Riser based SubseaPumping Systems

Top Hole Riserless Mud Recovery (RMR) system

Additional detail on some of the currently utilized or highervalued technologies identified above is discussed below.

Pressurized Mud Cap Drilling (PMCD) and/orConstant Bottom Hole Pressure (CBHP) mode of

MPDThe use of Pressurized Mud Cap Drilling (PMCD) (Figure 2)and or Constant Bottom Hole Pressure (CBHP) (Figure 3)mode of MPD with use of a Rotary Control device (RCD) andassociated choke manifold, Annular Pressure While Drilling(AWPD) tool and possible surface mud/gas separationequipment provides annular pressure control of the well usinga combination of surface backpressure and a typically lighterhydrostatic column provided by the drilling fluid for acombined bottom hole pressure in excess of pore pressure.

In PMCD, the use of these tools, in conjunction with duaannular fluid gradients, is intended to the enhance HSE

aspects of well control through the elimination of flow tosurface. PMCD is also used to minimize costs due to extrememud losses to formations where there is no capability to reestablish returns (such as in vugular or highly fracturedlimestone formations or in pressure depleted zones). With theCBHP mode, the use of surface pressure allows a lighter mudweight than that used in conventional drilling. This techniqueuses fluid density, frictional pressure losses along with surfaceback pressure to maintain the imposed wellbore pressurebetween the pore and formation fracture pressures.

The technology is intended to bring value to both onshore andoffshore applications. Potential drilling efficiency benefitsinclude:

Improve HSE through safely managed annularpressures and reduction of any occurrence of possibleannular gas migration

Drilling with less wellbore related NPT

Improved wellbore stability through less cycling ofannular pressure

Reduced mud costs through reduced losses

Enabling of well program unachievable byconventional drilling processes

Improved ROP performance

Improved well performance capability


3/13

OTC 18375 3

MPD projects of these types have been successfullyaccomplished in industry offshore SE Asia 3,4utilizing floatingrigs and in deepwater GOM and offshore Angola from surfacefacility installations.

Equivalent Circulating Density Reduction ToolMany of the problems associated with drilling in deepwater

can be related back to the inherent uncertainty in predictingpore pressures and fracture gradients. Maintaining sufficienthydrostatic pressure for controlling the pore pressure while notexceeding the fracture pressure on the previous casing shoe istypically present from the initial stages of the well until thewell is completely cased and cemented. In ultra-deepwater, theseverity of the problem is exacerbated because shallowformations have less strength and cannot support the weight ofa mud column.

Extensive pre-drill engineering and geological work isperformed to provide the best understanding about the narrowpressure window. Multi-disciplinary teams are essential inplanning deepwater wells. However, the accuracy of their porepressure predictions is based on the reliability of the availableoffset data and at times this data is minimal. Predictions arebased on empirical calculations and any enhancements topressure control with the application of mechanical technologysuch as a DGD system or ECD Reduction tool would increasethe drillability of the prospect.

The use of any type of ECD Reduction tool could provide amultitude of benefits to deepwater and ultra-deepwateroperations. The use of an ECD Reduction Tool in MPDprovides for a reduction in the wellbore pressure sensed by theannulus. This technology provides for the introduction ofmechanical energy (Figure 4) at a single point within the

upper portion of downhole string in hole at the discharge ofthe tool and translates this energy into a pressure reduction atthe point of introduction of the pump discharge. Accordingly,a shift in the pressure gradient through a reduction of thepressure of a fixed amount, typically 200 - 300 psi, is noted.This reduction in pressure translates into a reduction inannular wellbore pressure at all points below the depth of toolinstallation. Accordingly, as the name implies, the ECD on theformation is thereby reduced.

This cost effective technology is needed to reduce wellconstruction cost and enhance safety, particularly in the lowerportion of the hole interval(s). Use of an ECD Reduction Tool

in MPD would improve the ability to drill close pore pressure(PP) / fracture pressure (FP) window regimes moreeconomically, reduce associated NPT, significant mud losses,reduced mud weighting requirements, reduced associatedlogistical support and improve access to lower cost reserves.

ECD Reduction Tool technology is currently being field testedby two different industry service providers. It is felt that acommercialized tool will be available within 6 to 12 monthsafter the completion of the ongoing field trials of these tools.

Riserless Mud Recovery (RMR)Top-hole sections in deepwater and ultra-deepwater wells arecurrently being drilled using riserless Pump and Dumptechnology, where mud and cuttings returns are taken to theseafloor. RMR technology is needed to reduce welconstruction cost and enhance safety. Deepwater RMR wilreduce mud volume requirements, reduce logistical support

lessen operational dependence on weather, and minimizedischarge to the environment. It will eliminate the largevolumes of top-hole mud, often in excess of 40,000 bbls, thaare currently required to execute the Pump and Dumpapproach on some wells.

BP has successfully contributed to the development ofriserless mud recovery (RMR) technology (Figures 5 & 6)through its use in over 20 wells in shallow waters of theCaspian Sea. Historically, the surface holes of the wells in theWest Azeri field of the Caspian Sea were drilledconventionally with seawater and gel sweeps with destabilizedhighly reactive soil formations. Resulting unacceptablemovement of the 20-in. casing has required the use of a RMRsystem to allow formation inhibition with a silicate mudsystem. 5,6

Additional RMR work is being considered in shallow waterapplications offshore Russia, Australia and MalaysiaAdditionally, Statoil and Norsk Hydro have participated in theNorth Sea field trial of the Demo 2000 Joint Industry Project(JIP) to develop and qualify an RMR system for water depthsof up to 1,500 ft (450 m). An additional RMR JIP has beenrecently proposed in 2005 by AGR, Intellectual Property (IP)holder, to further the commercialization of this technology indeepwater depths. This R&D project will take the technologybeyond its current 1,500 ft (450 m) WD limitations, extending

its application to water depths of up to approximately 5,000 ft(1,500 m). The objective of the proposed JIP will be todeliver a low-to-medium capital cost system for use incommercial riserless well construction in these deepwaterdepths. However, the current pump type used in thistechnology is unable to achieve capability on the ultra-deepwater water depths due to the mechanical efficiency of itsdesign.

Dual Gradient Drilling (DGD)In deepwater, the seawater column, and the unconsolidatednature of the sediments near the seafloor make for achallenging drilling environment. The pore pressure and

fracture pressure are often close together, making it difficult tomaintain wellbore annulus pressure safely between thesevalues. If the annular pressure at the seafloor is reduced tothat of seawater by a dual gradient (riserless) system, thehydrostatic progression with depth becomes a straight line thatextends from the surface to the seafloor. Using this methodthe pressure control point at the mudline is significantlyreduced, when compared to a hydrostatic column of mudallowing a much greater vertical distance to be drilled whilemaintaining pressures safely between the pore and fracturepressures.


4/13

4 OTC 18375

Several major operators and others have contributed to thedevelopment of DGD technology over the last 10 yearsthrough their participation in both the SubSea MudLiftDrilling (SMD) JIP and the DeepVision JIP. Thisparticipation enabled the development of dual gradienttechnology through two distinctly different and competingapproaches. Additionally, both Shell and Maurer Engineering

have provided additional investments in similar DGDtechnology.

SubSea MudLift Drilling (SMD) JIPIn response to some of the challenges of deepwater drilling,five years ago, Conoco, BP, Amoco, Chevron and Texacoalong with Hydril supported by a consortium of drillingcontractors, and other service companies began participationin the SubSea MudLift Drilling JIP (SMD JIP). The goalwas to find a method of overcoming the challenges ofdeepwater drilling, and it was quickly determined that dualgradient drilling was potentially one of the optimal solutions.The JIP was then charged with delivering a dual gradientdrilling system, along with all the attendant drilling and wellcontrol procedures necessary to support this technology. Thefield test of the SubSea MudLift Drilling system and itsMudLift Pump (MLP) provided the first successfuldemonstration of the drilling of an offshore well under a dualgradient system. 7,8,9,10

The SMD JIP developed and delivered a pre-commercialversion of DGD technology. However the next major hurdle isto take the technology from the development stage to full-scale field implementation. The right to commercialize theequipment developed within the SMD JIP was assigned toHydril. In late 2000, Hydril formed SMDC, LLC, and beganto actively market the technology within the industry. SMDC

initially shifted their major focus for securing industry supportfor a commercial system from a single operator to aconsortium of interested operators. However, insufficientdemand for this relatively high Capex technology (over $ 50MM to integrate into a rig) has shelved it over the last fouryears due to insufficient demand by the deepwater operatorindustry segment. 11

The DeepVision JIPIndustry participated in another JIP project, DeepVision andBP (Amoco) and Chevron in conjunction with other industrycompanies, Transocean Sedco Forex (TSF) and Baker HughesInteq (BHI). The DeepVision Project was initially

envisioned to focus on the feasibility of developing adeepwater drilling and well intervention vessel using theconcept of riserless drilling with a reeled pipe system. Theadvancement of this concept was completed in late 1998 andattention shifted to the development of a DGD system thatwould utilize conventional drillpipe deployed from aconventional drilling rig. After focused work on this proposedDGD system, the third phase of the project was initiated. Theparticipants in the third and final phase were BP (Amoco),Chevron, BHI, and TSF.

This phase consisted of the design, manufacture, and testing ofkey components, including a pump and its control system,

updating and refinement of operating procedures, anddevelopment of a training plan. The pump design utilized inthis project is in contrast to the SMD JIPs hydraulicallypowered positive displacement MudLift Pump. TheDeepVision project developed a multi-stage centrifugapump configuration utilizing an electric powered variablespeed drive. The testing in the third phase of the

DeepVision project was completed in early 2002 with thesuccessful shop testing of the major components, including thepump and its control system, in a flow loop. 11

Through the third phase of the DeepVision project, avariation of the DeepVision pump system was discussed, toprovide significant benefits to the end user through a lesscapital-intensive system, allowing a more phased developmentof the technology. The DeltaVision concept utilized themotor and centrifugal pump developed in the DeepVisionProject to boost return mud flow to offset ECD rather thandeliver a full dual gradient column at the mudline. Anenhanced version of DeltaVision, DeltaVision Plus, usedthe motor and centrifugal pump modules at 3,000 ft. to 5,000ft. setting depths to obtain the majority of DGD benefits withmuch less complexity.11

Surface Controlled DGD TechnologyThe use of DGD techniques with surface controlled fluiddensity is potentially less complex than conventional mudlineor riser based pumping solutions. Considerable work has beendone by Luc de Boer to develop and test a Fluid DilutionDGD concept. He has been able to demonstrate, in a full-scalepilot technology trial, the ability to separate an intermediatedensity 80/20 fluid into heavy and light discharge streamsusing a centrifuge. Importantly, the heavy fluid stream retainthe properties required of a drilling fluid. 12,13

A fluid dilution DGD system does not require complex subseapumping systems or major modifications to drillingprocedures and rig systems.12,13 Light weight solids (e.ghollow-spheres) and/or fluid dilution systems in which alighter density component becomes mixed with annular mudreturns at or below the seafloor have potential advantages inthat they are simple lower cost alternatives to subsea basedmud pumps. Many deepwater rigs could use the systemwithout significant and costly rig modifications.

Fluid dilution alone can result in riser column fluid densitiesof 9.0 to 9.5 ppg. The use of light weight solids, such as

hollow-spheres in conjunction with fluid dilution, may allowthe hydrostatic to be lowered to the equivalent seawatergradient of 8.6 ppg. Fortunately, because of normal increasein rock strength with increased well depth, a DGD system witha seawater gradient to the mudline may not be required toobtain the majority of the benefits of DGD. The primarydisadvantage of light weight solids is that they can effectivelyreduce mud weight only about 3 ppg. However, when used inconjunction with fluid diluent technologies, light weight solidsmay be able to achieve much more significant reductionsapproaching a seawater gradient at the sea floor. Additionallyfuture offshore shelf and/or deep onshore wells may also be


5/13

OTC 18375 5

able to utilize this technology through the introduction of aparasite string or other deep injection point within the well.

This technology also has the added benefit of replacing heavydrilling mud in the riser with a lighter fluid. This reduces risertensile loads, thereby increasing the rigs water depth capacityand may open up the use of smaller rigs to the well

construction process in deeper water applications. Thistechnology may also provide an opportunity to utilize slimhole and smaller OD riser, reducing riser tension capacityrequirements and enabling smaller and older generation rigsincreased riser storage capacity for the deepwater depths.12,13

The Future of DGDOverall, the industry has spent significant research anddevelopment funds for the initial determination of thecapability and development of DGD technology. It isestimated that total research dollars in excess of $100 MM,were spent on industrys DGD technology developmentthrough 2002. This would include the work done in the late1990s through 2002 by the SMD JIP, DeepVision JIP,work on Shells DGD solution, as well as other industryefforts such as Maurer Engineering to advance gas lift andlight weight solids approaches.11

Much of the past DGD focus has been upon tricking thewellbore hydraulics into thinking the rig is setting on the seafloor of a deepwater well. However, possibly several yearsmay lapse before the necessity of a true seawater DGDtechnology will be economically viable. The industry may findin the nearer term that the 80/20 rule may be applicable in thisregard. At 20% of the cost, 80% of the benefit of DGDtechnology can be obtained.

Many of these other DGD techniques will not remove all ofthe mud and cuttings hydrostatic head within a marine riserequivalent to a seawater gradient at the mudline. One may saythat these techniques will only trick the wellbore into thinkingthe rig is closer to the seabed than it actually is whileallowing significant changes in Equivalent Mud Weight(EMW) and the resulting slope of the imposed pressureprofile. Such DGD techniques may be applied to reap therewards of the lower hanging fruit within the next severalyears.

Processes, Methods, Factors and ParametersUtilized to Evaluate Potential MPD Well Candidates

A process will be presented that has been has been developedand employed to evaluate candidate wells for the use of MPDtechniques. The technical and commercial benefits of MPDcan be evaluated using this process.

This process includes preparation of the following studieswhich a stage gate management process (Figure 6):

Feasibility Study

Preliminary Engineering Study

Detailed Engineering and Implementation PlanningStudy

Feasibility StudyA feasibility study is initially completed to provide a first lookbasis of the technical and commercial benefits of potentiaapplication of the MPD technologies to the well constructionprocess.

Objectives typically include:

1) Identify the MPD technical solution best suited forthe candidate well

2) Determine risk to personnel, environment, platformand wells introduced by the technology

3) Briefly evaluate risk mitigation tools, systems andprocesses

4) Determine potential MPD value through a scopingcost estimation and an overall Cost-Benefit analysis

The Feasibility Study will address both the technical andcommercial issues and allow management to make a decisionon the merits of further study. If the stage gate is passed, workwill progress with the development of a PreliminaryEngineering Study. Typically the scope and duration oPreliminary Engineering Study activities for the initiawell/well program candidate application can be completedwithin 4 to 6 weeks and with the required funding ofUS$ 50,000 - $ 100,000.

Typical deliverables for a Feasibility Study may include:1) Cataloging of available MPD techniques for the

candidate well/well program2) Technical evaluation of techniques & lessons learned

from other relevant MPD projects3) Preparation of a wellbore pressure profile with

potential MPD techniques identified4) Evaluation of the risks & benefit of MPD to the

candidate well5) Determine time and cost estimates for:

a. Preliminary Engineering Studyb. Detailed Engineering and Implementation

Planning Study6) Determine scope, schedule and deliverables for above

studies7) Evaluate the economic benefit of MPD techniques for

targeted hole sections of a candidate well or welprogram through a Cost-Benefit analysis

Preliminary Engineering StudyAfter a completion and review with Management of the results

of a successful Feasibility Study, an approved PreliminaryEngineering study will provide more engineering andtechnical support for development of a general strategic MPDplan for the candidate well or well program. This study wilalso provide detailed AFE cost estimate support and additionadetailed verification of the applicability and benefits of suchwork.

The scope of work will typically include collectionorganization and review of pertinent data on the candidatewell/well program, review of offset well information, reviewof field site and/or rig specifications including drillingoperations history, vendor data, desired completion plans, and


6/13

6 OTC 18375

detailed specification of requirements or a Basis of Design(BOD) for the required MPD equipment. Detailed analysis ofsite-specific costs and spread rates for the MPD equipmentand personnel will be undertaken, and the basis of a general,strategic MPD plan will be developed.

Specific tasks to be undertaken generally will include:

1) Implementation of a kick-off meeting to review theFeasibility Study and establish project objectives

2) Gather electronic data on offset candidate welloperations

3) Organize, review and analyze data4) Develop preliminary well & pressure profile designs

and perform specific preliminary hydraulics analysis5) Prepare a justification basis to address regulatory

concerns in technology application6) Meetings with Operator regulatory groups7) Meetings with potential MPD vendors and

contractors8) Field or rig site based visit9) Determine and document required rig modifications

and MPD equipment layout/integration10) Prepare impact of MPD on basic well design11) Final MPD method/technique selection and

application12) Review AFE costs and spread rates for MPD

equipment, personnel and rig integration costs13) Determine time requirements/schedule for execution

of MPD14) Perform a probabilistic Cost-Benefit analysis15) Present recommended MPD methods and basic

program

Typical deliverables for a Preliminary Engineering Study may

include:1) Well Profile Basis of Design (BOD)2) Preparation of a wellbore pressure profile with

potential MPD techniques and pressure profile forBOD design, including hydraulics analysis

3) Presentation material for regulatory introduction toproject

4) List of required rig modifications, includingestimated cost of each modification and proposedresponsible party

5) Strategic plan, including specific MPD method forthe specified wellbore/well program

6) Refine time and cost estimates for MPD

implementation as a basis for changes in theassumptions utilized in the initial Cost-Benefitanalysis

7) Preparation of a more defined probabilistic Cost-Benefit analysis

8) Overall MPD BOD for the application of thetechnology

With the basis of funding and completion of a PreliminaryEngineering Study, it is envisioned that Management can beprovided significant evidence with regard to both the technicaland commercial viability of the project. Should a negativeresult be encountered, Management may suspend further

work. Alternatively, a positive and convincing case for theuse of an MPD approach will result in passing through a stagegate into the next phase for the preparation of a DetailedEngineering and Implementation Planning Study. Typicallythe scope and duration of the activities for a PreliminaryEngineering Study for an initial well/well program candidateapplication can be completed within 8-12 weeks and with

required funding of no more than US$ 100,000 - $ 200,000.

Detailed Engineering and Implementation PlanningStudyThe Detailed Engineering and Implementation Planning Studywill provide for preparation of detailed MPD proceduresincluding hazard identification and mitigation, a contingencyplan, detailed hydraulics analysis of the wellbore, a tacticaMPD plan including a training program as required forsuccessful implementation of the MPD technology.

The scope of work typically will include thorough planningrequired to penetrate the target formations, managing bothvirgin and/or potentially depleted or transition/regressionpressure horizons to drill to the projected total depth. Detailssuch as target location, casing design criteria, drilling fluidsthe formation evaluation program, and review of well controissues must be considered. Hazards and operational aspectsnecessary to mitigate the hazards will be identified andcontingency procedures will be prepared for inclusion in theoverall MPD plan. All necessary equipment, including anyadditional well control or specialty equipment will be sourcedand procured, and any necessary rig modifications will bespecified. Site-specific training programs will be developedand presented in a timely manner to allow sufficient time forOperator, drilling contractor and vendor personnel to becomefamiliar with the MPD equipment and techniques that are to

be used. All material generated will be organized and used toprepare a specific, detailed tactical MPD plan.

Specific tasks to be undertaken will include:1) Compilation of standards and practices related to

MPD2) Description of specific PP/FP/wellbore stability

profile and hydraulics analysis3) Preparation of detailed MPD procedures4) Specification of MPD equipment, monitoring, and

suggested procurement5) Design of path of the flow design, routing and

definition of required pressure testing

6) Description of drilling fluids & required parametersparticularly rheology

7) Evaluate and analyze casing design for MPD andassociated changes in rating for revised MaximumAnticipated Surface Pressure (MASP)

8) Review MPD Implications on BOP and Well Controequipment and practices

9) Prepare casing/liner running and cementingprocedures w/MPD

10) Define bit program, general hydraulics and holecleaning parameters for MPD

11) Drill string design and analysis


7/13

OTC 18375 7

12) Identify MPD potential equipment and processesproblems and prepare detailed contingencyprocedures for proper risk mitigation

13) Prepare HazID/HazOP Report14) Finalize regulatory requirements & meetings with

regulatory personnel15) Review HSE implications and modify mitigations as

necessary on the well program16) Refine time and cost estimates for MPD equipment

and MPD rig integration17) Prepare schematics and P&ID's, including rig

modifications/integration18) Peer review of MPD drilling program19) Prepare customized training

Deliverables related to the Detailed Engineering andImplementation Planning will be similar to the PreliminaryEngineering phase, however will be more detailed to allowimplementation to proceed. However, these deliverables willtypically include in addition:

1) System P&ID drawings for MPD, including rigmodifications

2) Detailed MPD drilling/tripping procedures for allintervals

3) Regulatory requirements changes4) Detailed MPD casing/liner running and cementing

procedures5) HazOP Report6) Documentation of a customized training program,

including training manuals and defined program

Commitment by Management to undertake the DetailedEngineering and Implementation Planning Study typically will

require thorough preparation and adherence to the projectschedule to deliver a completed plan that all office and fieldpersonnel are prepared to execute to make MPD a part of thewell construction process. Typical scope and duration of theactivities for a Detailed Engineering and ImplementationPlanning Study for an initial well/well program candidateapplication can be completed within 8 to 20 weeks and withrequired funding for total costs typically in the US$ 150,000 -$ 250,000 range.

Cost-Benefit AnalysisThe cost-benefit analysis is an evaluation of the total estimatedincremental costs and associated time for the application of the

MPD techniques as compared to the value of the benefits ofthe use of these techniques. This analysis requires collectionof vendor and operator estimates of MPD and other equipmentcosts, personnel costs, study and training costs, and estimatesof the duration of incremental tasks within the well program asrelated to changes due to MPD application. Additionally, thebenefits of these techniques such as increases in ROP forparticular hole interval(s), reduction in wellbore related NPT,reduction in liner requirement and associated setting costs orother benefits will also have to identified for the project.

A cost-benefit analysis is initially prepared for the FeasibilityStudy. This base analysis is further evaluated in subsequent

Preliminary and Detailed Engineering and ImplementationPlanning phase studies. As necessary, the cost-benefit analysiscan be refined with modifications to the variable assumptionsand the possible introduction of additional variables within themodel.

Simulation Methods

This evaluation has included the use of a probabilistic MonteCarlo simulation of the potential results of the use of MPD andtakes into account time dependent, cost dependent andperformance related factors. This method allows for a range ofpotential inputs to be used to develop a probabilistic resulbased on probabilities rather than the conventionamethodology of using a deterministic number based on pasexperience. With respect to past experience, in many casesthere is generally no reliable experience that can be applied tothe inclusion of MPD into the well construction process due tothe limited industry experience with such technologyProbabilistic modeling of general cost estimating for drillingoperations was discussed in industry literature in the 1990s byS. K. Peterson et al.14,15 of Marathon. Other work hasaddressed risked based decision-making and modeling forstuck pipe and fishing operations, the influence ofenvironmental conditions in Arctic areas on drillingoperations, and weather downtime. Through the use oprobabilistic Monte Carlo simulation techniques, a moreaccurate assessment of the expected distribution of total welcosts or potential savings in costs and duration for the wellconstruction operations can be made. 16

Additional sensitivity modeling within this analysis canidentify the effects of certain modeled parameters to theeffective outcome of events such as total well days or welcost to more cost effectively apply resources to that those

parameters that can most influence the outcome of events. 1

With this modeling, the forecasted benefits of MPD can beidentified that are most sensitive to certain variables such as achange in rig and/or spread rate, reduction in number ofrequired casing strings or other similar variable.

With the continuing significant rise in the cost of both thedrilling contractor and other industry services required forwell construction along with considerable escalation intangible and other materials and equipment costs, it has beenincreasingly difficult to accurately assess costs related to boththe use of MPD technologies, particularly when trying toassess these costs one to two years before the actual projec

may be initiated and the variability of the benefits of thesetechnologies with variation in their associated costs. Throughthe use of probabilistic Monte Carlo simulation techniques, amore accurate assessment of the expected distribution of totacosts and the results of the benefits of the MPD process fordrilling operations can be made.16 We can introduceuncertainty into the level of costs that comprise the dailyspread rate which includes items such as the MPD equipmenand MPD personnel rates, drilling contractor rig costs, rentatools, transportation and other logistics costs, companysupervision costs, daily mud maintenance costs, daily rigconsumables and other daily costs.


8/13

8 OTC 18375

Although many times we think we have a better estimate ofour non-time dependent costs such as tangibles andintangibles, we also need to introduce uncertainty into theevaluation of these costs. This is particularly important whenapplication of estimates from time period may not reflectdifferences in labor rates, competitiveness or lack ofcompetitiveness of the local service industry and other factors.16

An Excel spreadsheet has been prepared with the modeledassumptions and forecasted variables on which commercialMonte Carlo simulation software packages can be run. Due tothe relatively short cumulative duration of the required studiesof 6-12 months followed by well drilling time of less than 180days, no attempt has been made to introduce Net PresentValue (NPV) concepts into the spreadsheet calculation.

Modeling ParametersA level of uncertainty regarding the duration of time savingsand similar variables was captured through assignment of anassumed range for the particular variable modeled. Typicallyeither a uniform (Figure 8) or triangular distribution (Figure 9)is utilized to represent variability within our definedassumptions. One exception would be when actual historicaldata on NPT is available and can be curve fitted. Theresulting distribution often takes the form of a Beta or Weibulldistribution. Variation in the type of assumptions utilizedwithin the spreadsheet model for analysis of the cost-benefitanalysis of several different techniques of MPD is furtherdiscussed below.

The use of other complimentary technologies to MPD, such aswellbore strengthening or wellbore stability technologies canalso be incorporated within the model variables to look at theoverall use of any applied technologies in conjunction with

MPD to further benefit the well construction process. Anadditional particularly complimentary technology may becasing or liner drilling, which reduces required trips in theprocess of well construction, a set of tasks in which MPD ismost difficult to manage with a RCD.

Description of Variable Factors in the Model forVaried MPD TechniquesThe variables considered for inclusion within the Cost-BenefitAnalysis Model include 1) Time Dependent factors, 2) Non-Time Dependent factors along with 3) Performance relatedfactors.

PMCD and or/ CBHP Mode with RCDThese techniques, within the umbrella of MPD technologies,are some of the more frequently utilized applications at thistime within industry. These techniques have applications forcandidate wells on fixed bottom offshore facilities such asjack-ups or platforms as well as floater applications, both forsubsea and surface BOP stacks.

Additional detail on the factors typically considered in themodeling for such techniques is shown below:

Time Dependent Factors

Increased tripping time due to MPD

Decreased NPT trouble time

Increased/Decreased circulating time

Faster ROP

Presence of Downhole Deployment Valve (DDV) orsimilar to reduce trip time

Incremental installation time for DDV

Additional RCD RU/RD time

Additional Separator/Piping/Choke RU/RD time

Non Time Dependent Factors

DDV equipment and installation costs

Additional RCD deployment and rental costs

Additional separator/piping/choke costs

Reduced mud costs-lower density/less losses

Additional operator/rig personnel training costs

Performance Factors

Decreased skin/Increased well performance

No acid job required in completion

Decreased HSE risk in hole section due to improvedgas/kick detection

Improved ability to get liner to bottom-contingencyliner reduced

No trip/swab surge losses while running liner

Forecasted potential total cost savings of US$ 2.4 MM from atypical cost-benefit analysis of MPD application in two holeintervals for a candidate offshore well using a jack-up rig isshown in Figure 10.

Riserless Mud Return (RMR)The potential application of RMR technology in the deepwaterand ultra-deepwater regions will provide advantages as related

to reduction in mud discharges to the environment as anenabling technology and the reduction in mud and logisticscosts and potential casing/liner settings costs as anenhancement technology.

Additional detail on the factors typically considered in themodeling for such techniques is shown below:

Time Dependent Factors

RMR deployment/recovery time

RMR rental costs

Decreased NPT trouble time

Decreased circulating time

Faster ROP Flat time reduction for elimination of casing/liner

Reduced logistics costs

Non Time Dependent Factors

Reduced mud costs-less losses

Additional Operator/rig personnel training costs

Performance Factors

Reduction of environmental discharges to theenvironment at the mudline


9/13

OTC 18375 9

Decreased HSE risk in upper hole sections due togas/water flows

Improved ability to get casing to bottom-nocontingency involved

Improved cementation of hole due to less washout,better cement contact to formation and less requiredremediation

Decreased susceptibility to flow after cementing withimproved cement results

Reduced potential of loss of well and required re-spud

One of the most important and visible factors to the erosion ofvalue of a deepwater version of the RMR system at this time isthe total rig spread rate costs, now approaching US$ 675,000 -$ 750,000/d, for deepwater and ultra-deepwater regions of theworld. Much of the potential value of RMR in deepwater iseroded by the effective value of critical path rig time that maybe required to initially deploy and ultimately recover the RMRmud return line and other subsea components. A simulation of

the overall benefit of the use of RMR solely by the reductionof pump and dump mud volumes shows a forecasted savings(Figure 11) of approximately US$ 723,000 P(50). This benefitis approaching the effective value of the range of the total rigspread costs for one day of a deepwater operation. An operatormay judge the benefits of this potential savings not to besignificant enough when considering the value of the spreadrate should potential delays in deployment or recovery of themud return line and the rest of the subsea components occur.

It also becomes apparent that the potential reduction in one ormore shallow casing string(s) by the ability to pump highermud weight fluids in the shallow hole sections may be a moreimportant factor to commercialization of deepwater RMR thanthe value realized in the reduction of cost savings from pumpand dump mud volumes and associated logistics costs. In thiscase, a savings of approximately US $ 4.34 MM P(50) (Figure12) may be realized with RMR and this benefit hassignificantly more cushion in terms of comparison to the dailyspread rate should delays occur.

This modeling suggests that significant potential savings canbe realized in the use of a pre-deployed deepwater RMR mudreturn line. In this case, a deepwater rig would move ontolocation, deploy a suction module and hook up subsea/surfacemud return hoses to a pre-installed mud return line adjacent tothe rig..

DGDThe potential savings for the use of dual gradient technologyfor typical wells in deepwater basins has previously beenestimated in the US$ 5 MM - $15 MM range per well duringthe 1999 - 2002 time period. These primary benefits areachieved by the reduction of required casing strings and lessreliance on close tolerance casing designs.7,8

An extensive exercise to determine the value of using DGDtechnology has been previously performed and potential costsavings/per deepwater well of approximately $US 6 MM

P(10) - $ 12 MM P(90) were modeled. Typical variables thawere used in this probabilistic model included: 10

Consumable Materials per Well (Excluding Mud)

Mud

Contingent Casing/Liner string, Hanger, etc.

Time Savings per Well

Casing Flat Time Days Savings

ROP Days Savings Historical Non-Productive Time (NPT)

Deepwater Trouble-Free Well Days

NPT Associated with DGD technology

Variation in Days through Surface (20 in. Csg.)Setting

NPT Savings

Total Days Saved

Contract Drilling Rates

Rig Total Daily Spread Rate

An additional analysis has recently been performed with thissame model. Updating of the previous simulations with therange of current total rig spread rates (US$ 675,000 $ 750,000/d) for deepwater operations, it becomes apparenthat there is significantly more value to be realized tooperators if a low Capex, low rig integration cost, efficientDGD system with high reliability can be provided to theindustry. Potential cost savings/per deepwater well ofapproximately $US 8 MM P(10) - $ 16 MM P(90) (Figure 13are now realistic in the current industry market structuresignificantly higher than seen in the previous time frame dueto the up tick in deepwater rig rates.

ConclusionManaged Pressure Drilling (MPD) with its many techniques

is currently providing decreases in costs of well constructionwithin the industry with additional HSE benefits. CertainMPD techniques less commonly utilized such as DGD andRMR, previously have been considered only as anenhancement technology, but are now ready to becommercialized to become enabling technology as industrysteps further into the ultra-deepwater depths of the Gulf oMexico and other areas of the world, often exceeding 6,000 ftwater depths with planned well depths in excess of 30,000 ft.

For the further commercialization of DGD, the industry musevaluate the status of the various DGD technologies, eitherdeveloped or yet to be developed, and determine which

technology is technically most cost-effective for the range owater depth or other parameters. To move DGD technologiesforward on a common industry basis, operators with the helpof drilling contractors and other technology providers wilneed to work together to implement these technologies tomake the significant step changes possible in reduction of welconstruction costs. 11

Techniques, processes and modeling simulations such aspresented in this paper can be used to evaluate the potentiause of MPD technologies in candidate wells or well programsMPD techniques have the potential to allow industry to makethe most significant step-changes in drilling well duration and


10/13


11/13

OTC 18375 11

FIGURES

Figure 1-MPD Technologies

Figure 2- Pressurized Mud Cap (PMCD) Mode of MPD w/ RCD

Figure 3-Constant Bottom Hole Pressure (CBHP) Mode of MPD w/RCD (Courtesy SPE

2)

Figure 4- ECD Reduction Tool Pressure Profile

Pressurized Mud Cap MPD

GELLED MUD INJECTED INTOANNULUS PREVENTS HC

MIGRATION

EQUIVALENT SINGLEDENSITY GRADIENT

LOW DENSITY FLUID,E.G. SEAWATER

BHP

ALL RETURNS

INJECTED INTO CARBONATE

LOSS ZONE

BACK PRESSURE

PRESSURE, PSI

TRUEVERTICALDEPTH,FT

Pressurized Mud Cap MPD

GELLED MUD INJECTED INTOANNULUS PREVENTS HC

MIGRATION

EQUIVALENT SINGLEDENSITY GRADIENT

LOW DENSITY FLUID,E.G. SEAWATER

BHP

ALL RETURNS

INJECTED INTO CARBONATE

LOSS ZONE

BACK PRESSURE

PRESSURE, PSI

TRUEVERTICALDEPTH,FT

T

V

D

p s i

S T A T I C

B H P = H H ( M W ) +B P

A FP

C O N S T A N T B H P M P D

D Y N A M I C

B H P = H H ( M W ) + A F P

N o t e : Idea l l y , A F P = B P , s o B H P

r e m a i n s c o n s t a n t , a n d p r e s s u r ea t w e a k z o n e is r e d u c e d .

T

V

D

p s ip s i

S T A T I C

B H P = H H ( M W ) +B P

A FP

C O N S T A N T B H P M P D

D Y N A M I C

B H P = H H ( M W ) + A F P

N o t e : Idea l l y , A F P = B P , s o B H P

r e m a i n s c o n s t a n t , a n d p r e s s u r ea t w e a k z o n e is r e d u c e d .

ManagedPressure

Drilling (MPD)

Single GradientTechnologies

Dual/VariableGradient

Technologies

Surface PressureControl Technologies

Subsea or DownholeControl Technologies

Surface PressureControl

Surface/SubsurfacePressure Control


12/13

12 OTC 18375

Figure 5-Riserlesss Mud Recovery (RMR) Technology PressureProfile

Figure 6-RMR Basic System Configuration (Courtesy AGR)

Figure 7-Defined MPD Well Candidate Process

Figure 8-Example Uniform Distribution for 8 1/2 Hole AverageTrip Depth

Figure 9-Example Triangular Distribution for 12 Hole Bit Trips

8.00 9.00 10.00 11.00 12.00

12 1/4" Hole-Bit Trips

1 3,1 00 .0 0 1 3,9 50 .0 0 1 4,8 00 .0 0 1 5,6 50 .0 0 1 6,5 00 .0 0

8 1/2" Hole-Avg Trip Depth

Pump module

Power Supply, Winch and

umbilical

Return lineSuction

module

Pump modulePump module


umbilical


umbilical

Return lineReturn lineSuction

module

Suction

module

Defined MPDWell Candidate Process

Feasibility Study

Detailed Engineering

and Implementation

Planning Study

Preliminary

Engineering

Study

Stage Gate Stage GateExecute

Stage Gate


13/13

OTC 18375 13

Figure 10- Forecasted Total Well Cost Savings w/ MPD (Jack-upCase)

Figure 11-Forecasted Total Well Cost Savings w/ RMR(DW Floater Case w/ Pump & Dump Mud Reduction Only)

Figure 12-Forecasted Total Well Cost Savings w/ RMR (DWFloater Case w/ One String Casing/Liner Reduction)

Figure 13-Forecasted Total Well Cost Savings w/ DGD(DW Floater Case w/ Current Rig Market Rates)

Frequency Chart

$

.000

.006

.012

.018

.024

0

30.25

60.5

90.75

121

$4,405,301 $8,377,102 $12,348,903 $16,320,703 $20,292,504

5,000 Trials 4,887 Displaye

Forecast: Total Savings/Well

Frequency Chart

$

.000

.005

.010

.015

.020

0

25.5

51

76.5

102

$3,047,127 $3,698,764 $4,350,402 $5,002,039 $5,653,677

5,000 Trials 4,998 Displaye

Forecast: RMR Estimated Total Savings

Frequency Chart

.000

.007

.014

.021

.028

0

34.75

69.5

104.2

139

($1,423,486) $600,563 $2,624,612 $4,648,661 $6,672,710

5,000 Trials 4,950 Displayed

Forecast: All-Total Well Cost/Savings w MPD

Frequency Chart

$

.000

.005

.009

.014

.018

0

22.5

45

67.5

90

($335,386) $198,963 $733,313 $1,267,662 $1,802,012

5,000 Trials 4,997 Displayed

Forecast: RMR Estimated Total Sav ings

a process used in evaluation of managed-pressure drilling candidates and probabilistic cost-benefit...

Documents