mitigating drilling hazards with technologies

8/13/2019 Mitigating Drilling Hazards With Technologies

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Deepwater Horizon Study Group 3 Working Paper January 2011

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Mitigating Drilling Hazards with Technologies(Part 3 of DHM Series)

David M. Pritchardi

Owner, Successful Energy Practices International, LLC

AbstractIntegrating Mitigating Practices and Technologies into the well design is fundamental to

managing the risk of any drilling and completion operation.

Managing drilling hazards requires understanding how practices and technologies can improvethe risk profile and add value. This requires understanding how the risk assessment process can beapplied to both practices as well as technologies. From a DHM perspective, added value also meansimproving the risk profile as well as understanding that any new or added mitigant must showpositive cost and benefits from a risk adjusted perspective. Any new mitigant must first decrease thelikelihood of the risk event occurring and the risk adjusted cost should be financially beneficial tothe overall operation. It is therefore important to understand how technologies can improve theability to mitigate and manage risk and improve the ultimate value of the well.

Successful Energy Practices International, LLC 2010

iDavid Pritchard is a Registered Professional Petroleum Engineer associated with the Petroleum industry since 1970. Hehas extensive experience managing and supervising worldwide drilling and production operations. David has consultedfor an array of national and international independents, major companies and service providers in over 20 countries.Drilling and completion specialties include HPHT and Deepwater environments. David has analyzed, planned or auditedover 40 Deepwater and HPHT global operations. David holds a Bachelor of Science in Petroleum Engineering from theUniversity of Tulsa.


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Deepwater Horizon Study Group Working PaperMitigating Drilling Hazards with Technologies

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Table of Contents1 Reducing Risk Through Effective Application of Fit for Problem Technology .................... 32 Understanding the Mitigant Well Construction Technologies ................................................... 3

2.1 Drilling with Casing (DwC)/Drilling with Liners (DwL) ....................................................... 32.2 Managed Pressure Drilling (MPD) ............................................................................................. 62.3 Solid Expandable Systems (SES) .............................................................................................. 102.4 Purpose of Technical Limit Analysis........................................................................................ 122.5 Reducing Risk and Improving Drilling Time.......................................................................... 17

3 Conclusion ........................................................................................................................................... 24 Acronyms and Definitions ................................................................................................................ 225 References ........................................................................................................................................... 2

FiguresFigure 2.1 Comparing 100m/hr ROP with 50m/hr ROP. ............................................................... 4 Figure 2.2 Flat time reduction................................................................................................................ 4 Figure 2.3 Annular velocity comparison. ............................................................................................. 6

Figure 2.4 Simplified MPD system components. ............................................................................... 7

Figure 2.5 Depth vs. pressure. ............................................................................................................... 9 Figure 2.6 Slimming of wellbores through the use of solid expandable openhole systems. ...... 11

Figure 2.7 Geological map of example well. ...................................................................................... 13

Figure 2.8 Comparison of drilling curves with and without effective application of drillinghazard mitigants. ................................................................................................................. 14

Figure 2.9 Comparison of productive time, NPT, and removable lost time to total drillingtime........................................................................................................................................ 1

Figure 2.10 Depth versus time drilling curves with DwC/DwL and pressurized mudcapdrilling technologies applied in the upper hole sections. .............................................. 20

Tables Table 2.1 DwC annular velocity vs. conventional annular velocity.................................................. 6 Table 2.2 SMART well objectives for the example well. ................................................................. 15

Table 2.3 Excerpt of risk assessment for the application of the DwC/DwL technology. ......... 18

Table 2.4 Excerpt of risk assessment for the application of the pressurized mudcap drillingmethod of the MPD technology....................................................................................... 19

Table 2.5 Excerpt of risk assessment for the application of the SES technology. ....................... 21

Table 4.1 Drilling acronyms used in this paper. ................................................................................ 22 Table 4.2 Key drilling definitions. ....................................................................................................... 24


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1 Reducing Risk Through Effective Application o f Fit forProblem Technology

The many and varied technologies available to assist in drilling complex wells are often

underutilized. In light of the current workloads imposed on todays drilling engineers and wellsupervisors, it has been easy to apply the more familiar or what has generally worked in previous

well situations rather than apply the most fit for problem technology . Conversely, applyingtechnology for technologys sake is seldom the best approach especially when simply implementinggood drilling practices may be the best solution to the current challenge.

As previously highlighted in the Part 11 and Part 2 2 the best strategy and most prudent approachbegins with SMART well objectives followed by a thorough understanding of the uncertainties andthe most appropriate risk mitigants. Studies3 conducted over the past decade have shown thatapproximately 50 % of drilling hazards resulting in non-productive time (NPT) can be eitheravoided or mitigated using good drilling practices such as well listening (discussed in Part 2 of the

DHM series). Most of the other half of drilling hazards can be mitigated or avoided through the useof drilling with casing (DwC)/drilling with liners (DwL), managed pressure drilling (MPD, or solidexpandable liner technologies. These technologies are only a few of many from the drillingprofessionals tool box and any one should not be considered as a panacea solution.

2 Understanding the Mitigant Well ConstructionTechnologies

Because multiple resources4, 5, 6 exist that detail the workings of these technologies, this articleprovides only a brief description for review. Rather than fixate on how the technologies work, thefocus is on how DwC/DwL, MPD, or solid expandable liners can be applied to a real example to

substantially reduce well risk and cost in a set of complex wells within a very complex reservoir.2.1 Drilling with Casing (DwC)/Drilling with Liners (DwL)

DwC and DwL are applied methods and key technologies to manage drilling hazards. Thismethod of hazard management can be deployed to reduce risk in many hole sections or casing sizesand is a relatively simple, safe, and inexpensive insurance when drilling through trouble zones.

With DwC technology the casing string is used as the drillstring instead of drillpipe. Since the1950s, it has been common in some areas of the world to drill in the final tubing string and cementin place with the drill bit still attached. Modern DwC started in the early 1990s and differs fromprevious applications in that it is not limited to the final string. To date, this technology has beenused in approximately 2,000 applications. With the exception of a few experimental wells, casing has

been used to drill specific sections of the wellbore rather than the entire hole.2.1.1 Reduce Drilling Flat Time

A key benefit of DwC is time reduction. The time associated with tripping pipe and runningcasing, including much of the circulation time involved, is removed. Connection time savings equateto 12 %, assuming 3.5 minutes for 90 ft drillpipe and 5 minutes for 40 ft casing with on-bottom rateof penetration (ROP) of 50m/hr. At 100m/hr ROP the saving increases to 18 % (Figure ).7


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Figure 2.1 Comparing 100m/hr ROP with 50m/hr ROP.

These figures illustrate purely connection time savings. DwC also eliminates other NPT involvedin operations such as reaming, circulating high viscosity pills, conductor cleanout runs, etc. There areother potential savings from unscheduled events, for example, hole collapse. Typical total timesavings from DwC range from 30 % to 50 % of the time from section spud to leakoff test. Figure2.2 shows an example of flat time reduction.

Figure 2.2 Flat time reduction.


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2.1.2 Getting Casing to BottomDwC eliminates tripping drillstrings and conventional casing running operations and

subsequently, deterioration of time-dependent formations does not exist. The fact that the casing isalways on bottom ensures that where the drillable casing bit reaches is where it can be cased.Essentially all concerns regarding getting casing to total depth can be forgotten with DwC.

2.1.3 Eliminating Problems Related to Tripping Tripping the drillstring may result in many other problems such as surge and swab effect, lost

circulation, key-seating, borehole stability problems, and well control incidents. Elimination of pipetripping prevents the occurrence of these problems.

2.1.4 Drilling Depleted Zone and Overcoming Lost CirculationLost circulation is a severe problem, a frequent occurrence in mature fields and areas with weak

formations. It is a contributing factor to another serious problem which plagues drillers, that beingstuck pipe.8

It might appear that DwC would not be a good option because the casing could get stuck beforereaching the planned casing point. One would also expect lost circulation to be a potential problem

with DwC because the smaller annular clearance between the casing and borehole wall increases thefrictional pressure losses, thus increasing the ECD. In fact, the results indicate DwC significantlyreduces lost circulation. The exact mechanism that provides this benefit has not been scientificallyproven, however there is strong evidence and an industry belief this is the result of mechanically

working drilled solids into the face of the borehole, essentially smearing drilled cuttings and mudsolids into the borehole wall. This plastering effect mechanically builds an impermeable filter cake.9

Many case histories, published papers, and documented results exist to demonstrate thereduction of lost circulation and enhanced well control, and with no recorded stuck pipe incidents,

there is a compelling argument for DwC. But whether DwC should be the first choice for drillingtrouble zones is another question.

2.1.5 Enhancing Borehole Quality The inherent stiffness of the casing string in the wellbore produces a less tortuous hole,

providing a smoother wellbore and reducing the risk of key-seating and mechanical sticking. Thestiff assembly also is less prone to vibrations, reducing the mechanical impact damage on theborehole wall. Drillstring vibrations have been attributed to borehole stability problems and ovalshape holes.

2.1.6 Improving Safety

Some potentially hazardous operations may be eliminated when using DwC. Drilling surfacehole in shallow waters with high currents can require deployment of divers. Divers are not required when using DwC as the string does not have to be pulled out of the hole. Another advantage iseliminating hammering operations. Loading and rigging up pile hammers is often considered to beone of the most hazardous operations carried out on the rig floor.


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2.1.7 Reducing Rental CostsDwC eliminates the need for conventional bottom hole assembly (BHA) components, and can

eliminate the need for one or more strings of drill pipe.

2.1.8 Improving Hydraulics The annulus area between the BHA/casing OD and borehole ID is reduced in DwC, hence

under the same operating conditions DwC delivers higher annular velocity (AV) than conventionaldrilling (Figure 2.3). The improvement ranges from 81 % to 134 %, averaging 110 %. A rule ofthumb established consists of DwC annular velocity = 2 x conventional annular velocity.

Table 2.1 DwC annular velocity vs. conventional annular velocity.

Figure 2.3 Annular velocity comparison.

2.2 Managed Pressure Drilling (MPD)

Managed pressure drilling (MPD) is an advanced form of primary well control usually employinga closed and pressurized circulating drilling fluids (mud) system(Figure ), which facilitates drilling

with precise management of the wellbore pressure profile.

292

527

164

341

89

192

42

98

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100

200

300

400

500

600

V a n n , f

t / m

i n

500 800 1000 1100

7 9 5/8 13 3/8 20

5 1/2 5 1/2 5 1/2 5 1/2

8 1/2 12 1/4 17 1/2 26

Flow, Csg , DP , Hole

Conv

DwC


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Figure 2.4 Simplified MPD system components.

The primary objective of MPD is to optimize drilling processes by decreasing NPT, mitigatingdrilling hazards, and to enable drilling otherwise technically or economically un-drillable high-complexity prospects. The Society of Petroleum Engineers (SPE) and the International Associationof Drilling Contractors (IADC) offers this definition:

MPD is an adaptive drilling process used to control precisely the annular pressure profilethroughout the wellbore. The objectives are to ascertain the downhole pressure environment limits

and to manage the annular hydraulic pressure profile accordingly. MPD is intended to avoidcontinuous influx of formation fluids to the surface. Any flow incidental to the operation will besafely contained using an appropriate process.

MPD process employs a collection of tools and techniques which may mitigatethe risks and costs associated with drilling wells that have narrow downholeenvironmental limits, by proactively managing the annular hydraulic pressureprofile.MPD may include control of back pressure, fluid density, fluid rheology, annularfluid level, circulating friction, and hole geometry, or combinations thereof.MPD may allow faster corrective action to deal with observed pressure

variations. The ability to control annular pressures dynamically facilitates drillingof what might otherwise be economically unattainable prospects.

MPDs specialized equipment and techniques to practice its four industry -recognized Variationssafely and effectively have evolved since the mid-1960s on thousands of U.S. land drilling programsand is considered status quo by many who pioneered the root concepts. Compared to conventionalrotary drilling with jointed pipe and weighted mud, MPD applications have established acommendable well control incident track record. 10


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Because MPD addresses NPT, the technology is of greatest potential benefit to offshore drillingprograms where cost of lost drilling time is much higher than onshore. Although MPD was beensafely and efficiently practiced from all types of offshore rigs and produced the desired results in theprocess, it is still considered a relatively new technology to the majority of offshore drillers.

Nevertheless, since MPD technology and enabling tools was introduced to offshore drillingdecision-makers in 2003, there have been hundreds of applications globally in marine environments

from fixed rigs (jackup, platform mounted with surface BOPs) and floating rigs (moored semi-submersibles & drill ships with surface or subsea BOPs).

2.2.1 MPD ApplicationsDrilling-related issues such as excessive mud cost, slow ROP, wellbore ballooning/breathing,

kick-detection limitations, difficulty in avoiding gross overbalance conditions, differentially stuckpipe, risk of twist-off, and resulting well-control issues contribute to defining the offshore industrysneed for MPD technology. Kick-loss scenarios that frequently occur when drilling into narrow orrelatively unknown downhole pressure environments also define a requirement to deviate fromconventional methods. Excessive drilling flat time and health, environment, and safety (HES) issuesfurther indicate the necessity for a technology that addresses the root causes.

2.2.2 Hydraulics of Conventional DrillingSince founding the principles of conventional drilling hydraulics (Spindletop, Beaumont, Texas,

1901), it has been widely accepted that with mud in the hole, the only way to change the equivalentmud weight (EMW) or adjust the wellbore pressure profile is to change the speed of the rig s mudpumps. This depth vs. pressure map (Figure 2.5) illustrates that the wellbore pressure profilefluctuates significantly with each jointed pipe connection in harmony with circulating annularfriction pressure ( AFP).

When not circulating, the effective wellbore pressure is the mud weight hydrostatic headpressure (MW HH ). It may be determined in English units of measurement by multiplying a constant(0.052) times the mud density (MD) times the true vertical depth (TVD).

When circulating, the resulting equivalent mud weight is the sum of MW HH and the AFP.

EMW = MWHH + AFP

While drilling, if the annulus returns over flow the drilling nipple or marine diverter, a kick maybe occurring. If the returns fluid column falls, the fracture gradient of the open hole may have beenexceeded. In either case, an interruption to drilling progress is likely to occur.


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Window

X

TVD

MWHH = 0.052 x d x TVD EMW = MW HH + AFP CIRCULATING

Pressure

M W H H

E M W

AFP

P o r e P r e s s u r e

F r a c t u r e P r e s s u r e

Drilling

(varies with depth)Reference SPE Textbook, Applied Drilling Engineering , Adam T. Bourgoyne, Jr. et al

D e p

t h

Returns must not overflow or fall within the drilling nipple ormarine diverter for drilling to progress without interruption

Wellbore pressure fluctuations upon every jointed pipeconnection

Window

X

TVD

MWHH = 0.052 x d x TVD EMW = MW HH + AFP CIRCULATING

Pressure

M W H H

E M W

AFP

P o r e P r e s s u r e

F r a c t u r e P r e s s u r e

Drilling

(varies with depth)Reference SPE Textbook, Applied Drilling Engineering , Adam T. Bourgoyne, Jr. et al

D e p

t h

Returns must not overflow or fall within the drilling nipple ormarine diverter for drilling to progress without interruption

Wellbore pressure fluctuations upon every jointed pipeconnection

Figure 2.5 Depth vs. pressure.

2.2.3 Root Concepts of MPD

MPD is enabled by drilling with a closed and pressurized circulating fluids system. At theminimum, a rotating control device (RCD), drill string non-return valves (NRV), and a dedicatedchoke manifold are required. (The rig s existing choke manifold should not be used as a drillingchoke. Its role must be reserved for conventional well control.) This minimum system enables thedrilling decision-maker to view the whole of the circulating fluids system as one may a pressure

vessel.

Amounts of surface backpressure may be applied as needed to prevent continuous flow ofreservoir fluids to surface while drilling. When drilling with an essentially incompressible fluid,surface backpressure has an immediate impact on the wellbore pressure profile.

The equivalent weight of the mud in the hole at the time is thus determined:

Circulating (dynamic), EMW = MW HH + AFP

Not circulating (static), EMW = MW HH + BPSURFACE BACKPRESSURE

The ability to add varying amounts of surface backpressure when not circulating, that amountbeing roughly equal to the circulating annular friction pressure (AFP) when the last stand was drilledin, adds an important element to the equation. It also allows drilling nearer balanced and with lighter


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than conventional mud weights. With the mud in the hole at the time, the EMW may be adjusted with the rig s mud pump rates when circulating and desired amounts of surface backpressure applied when not circulating.

The result is MPDs most influential and valuable characteristic:

Circulating EMW = Static EMW

2.2.4 Variations of MPDEach of the four variations of MPD is applicable to specific drilling-related challenges or

hazards. On some complex wells, combinations of the variations may be required to better addressdrilling trouble zones from spud to total depth objective. Each variation has deepwater potential andunique application to complex drilling programs and enabling equipment is commercially availableto accommodate all types of offshore rigs:

Constant Bottom Hole Pressure (CBHP) is applicable to narrow or relatively

unknown drilling windows, high-pressure, high-temperature (HPHT) wells,pressure fluctuation-induced wellbore instability, ballooning/breathing, andcontrol-of-the-well scenarios.Pressurized Mud Cap Drilling (PMCD) is applicable to severe loss circulationand/or drilling into sour formations.Dual Gradie nt (DG), with or without a marine riser, is applicable to depletedformations and to avoid grossly overbalance associated with a tall column ofannulus returns in deepwater riser systems. Hydraulically speaking, DG tricks the

well into thinking the rig is closer than it is; removing some of the weight of mudand cuttings, creating two or more pressure vs. depth gradients via injection oflight liquids, subsea pumps, down-hole pumps, or combinations thereof in

annulus returns path.Returns Flow Control is simply drilling with a closed annulus returns systemimmediately under the rig floor for HES purposes only.

2.3 Solid Expandable Systems (SES)Solid Expandable Systems (SES) were initially developed because of a need to reduce drilling

costs, increase production of tubing-constrained wells, and to enable operators to access reservoirsthat could otherwise not be reached economically.

The last half of the 20 th century saw the age-old process of forming malleable metal into fit-for-purpose shapes transferred to oilfield tubular products and adapted for downhole applications in the

upstream sector of the oil and gas industry. As generally defined by the industry in its simplest form,expandable tubular technology is cold-drawing steel downhole.

Although the first related patent was issued in 1865, it wasnt until the mid -1900s that theindustry successfully expanded pipe in situ , e.g., downhole. At this time, operators in the formerSoviet Union successfully expanded corrugated pipe with pressure (hydro forming) and roller conesto patch openhole trouble zones. This transitional system and its relevant application furthermotivated the evolution of expandable technology.


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The nature of the wellbore itself dictates what expansion tools and systems are applicable, whether open hole or cased hole. Today, expandable technology is used to construct deeper,slimmer, and greater-production wells and used to repair or seal worn and damaged pipe.

In downhole applications, solid expandable technology reduces or eliminates the telescopic

profile of the wellbore (Figure 2.6). In the open hole, the technology extends casing intervals inpreparation for drilling through trouble zones or when an unplanned event in the wellbore requiressacrificing or compromising a casing point as designed in the drilling plan.

Figure 2.6 Slimming of wellbores through the use of solid expandable openhole systems.

In an openhole environment, the most common application runs a solid expansion system,expands it, and typically ties it back to the previous casing string. This structural approach facilitatesthe extension of the previous string of conventional casing while minimizing the slimming of the

well profile during well construction.

The type and size of system that is used in a project depends on the issues and conditions that

demand mitigating. Unexpected problems may require the application of a one-off installation, which is especially common in exploratory wells. Offset data can identify formation characteristicsthat may warrant planning in the system as a design contingency. Typical drilling problems that canbe mitigated with an expandable liner solution include:

Inadequate hole stability.Over-exposed hole as a result of drilling issues, equipment failures, prolongedtripping, etc.


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Over-pressured formations.Under-pressured formations.Close fracture gradient/pore pressure tolerance.Poor isolation across multiple zones.Remediation for casing that was inadvertently set shallow.

In contrast to a last resort application as discussed, expandable systems may be used as afundamental casing string as an integral part of the wells basis of design (BoD). This proactiveapproach enables the system to be installed over the trouble zone or above the zone to facilitate theinstallation of a conventional casing string over the trouble zone. With either scenario, the BoD ismaintained. Whether an expandable system is used as part of the plan or for contingency purposes,the technology saves hole size, compensates for unplanned events, and allows for flexibility in the

well-planning process.

2.3.1 Application of Mitigating Technologies to Solve Complex WellChallenges

The following a real well example illustrates the effective planning and application of thesetechnologies. This particular well is one of a set of wells to be drilled through some very complexformations near the foothills of a mountain range. The seismic and offset well information indicated:

Complex geology.Depth uncertainty due to seismic resolution.

Trajectory passing up, down, and cross dip.Uncertainty in type of hydrocarbons.

2.4 Purpose of Technical Limit Analysis

The initial well drilled in this environment required approximately 360 days to drill. Afterimplementing good drilling practices and without applying technology mitigants, this time wasreduced to 260 days. However, the subsequent technical limit analysis highlighted additionalopportunities to further reduce the drilling time. The purpose for the technical review of the wells tobe drilled was to understand:

What depth hazards are realized. What created the hazards.How the well design impacts hazards risk management.

The geotechnical environment.Practices and technology that were employed to mitigate the hazard.

What performance measurements were utilized. The framework for determining mitigating practices and technologies to:

o Reduce and manage hazards and the resultant risk.o Reduce future risks and well costs.

To provide future recommendations for alternative solutions.


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After reviewing the offset data, including 260 detailed daily drilling reports from the offset well,performance objectives were analyzed to determine:

The average time on the analogue well. Where the NPT has been expended.

How much time can be removed with improved practices and technologies. What the hazards were and why they occurred. Risk/consequence profiles of allhazards should be developed, which provide a baseline to derive a risk-assessedcost benefits analysis of the hazards mitigants.

A baseline for technical limit time iterations: sustaining learning.

The earth model (Figure ) illustrates the geological complexity of the environment where thesame formations are encountered several times by the perspective wellbore due to severe faults andgeophysical events that occurred during and subsequent to their deposition.

2008 Weatherford. All rights reserved.

Geo 2

Geo 3

Geo 4Geo 5

Geo 6

Geo 1

W1

W1

W1

W1

W1

W1

W1

Figure 2.7 Geological map of example well.


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Figure 2.8 and Figure 2.9 illustrate how Technical Limit Engineering using both good drillingpractices and a variety of cutting edge technologies can significantly reduce drilling time to totaldepth (TD) from 216 days to 115 days.

W1a: 3.502

Geo 2: 6,660

T/Cv: 7,728

Marker 1: 10,095

W1b: 11,004

W1a: 11,632

W1b: 11,851

Top Marker 1: 12,874

Top Cv: 13,407

Marker 2: 14,318Top Pay 1: 15,011 Md.

Definitions:

ILT : Invisible Lost Time, or in efficiencies such as controlled drillingRLT : ILT plus Wasted Time (Un necessary bit trips, casing set sh ort,

etc.) Techn ical Limi t removes all NPT an d RLT

Technical Limit:115 Days

Actual Time: 216days

Figure 2.8 Comparison of drilling curves with and without effective application of drilling hazard

mitigants.

PT, 4,410.3,66%

NPT, 618.5,9%

RLT, 1,670.3,25%

NPT, RLT, PT

PT NPT RLT

ProdcutiveTime,

4,410.25,47%

Total Time,

5,028.8,53%

Productive Time as a % of Total Time

Prodcutive TimeTotal Time

Figure 2.9 Comparison of productive time, NPT, and removable lost time to total drilling time.


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2.4.1 Defining SMART Well Objectives As previously discussed in Part 1 of this series, well planners must guard against developing

objectives that are not specific, measurable, achievable, relevant, and timely (SMART). SMART wellobjectives are essential to quality well plans. Too often the root cause of failure lies with objectivesthat are not initially aligned nor understood by the disciplines or stakeholders. Well planners must

guard against developing objectives that conflict and together are not achievable.

With this example project the following well objectives defined were in fact a set of goals:

Maintain below 2 inclination at casing point (~2,000 ft).Drill Section 1 formations to 6600 ft MD. Build angle from 2000 ft (KOP) to22 inclination.Drill Sections 3 and 4 to the top of pressure ramp to 13,000 ft MD. Directionaldrilling plan: Drill tangent section from 7000 ft to 11,400 ft, and then continue

with drop section with 1/100 ft DLS, keeping direction to the east.Run LWD tools to obtain accurate geological information.Keep the well vertical (less than 3 inclination) and maintain azimuth to reach thetarget according to the drilling plan.Drill, core, log, and isolate Target 1 high pressure and consider isolationcontingencies.Drill, core, log, and isolate Target 2 depleted formation and considercontingencies for high differential pressures and stress.Drill and complete both targets with non-damaging fluids.

In contrast to the previously stated goals, Table 2.2 lists well objectives that can be deemedSMART.

Table 2.2 SMART well objectives for the example well.Measure Key Uncertainty Comments Conflicts Actions

Overall Well Plan: Appraisal well 1: 17,000' TVD, 20,000' MD. Section 1: 20" Surface 2000' MD, Section 2: 16" at 6600'MD or 13 10,000' MD Intermediate, Section 3: Intermediate 13" or 11" at 13,000', Section 4: Protective DrillingLiner (?) 15,000'. Minimum 7" Production casting at TD.

HES metrics: contractorand company

Rig availability Three rigs meetavailability criteria, 2 havepoor IFO

Timing for best metricsrig

Investigate neededimprovements on otherrigs, training?

Lose concession Rig availability Must have at least 2000HHP and backup pumpfor target section

Only rig 2 has HHPrequirements, no zerodischarge capabilities

Investigate neededimprovements on otherrigs, training?

AFE approval Funding AFE Asset manager says over$100,000,000 is outsidebudget

Low cost well Need to prioritizeobjectives

Top quartile in regionalcost/well: Metrics

Well design Assets want simple, smalldiameter monobore toreduce cost.

Completions wants gaslift and smartcompletions

Need to prioritizeobjectives

Dry hole at location Well design Small monobore will notaccommodate sidetrack

Low Cost Well Need to prioritizeobjectives

Production rate Well design Completion productionrate targets

Small monobore holesize will notaccommodate minimumproduction rate, norcontingency risk of

Will need to fracture wellfor maximum rate, small

wellbore will notaccommodate HHP


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Measure Key Uncertainty Comments Conflicts ActionsOverall Well Plan: Appraisal well 1: 17,000' TVD, 20,000' MD. Section 1: 20" Surface 2000' MD, Section 2: 16" at 6600'MD or 13 10,000' MD Intermediate, Section 3: Intermediate 13" or 11" at 13,000', Section 4: Protective DrillingLiner (?) 15,000'. Minimum 7" Production casting at TD.

sidetrack and loss of holesize

Metrics, improved criticalpath time

Rock geomechanics Requires compilinggeomechanics log

Geologist tight holinglogs on prior well

Develop a plan for rockmechanics analysis logthat ensuresconfidentiality

Productivity index Formation sensitivity Reservoir engineerrequire OBM

Impedes loggingevaluation, no rigs havezero dischargecapabilities: Well cost

Align fluids withgeoscientists. Understandcost benefits ofrequirements

Achieving hole section:Could have collapse at upto 18 PPG, pore pressurenormal gradient in all

well sections

Drilling margin/faults, Tectonic stress

Could require drillingliner

Last well lost holesections and low cost

Could require twointermediate casingstrings: well cost

Minimum unscheduledevents and NPT (lessthan 20 % with no

wasted time): Hazards:ballooning,

Drilling margin/faults, Tectonic stress

Could require drillingliner

Low cost well, sidetrackcapability

Requires real timemonitoring, contingencyplans

Intersect target verticallyat optimum depth

High pressure requiringup to 18 PPG

Tight well path requiressignificant geo-steering:Cuttings beds and keyseats, high torque/drag

Low cost well Priorities drive costs

No doglegs, smoothhole. Final 22 degrees

Faults and rock strengthfor KOP

Need rock geomechanicscompressive strengthdata

Low cost well Need rockgeomechangicscompressive strengthdata for best fit BHA andbit design

Smooth hole, gentle drop

angle less than 3 degreesfor verticality in targetproduction intervals

Principle stress vectors:

direction and magnitude.

Need rock geomechanics

compressive strengthdata

Low cost well, sidetrack

capability andcontingencies for failure

Wellbore stability study

rock mechanics analysis with predicted breakouts

Successful cores and logsas well as isolation beforedrilling into depletedsecondary target

Pressure low (10 PPG) tohigh stress equivalence ofup to 18 PPG at base in

Very difficultenvironment. Must havemeans to see pressurestress ramps whiledrilling

Low cost well, sidetrackcapability andcontingencies for failure

Risk mitigant critical forhigh differential pressures

Intersect target atoptimum depth

High pressure to 18 PPG Tight well path requiressignificant geo-steering

Low cost well This priority drives wellcost prioritizeobjectives and consider

value of risk vs. benefitto well

Successful log evaluation DP conveyed logs ifnecessary

Require trips, impact wellbore stability, increasessuccess risk case

Low cost well Tradeoff is LWD: whatare the risk-adjusted cost& benefits?

Time Requires trips, impacts well bore stability,negatively impactssuccess risk case


Wellbore stability Requires trips, impacts well bore stability,negatively impactssuccess risk case



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2.5 Reducing Risk and Improving Drilling Time The following summarizes the opportunities that exist to improve the well economics through

the applications of the DwL, MPD (pressurized mudcap application) and SES technologies.

2.5.1 Application of DwC/DwLUsing DwC in the top hole section offers the following:

Ensures verticality.Ensures stability.Uses the rock strength that is well within range of cutter technology.Removes three days time.Enables the ability to extend shoe depth.

o Improves leak off tolerance for next hole section.o Simplifies drilling margins.

It should be noted that using DwL technology as a hole cleaning while drilling method, afterconventionally drilling the last two hole sections for the drilling liners, ensures that these linerssuccessfully reach its total depth. Additionally this application facilitates well stability under MPDconditions as well as minimizing running and cementing risks, lost time, NPT, and flat time.

To effectively evaluate the uncertainties of using each technology being considered, acomprehensive risk analysis must be preformed including the technology and its particularapplication within the well.

Table 2.3 is an excerpt of the risk analysis for the DwL.

2.5.2 Application of MPD (Pressurized Mudcap Drilling Method)Using the MPD pressurized mudcap drilling method from the top of the hole down offers the

following:

Eliminates risk of up to 33 days lost time: Risk adjusted cost benefit is at least afactor of 11 over conventional in top hole alone.Eliminates risk of losing over 13,500 bbls expensive oil-based mud in the tophole.Improves better control of confining stresses while accepting losses.

o Bit selection and performance.o Eliminate need of turbine and impregs especially where temperature is

not an issue.Ensures ability to utilize cheap, expendable water-based mud.

o Losses become non-consequential.o Cuttings cure loss zones.o Cap controls cavings.

Table 2.4 is an excerpt of the risk assessment for the pressurized mudcap drilling method of theMPD technology.


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18

Mitigating DrillingHazardsWithTechnologies

18

Table 2.3 Excerpt of risk assessment for the application of the DwC/DwL technology.

R i s k

C o n s e q u e n c e s

E x i s t i n g

M i t i g a t i o n s

i n

p l a c e

L i k e l

i h o o

d ( % P r o

b a b i l i t y )

o f O

c c u r r e n c e w

i t h

E x i s t

i n g

M i t i g a t

i o n s

( I N

P L A

C E )

L i k e l

i h o o

d R a n

k i n g

( 1 - 6 )

C o n s e q u e n c e

R a n

k i n g

( 1 - 6 )

R i s k R a n

k i n g

F a c t o r

R i s k R e s p o n s e

C h o i c e :

A c c e p t ,

M i t i g a t e , a

V o i

d

M i t i g a t

i o n s

C o s t o f


L i k e l

i h o o

d ( P r o

b a b i l i t y ,

% )

o f O

c c u r r e n c e w

i t h

M i t i g a n t s n e e d e d

i n p l a c e .

L i k e l

i h o o

d R a n

k i n g

( 1 - 6 )


R a n

k i n g

( 1 - 6 )

R i s k R a n

k i n g

F a c t o r

( w /

M i t i g a t

i o n s

N e e

d e d i n P l a c e

)

E x t r a

T i m e

i f e v e n t o c c u r s

( h r s )

E x t r a c o s t

i f t h e e v e n t

o c c u r s

R i s k e d T i m e

( h r s

)

R i s k e d C o s t

B e n e f

i t C o s t

R a t

i o

Comments

1.00 ole Section 2: 16" drilled out of 20"1.01 luid

oss inholesection

Nonproductivetime (NPT)

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills.

100% 1 6 6 A

1.02 Slight losses ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, appliedcontrolled drilling

100 % 1 6 6 A

1.03 Severe lossesresulting in25 days tocure, withseven daysto squeezeand drillout. Loss of15,000barrels ofoil-basemud.

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, appliedcontrolled drilling

100 % 1 3 3 V

Mitigate this risk as theoccurrence and consequences ofthe risk have not been a cceptableand in some cases resulted in losthole sections with high costs. Thenew mitigants to drill the 16"section with a drilling liner tomitigate losses and maintainstability. Rock compressivestrength is well below the design

limit of the drill shoe.

$ 2 5 0

, 0 0 0

1 % 6 3 8 6 0 0 . 0 0

$ 5 , 8

5 0 , 0

0 0

6.00 $ 5 8 , 5 0 0

2 3 1 6

. 6 %

The cost savings if theevents occur as beforeis: No loss of OBM:$3,000,000 plus 25days saved @$100,000/day plus 7days of cementremediation.

These columns represent the risk register . The combination of a risk by a single consequence is a risk event. First, identify the risk the what if? Migitants in place recognizeexiting practices. Each risk can have different consequences the so what? Probability of occurrence is based on data or experience. Ranking from the matrix, A ccept, Mitigate, ora V oid is suggested by color (red, green, yellow). Action is determined by the team. The new mitigant is described with the intent to reduce the probability of the risk occurring. Thediscrete cost of the new mitigant is indicated. The new ranking is based on the lower probability of the risk occu rring. The Consequence, in general, remains the same. Note theimprovement of the risk profile. Risk adjusted lost time and cost if the event still occurs. Normally the total non -productive time off the critical path to the time on the critical path.

Associated costs are the total daily cost of operations. This is the added value of the new mitigant represented by the discrete cost of the new mitigant as a function of the reduced risk exposu. This value for the worst ranked risk indicates that the mitigant has added value. Thus the overall risk is managed by the new mitigant.


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19


19

Table 2.4 Excerpt of risk assessment for the application of the pressurized mudcap drilling method of the MPD technology.

R i s k C o

n s e q u e n c e s

E x i s t

i n g

M i t i g a t

i o n s

i n

p l a c e

L i k e l

i h o o

d ( % P r o

b a b i l i t y )

o f O

c c u r r e n c e w

i t h

E x i s t

i n g

M i t i g a t

i o n s

( I N

P L A

C E )

L i k e l

i h o o

d R a n

k i n g

( 1 - 6 )


R a n

k i n g

( 1 - 6 )

R i s k R a n

k i n g

F a c t o r


C h o i c e :

A c c e p t ,

M i t i g a t e , a

V o i

d

M i t i g a t

i o n s

C o s t o f


L i k e l

i h o o

d ( P r o

b a b i l i t y ,

% )

o f O

c c u r r e n c e w

i t h


i n p l a c e .

L i k e l

i h o o

d R a n

k i n g

( 1 - 6 )


R a n

k i n g

( 1 - 6 )

R i s k R a n

k i n g

F a c t o r

( w /

M i t i g a t

i o n s

N e e

d e d i n P l a c e

)

E x t r a

T i m e


( h r s )

E x t r a c o s t

i f t h e e v e n t

o c c u r s

R i s k e d T i m e

( h r s

)

R i s k e d C o s t

B e n e f

i t C o s t

R a t

i o

Comments

1.00 ole Section 2: 16" drilled out of 20"1.01 luid

oss inholesection

Nonproductivetime (NPT)

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills.

100% 1 6 6 A

1.02 Slight losses ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, appliedcontrolled drilling

100 % 1 6 6 A

1.03 Severe lossesresulting in25 days tocure, withseven daysto squeezeand drillout. Loss of15,000barrels ofoil-basemud.

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, appliedcontrolled drilling

100 % 1 3 3 V

Mitigate this risk as theoccurrence and consequences ofthe risk have not been acceptableand in some cases resulted in losthole sections with high costs. Thenew mitigant will be water-basedmud and managed pressuredrilling.

$ 5 0 0

, 0 0 0

1 % 6 3 8 6 0 0 . 0 0

$ 5

, 8 5 0

, 0 0 0

6.00 $ 5 8 , 5 0 0

1 1 5 8

. 3 %

The cost savings if theevents occur as beforeis: No loss of OBM:$3,000,000 plus 25days saved @$100,000/day plus 7days of cementremediation.

These columns represent the risk register . The combination of a risk by a single consequence is a risk event. First, identify t he risk the what if? Migitants in place recognizeexiting practices. Each risk can have different consequences the so what? Probability of occurrence is based on data or experience. Ranking from the matrix, A ccept, Mitigate, ora V oid is suggested by color (red, green, yellow). Action is determined by the t eam. The new mitigant is described with the intent to reduce the probability of the risk occurring. Thediscrete cost of the new mitigant is indicated. The new ranking is based on the lower probability of the risk occurring. The Consequence, in general, remains the same. Note theimprovement of the risk profile. Risk adjusted lost time and cost if the event still occurs. Normally the total non -productive time off the critical path to the time on the critical path.



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Deepwater Horizon Study Group Working PaperMitigating Drilling Hazards With Technologies

20

Figure 2.10 indicates the areas of the well where the DwC and pressurized mudcap technologiesare applied to the well trouble zones.

Figure 2.10 Depth versus time drilling curves with DwC/DwL and pressurized mudcap drillingtechnologies applied in the upper hole sections.

2.5.3 Application of Solid Expandable Systems The application of either 7 in x 9 in openhole expandable liner (resulting in a post expanded

inside diameter of ~7 in) or a 8 in monobore openhole liner (resulting in a post expanded ID of8 in) allows a liner to be installed below the 9 in conventional casing string. This expandablesolution allows for mitigating the trouble zone while enabling the running a 7 in (or smaller) stringof conventional casing, adding an extra casing string without loss of hole size. However, within the8 in hole section (which requires under-reaming if the expandable liner is to be installed) theformation is extremely hard as was evidenced by:

Highly worn impregnated bits.Stabilizers out of gauge.Difficult conventional reaming, torque loading, drillstring stalling (not turbine),etc.

o Highly worn turbine bearings.o This is easily notable where there is a high percentage of sandstone in

cuttings.o Where pore pressure is lowest, overbalance is greatest.


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21


The following (Table 2.5) is an excerpt of the risk assessment for the Solid Expandable System(s) technology.

Table 2.5 Excerpt of risk assessment for the application of the SES technology.

R i s k

C o n s e q u e n c e s

E x i s t

i n g

M i t i g a t

i o n s

i n

p l a c e

L i k e l

i h o o d

( % P r o

b a b i l i t y )

o f O c c u r r e n c e w

i t h

E x i s t i n g

M i t i g a t

i o n s

( I N

P L A C E )

L i k e l i h o o

d R a n

k i n g

( 1 - 6

)


R a n

k i n g

( 1 - 6

)

R i s k R a n

k i n g

F a c t o r


C h o i c e :

A c c e p t , M

i t i g a t e , a

V o i

d


C o s t o

f M i t i g a t i o n s

L i k e l

i h o o d

( P r o

b a b i l i t y ,

% )

o f O c c u r r e n c e w

i t h


i n p l a c e .

L i k e l

i h o o d

R a n

k i n g

( 1 - 6

)


R a n

k i n g

( 1 - 6

)

R i s k R a n k

i n g

F a c t o r

( w /


N e e

d e d i n P l a c e

)

E x t r a

T i m e


( h r s

)

E x t r a c o s t i

f t h e e v e n t

o c c u r s

R i s k e d T i m e

( h r s

)

R i s k e d C o s t

B e n e f

i t C o s t

R a t

i o

Comments

1.00 xpandable liner for sidetrack operations1.01 tuck

pipe inhole

NPT butable toretrieve drillstringsuccessfully

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, spiral drillcollars

40% 2 6 7 A

1.02 NPT:retrieve drillstring byfishing

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, spiral drillcollars

25 % 2 4 5 A

1.03 iperrectrievabl stuck. Cut,

plug, andsidetrack,oss of

requiredhole size

ud program, losscirculation proceduresand materials, Blowoutprevention equipment,pit drills, appliedcontrolled drilling 25 % 2 3 4 V

Mitigate this risk as theoccurrence and consequences ofthe risk havie not been acceptableand in some cases resulted in losthole sections with high costs. Thenew mitigant will be to set theprior casing string with an

oversize shoe and use anexpandable drilling liner toconserve hole size.

$ 5 0 0

, 0 0 0

1 % 6 3 8 6.00 $ 4

, 0 0 0

, 0 0 0

0.96 $ 1 4 0

, 0 0 0

192 %

This indicates that notonly is the risk profileimproved, but in arisk adjusted basis, thecost of the new SETmitigant adds value tothe operation.

These columns represent the risk register . The combination of a risk by a single consequence is a risk event. First, identify the risk the what if? Migitants in place recognizeexiting practices. Each risk can have different consequences the so what? Probability of occurrence is based on data or experience. Ranking from the matrix, A ccept, Mitigate, ora V oid is suggested by color (red, green, yellow). Action is determined by the team. The new mitigant is described with the intent to reduce the probability of the risk occurring. Thediscrete cost of the new mitigant is indicated. The new ranking is based on the lower probability of the risk occ urring. The Consequence, in general, remains the same. Note theimprovement of the risk profile. Risk adjusted lost time and cost if the event still occurs. Normally the total non -productive time off the critical path to the time on the critical path.



22/25


22

3 ConclusionDHM begins with well planning. All drilling operations have risk that can never be fully

eliminated but it can be mitigated and managed. The key to mitigating and managing risk lies inunderstanding the importance of the stage-gated planning process, developing SMART objectives,

acknowledging and defining possible uncertainties and risks applied to practices and technologies. Well construction is a drilling function effort; excellence in performance is a multidisciplinary

responsibility. Complex wells require multi-disciplinary alignment to ensure and sustainperformance. Aligning objectives is necessary and critical to managing drilling hazards and achievingsuccessful well execution. All disciplines must understand the trade-offs of their requirements andhow the uncertainties of the earth model influence risk management and therefore the well design.

Attaining success with DHM depends on a cognizant and deliber ate recognition of the projectsrisks. If executed effectively, the process yields a comprehensive awareness that provides afoundation to not only mitigate and manage risk but optimize operations. The basic premise ofDHM is to eliminate, reduce, or prepare for risks and hazards by following a distinct process. Therisk assessment process should be applicable to and conducted for any operation. The processimplemented should be used to critically challenge each facet of the well design.

In the final analysis it is important to understand how practices and technologies can improvethe ability to mitigate and manage risk and improve the ultimate value of the well. Any mitigant mustdecrease the likelihood of the occurrence of any hazard. The risk profile and risk-adjusted costshould be financially beneficial to the overall operation. DHM begins with well planning andexcellence in performance is dependent on successfully applying mitigants to manage risks.

4 Acronyms and Definitions

Table 4.1 Drilling acronyms used in this paper. ii Acronym Definition

DAFP Circulating Annular Friction Pressure AFE Approved for Expenditure ALARP As Low As Reasonably PracticalBHA Bottom Hole AssemblyBOP Blow Out PreventerBOD Basis of DesignBUR Build up Rate

CBHP Constant Bottom Hole PressureCBU Circulating "Bottoms Up"CCI Cutting Carrying IndexDG Dual GradientDHM Drilling Hazards ManagementDLS Dog-Leg Severity (directional drilling)DP Drill Pipe

ii See a more complete list at http://en.wikipedia.org/wiki/List_of_oil_field_acronyms .
http://en.wikipedia.org/wiki/List_of_oil_field_acronymshttp://en.wikipedia.org/wiki/List_of_oil_field_acronymshttp://en.wikipedia.org/wiki/List_of_oil_field_acronymshttp://en.wikipedia.org/wiki/List_of_oil_field_acronyms


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23

Acronym DefinitionDwC Drilling with CasingDwL Drilling with LinersDWOP Drill the Well on PaperECD Equivalent Circulating DensityEMW Equivalent Mud WeightEOW (R) End of Well (Report)HAZOP Hazardous Operation (assessment session)HES Health, Environment, SafetyHHP Hydraulic Horse PowerHPHT High Pressure, High TemperatureIADC International Association of Drilling ContractorsID Inside DiameterIFO Income from OperationsILT Invisible Lost Time

JSA Job Safety AnalysisKOP Kick Off Point or Kick Off Plug

LCM Lost Circulation MaterialLWD Logging While DrillingM&E Mechanical and EfficiencyMD Measured DepthMOC Management of ChangeMPD Managed Pressure DrillingMWD Measurement While DrillingMW HH Mud Weight Hydrostatic PressureNPT Non Productive TimeOBM Oil-Based MudOD Outside DiameterPDC Polycrystalline Diamond Compact (bit)PMCD Pressurized Mud Cap DrillingPPG Pounds Per GallonPT Productive TimePWD Pressure While DrillingRA Risk AssessmentRCD Rotating Control DeviceRLT Removable Lost TimeROP Rate of PenetrationSES Solid Expandable SystemsSMART Specific, Measurable, Achievable, Relevant, TimelySPE Society of Petroleum Engineers

TD Total Depth TVD True Vertical DepthUE Unscheduled Events

VSP Velocity Seismic Profile WT Wasted Time


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24

Table 4.2 Key drilling definitions.

Term DefinitionBasis of Design The technical details, information and procedures necessary to plan and execute a well

Consequence Consequence is the result of a failure to prevent a risk event. There can be severalconsequences for any given risk of occurrence

Critical Path ofDrilling Operations

The planned execution sequential path of drilling and completion operations with thesteps necessary to successfully drill and complete an oil and gas well

Drilling Hazard A drilling hazard is any rotating or flat time incident that causes a deviation from thecritical operating path

Drilling HazardsManagement

Engaging the designs, practices, or technologies necessary to mitigate the risks ofdrilling operations

Drilling Margin The boundaries for the safe application of Equivalent Circulating Density between insitu pore pressure and/or stress equivalence, and the fracture gradient resulting from theoverburden at true vertical depth.

Drill the Well OnPaper A detailed exercise to communicate and vet the Basis of Design with stakeholders

EquivalentCirculating Density

The effective mud density expressed in pounds per square inch (or similar units such asmetrics) per true vertical foot of well depth (psi/foot) exhibited by a circulating fluid ata certain circulating rate in gallons per minute (or similar units such as metrics) againstthe formation that takes into account the pressure drop in the annulus above the pointof circulation due to friction and hydrostatic pressure

Fracture Gradient The amount of pressure, expressed in pounds per square inch (or similar units such asmetrics) per true vertical foot of well depth (psi/foot) that is required to inducefractures in rock at a given true vertical depth

Kick Tolerance

The maximum kick volume of fluid that can be taken into the wellbore and circulatedout without fracturing the formation at a weak point (shoe), thereby exceeding the leak-off, given a difference between the pore pressure and equivalent circulating mud densityin use

Leak Off

The amount of pressure, expressed in pounds per square inch (or similar units such asmetrics) per true vertical foot of well depth (psi/foot) that is exerted by a column ofdrilling fluid on the formation being drilled whereby fluid will continue to enter theformation, or leak off . This is the maximum pressure of equivalent circulatingdensity mud density that may be applied to the well during drilling operations

Management ofChange

A process that is designed to manage changes to: approved well objectives, Basis ofDesign, program, or procedure

Mitigant

A mitigant is any proactive use of best practices and/or technologies which reduces therisk of occurrence the hazard with an improved risk profile and risk adjusted costbenefits to the drilling operation. For the purpose of a risk assessment, mitigants arerelegated to what is currently being done in an operation

Morning Report The daily report summary of prior day operations

New Mitigant The risk event is represented by any added or new mitigation which reduces theprobability or likelihood of occurrence of any indicated risk and correspondingconsequence, or the risk event
http://www.glossary.oilfield.slb.com/Display.cfm?Term=formationhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=pressurehttp://www.glossary.oilfield.slb.com/Display.cfm?Term=annulushttp://www.glossary.oilfield.slb.com/Display.cfm?Term=rockhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=leak%20offhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=leak%20offhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=leak%20offhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=leak%20offhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=rockhttp://www.glossary.oilfield.slb.com/Display.cfm?Term=annulushttp://www.glossary.oilfield.slb.com/Display.cfm?Term=pressurehttp://www.glossary.oilfield.slb.com/Display.cfm?Term=formation


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5 References1. David Pritchard, Drilling Hazards Management: Excellence in Drilling Performance Begins

with Planning, World Oil, August 2010, 75-83. Also DHGS white paper.

2. David Pritchard, The Value of the Risk Assessment Process, World Oil, October 2010,43-52. Also DHSG white paper.

3. P. York, et al., Eliminating Non -Productive Time Associated with Drilling Trouble Zones(paper OTC 20220, presentation at the 2009 Offshore Technology Conference, Houston,

Texas, USA, May 4 7, 2009).

4. M.Al-Umran, et al., New 5 in. Solid Expandable Systems Provide Effective Technologyfor Successful Workover Project in Saudi Arabia (paper SPE 08057 presented at the 2008SPE Saudi Arabia Section Technical Symposium, Alkhobar, Saudi Arabia, May 10-12, 2008).

5. L. Jianhua, et al., Use of Liner Drilling Technology as a Solution to Hole Instability andLoss Intervals: A Case Study Offshore Indonesia (paper SPE/IADC 118806 presented atSPE/IADC Drilling Conference and Exhibition, Amsterdam, Netherlands, March 17-19,2009).

6. S. Nas, et al., Offshore Managed Pressure Drilling Experiences in Asia Pacific (paperSPE/IADC 119875 presented at SPE/IADC Drilling Conference and Exhibition,

Amsterdam, Netherlands, March 17-19, 2009).

7. Randy Scott et al., Pushing the Limit of Drilling with Casing (paper OTC 16568 presentedat the 2004 Offshore Technology Conference held in Houston, Texas, USA, May 3-6, 2004).

8. Liao Jianhua et al., Use of Liner Drilling Technology as a Solution to Hole Instability andLoss Intervals: A Case Study Offshore Indones ia (paper SPE/IADC 118806, presentationat the 2009 SPE/IADC Drilling Conference and Exhibition held in Amsterdam, TheNetherlands, March 17-19, 2009).

9. R. D. Watts et al., Particle Size Distribution Improves Casing -While-Drilling WellboreStrengthening R esults (paper SPE 128913 presented at the 2010 IADC/SPE DrillingConference and Exhibition held in New Orleans, Louisiana, USA, February 2-4, 2010).

10. C.J. Jablonowski, et al., The Impact of Rotating Control Devices on the Incidence ofBlowouts: A Case Study for Onshore Texas, USA (paper SPE133019 -MS, presented at the2010 Trinidad and Tobago Energy Resources Conference, Port of Spain, Trinidad, June 27-30, 2010).

mitigating drilling hazards with technologies

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