part 3 of dhm series-mitigating drilling hazards with technologies · 2011-02-14 · deepwater...

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

Abstract Integrating 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 improve

the risk profile and add value. This requires understanding how the risk assessment process can be applied to both practices as well as technologies. From a DHM perspective, added value also means improving the risk profile as well as understanding that any new or added mitigant must show positive cost and benefits from a risk adjusted perspective. Any new mitigant must first decrease the likelihood of the risk event occurring and the risk adjusted cost should be financially beneficial to the overall operation. It is therefore important to understand how technologies can improve the ability 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. He has extensive experience managing and supervising worldwide drilling and production operations. David has consulted for 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 audited over 40 Deepwater and HPHT global operations. David holds a Bachelor of Science in Petroleum Engineering from the University of Tulsa.

Deepwater Horizon Study Group – Working Paper Mitigating Drilling Hazards with Technologies

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Table of Contents 1 Reducing Risk Through Effective Application of “Fit for Problem” Technology .................... 3

2 Understanding the Mitigant – Well Construction Technologies ................................................... 3

2.1 Drilling with Casing (DwC)/Drilling with Liners (DwL) ....................................................... 3

2.2 Managed Pressure Drilling (MPD) ............................................................................................. 6

2.3 Solid Expandable Systems (SES) .............................................................................................. 10

2.4 Purpose of Technical Limit Analysis........................................................................................ 12

2.5 Reducing Risk and Improving Drilling Time.......................................................................... 17

3 Conclusion ........................................................................................................................................... 22

4 Acronyms and Definitions ................................................................................................................ 22

5 References ........................................................................................................................................... 25

Figures Figure 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 drilling

hazard mitigants. ................................................................................................................. 14

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

time........................................................................................................................................ 14

Figure 2.10 – Depth versus time drilling curves with DwC/DwL and pressurized mudcap

drilling 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 drilling

method 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 of “Fit for Problem” Technology

The many and varied technologies available to assist in drilling complex wells are often underutilized. In light of the current workloads imposed on today’s drilling engineers and well supervisors, 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, applying technology for technology’s sake is seldom the best approach especially when simply implementing good drilling practices may be the best solution to the current challenge.

As previously highlighted in the Part 11 and Part 22 the best strategy and most prudent approach

begins with SMART well objectives followed by a thorough understanding of the uncertainties and the most appropriate risk mitigants. Studies3 conducted over the past decade have shown that approximately 50 % of drilling hazards resulting in non-productive time (NPT) can be either avoided 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 use of drilling with casing (DwC)/drilling with liners (DwL), managed pressure drilling (MPD, or solid expandable liner technologies. These technologies are only a few of many from the drilling professional’s “tool box” and any one should not be considered as a “panacea” solution.

2 Understanding the Mitigant – Well Construction Technologies

Because multiple resources4, 5, 6 exist that detail the workings of these technologies, this article provides only a brief description for review. Rather than fixate on how the technologies work, the focus 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. This method of hazard management can be deployed to reduce risk in many hole sections or casing sizes and 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 the 1950s, it has been common in some areas of the world to drill in the final tubing string and cement in place with the drill bit still attached. Modern DwC started in the early 1990s and differs from previous applications in that it is not limited to the final string. To date, this technology has been used 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 running casing, including much of the circulation time involved, is removed. Connection time savings equate to 12 %, assuming 3.5 minutes for 90 ft drillpipe and 5 minutes for 40 ft casing with on-bottom rate of 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 involved

in operations such as reaming, circulating high viscosity pills, conductor cleanout runs, etc. There are other potential savings from unscheduled events, for example, hole collapse. Typical total time savings from DwC range from 30 % to 50 % of the time from section spud to leakoff test. Figure 2.2 shows an example of flat time reduction.

Figure 2.2 – Flat time reduction.


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2.1.2 Getting Casing to Bottom

DwC eliminates tripping drillstrings and conventional casing running operations and subsequently, deterioration of time-dependent formations does not exist. The fact that the casing is always 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 pipe tripping prevents the occurrence of these problems.

2.1.4 Drilling Depleted Zone and Overcoming Lost Circulation

Lost 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 being stuck pipe.8

It might appear that DwC would not be a good option because the casing could get stuck before

reaching 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 the frictional pressure losses, thus increasing the ECD. In fact, the results indicate DwC significantly reduces lost circulation. The exact mechanism that provides this benefit has not been scientifically proven, 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 mud solids 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 the

reduction 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 drilling trouble 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. The stiff assembly also is less prone to vibrations, reducing the mechanical impact damage on the borehole wall. Drillstring vibrations have been attributed to borehole stability problems and oval shape holes.

2.1.6 Improving Safety

Some potentially hazardous operations may be eliminated when using DwC. Drilling surface hole 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 is eliminating hammering operations. Loading and rigging up pile hammers is often considered to be one of the most hazardous operations carried out on the rig floor.


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2.1.7 Reducing Rental Costs

DwC 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 conventional drilling (Figure 2.3). The improvement ranges from 81 % to 134 %, averaging 110 %. A rule of thumb 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 employing a 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

-

100

200

300

400

500

600

Va

nn, ft

/min

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, mitigating drilling hazards, and to enable drilling otherwise technically or economically un-drillable high-complexity prospects. The Society of Petroleum Engineers (SPE) and the International Association of Drilling Contractors (IADC) offers this definition:

“MPD is an adaptive drilling process used to control precisely the annular pressure profile

throughout 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 avoid continuous influx of formation fluids to the surface. Any flow incidental to the operation will be safely contained using an appropriate process.

MPD process employs a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits, by proactively managing the annular hydraulic pressure profile.

MPD may include control of back pressure, fluid density, fluid rheology, annular fluid 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 drilling of what might otherwise be economically unattainable prospects.”

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


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Because MPD addresses NPT, the technology is of greatest potential benefit to offshore drilling

programs where cost of lost drilling time is much higher than onshore. Although MPD was been safely and efficiently practiced from all types of offshore rigs and produced the desired results in the process, 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 drilling decision-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 Applications

Drilling-related issues such as excessive mud cost, slow ROP, wellbore ballooning/breathing, kick-detection limitations, difficulty in avoiding gross overbalance conditions, differentially stuck pipe, risk of twist-off, and resulting well-control issues contribute to defining the offshore industry’s need for MPD technology. Kick-loss scenarios that frequently occur when drilling into narrow or relatively unknown downhole pressure environments also define a requirement to deviate from conventional methods. Excessive drilling flat time and health, environment, and safety (HES) issues further indicate the necessity for a technology that addresses the root causes.

2.2.2 Hydraulics of Conventional Drilling

Since 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 equivalent mud weight (EMW) or adjust the wellbore pressure profile is to change the speed of the rig’s mud pumps. This depth vs. pressure map (Figure 2.5) illustrates that the wellbore pressure profile fluctuates significantly with each jointed pipe connection in harmony with circulating annular friction pressure (ΔAFP).

When not circulating, the effective wellbore pressure is the mud weight hydrostatic head

pressure (MWHH). 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 MWHH and the ΔAFP.

EMW = MWHH + ΔAFP While drilling, if the annulus returns over flow the drilling nipple or marine diverter, a kick may

be occurring. If the returns fluid column falls, the fracture gradient of the open hole may have been exceeded. 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 = MWHH + AFPCIRCULATING

Pressure

MW

HH

EM

W

AFP

Pore

Pre

ssure

Fractu

re Pressu

re

Drilling

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

Dep

th

• Returns must not overflow or fall within the drilling nipple or

marine diverter for drilling to progress without interruption

• Wellbore pressure fluctuations upon every jointed pipe

connection

Window

X

TVD

MWHH = 0.052 x d x TVD EMW = MWHH + AFPCIRCULATING

Pressure

MW

HH

EM

W

AFP

Pore

Pre

ssure

Fractu

re Pressu

re

Drilling

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

Dep

th

• Returns must not overflow or fall within the drilling nipple or

marine diverter for drilling to progress without interruption

• Wellbore pressure fluctuations upon every jointed pipe

connection

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 the minimum, a rotating control device (RCD), drill string non-return valves (NRV), and a dedicated choke manifold are required. (The rig’s existing choke manifold should not be used as a drilling choke. Its role must be reserved for conventional well control.) This minimum system enables the drilling 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 of

reservoir 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 = MWHH + ΔAFP Not circulating (static), EMW = MWHH + ΔBPSURFACE BACKPRESSURE

The ability to add varying amounts of surface backpressure when not circulating, that amount being roughly equal to the circulating annular friction pressure (AFP) when the last stand was drilled in, 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 MPD’s most influential and valuable characteristic:

Circulating EMW = Static EMW

2.2.4 Variations of MPD

Each 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 address drilling trouble zones from spud to total depth objective. Each variation has deepwater potential and unique application to complex drilling programs and enabling equipment is commercially available to 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, and control-of-the-well scenarios.

Pressurized Mud Cap Drilling (PMCD) is applicable to severe loss circulation and/or drilling into sour formations.

Dual Gradient (DG), with or without a marine riser, is applicable to depleted formations and to avoid grossly overbalance associated with a tall column of annulus 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 mud and cuttings, creating two or more pressure vs. depth gradients via injection of light liquids, subsea pumps, down-hole pumps, or combinations thereof in annulus returns path.

Returns Flow Control is simply drilling with a closed annulus returns system immediately 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 reservoirs that could otherwise not be reached economically.

The last half of the 20th 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 wasn’t until the mid-1900s that the

industry successfully expanded pipe in situ, e.g., downhole. At this time, operators in the former Soviet Union successfully expanded corrugated pipe with pressure (hydro forming) and roller cones to patch openhole trouble zones. This transitional system and its relevant application further motivated 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 in preparation for drilling through trouble zones or when an unplanned event in the wellbore requires sacrificing 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 facilitates the 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 characteristics that may warrant planning in the system as a design contingency. Typical drilling problems that can be mitigated with an expandable liner solution include:

Inadequate hole stability.

Over-exposed hole as a result of drilling issues, equipment failures, prolonged tripping, 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 a

fundamental casing string as an integral part of the well’s basis of design (BoD). This proactive approach enables the system to be installed over the trouble zone or above the zone to facilitate the installation of a conventional casing string over the trouble zone. With either scenario, the BoD is maintained. 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 Well Challenges

The following a real well example illustrates the effective planning and application of these technologies. This particular well is one of a set of wells to be drilled through some very complex formations 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. After implementing good drilling practices and without applying technology mitigants, this time was reduced to 260 days. However, the subsequent technical limit analysis highlighted additional opportunities to further reduce the drilling time. The purpose for the technical review of the wells to be 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 all hazards should be developed, which provide a baseline to derive a risk-assessed cost 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 the

same formations are encountered several times by the perspective wellbore due to severe faults and geophysical 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 drilling practices and a variety of cutting edge technologies can significantly reduce drilling time to total depth (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: 14,318’ Top Pay 1: 15,011’ Md.

Definitions:

ILT: Invisible Lost Time, or inefficiencies such as controlled drilling

RLT: ILT plus Wasted Time (Unnecessary bit trips, casing set short,

etc.) Technical Limit removes all NPT and RLT

Technical Limit:

115 Days

Actual Time: 216

days

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

Prodcutive Time,

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 well objectives are essential to quality well plans. Too often the root cause of failure lies with objectives that 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) to 22° inclination.

Drill Sections 3 and 4 to the top of pressure ramp to ±13,000 ft MD. Directional drilling 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 the target according to the drilling plan.

Drill, core, log, and isolate Target 1 high pressure and consider isolation contingencies.

Drill, core, log, and isolate Target 2 depleted formation and consider contingencies 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 deemed

SMART. 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 13⅝ ± 10,000' MD Intermediate, Section 3: Intermediate 13⅝" or 11⅝" at ± 13,000', Section 4: Protective Drilling Liner (?) ± 15,000'. Minimum 7" Production casting at TD.

HES metrics: contractor and company

Rig availability Three rigs meet availability criteria, 2 have poor IFO

Timing for best metrics rig

Investigate needed improvements on other rigs, training?

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

Only rig 2 has HHP requirements, no zero discharge capabilities

Investigate needed improvements on other rigs, training?

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

Low cost well Need to prioritize objectives

Top quartile in regional cost/well: Metrics

Well design Assets want simple, small diameter monobore to reduce cost.

Completions wants gas lift and smart completions

Need to prioritize objectives

Dry hole at location Well design Small monobore will not accommodate sidetrack

Low Cost Well Need to prioritize objectives

Production rate Well design Completion production rate targets

Small monobore hole size will not accommodate minimum production rate, nor contingency risk of

Will need to fracture well for maximum rate, small wellbore will not accommodate HHP


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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 13⅝ ± 10,000' MD Intermediate, Section 3: Intermediate 13⅝" or 11⅝" at ± 13,000', Section 4: Protective Drilling Liner (?) ± 15,000'. Minimum 7" Production casting at TD.

sidetrack and loss of hole size

Metrics, improved critical path time

Rock geomechanics Requires compiling geomechanics log

Geologist tight holing logs on prior well

Develop a plan for rock mechanics analysis log that ensures confidentiality

Productivity index Formation sensitivity Reservoir engineer require OBM

Impedes logging evaluation, no rigs have zero discharge capabilities: Well cost

Align fluids with geoscientists. Understand cost benefits of requirements

Achieving hole section: Could have collapse at up to 18 PPG, pore pressure normal gradient in all well sections

Drilling margin/faults, Tectonic stress

Could require drilling liner

Last well lost hole sections and low cost

Could require two intermediate casing strings: well cost

Minimum unscheduled events and NPT (less than 20 % with no wasted time): Hazards: ballooning,

Drilling margin/faults, Tectonic stress

Could require drilling liner

Low cost well, sidetrack capability

Requires real time monitoring, contingency plans

Intersect target vertically at optimum depth

High pressure requiring up to 18 PPG

Tight well path requires significant geo-steering: Cuttings beds and key seats, high torque/drag

Low cost well Priorities drive costs

No doglegs, smooth hole. Final 22 degrees

Faults and rock strength for KOP

Need rock geomechanics compressive strength data

Low cost well Need rock geomechangics compressive strength data for best fit BHA and bit design

Smooth hole, gentle drop angle less than 3 degrees for verticality in target production intervals

Principle stress vectors: direction and magnitude.

Need rock geomechanics compressive strength data

Low cost well, sidetrack capability and contingencies for failure

Wellbore stability study rock mechanics analysis with predicted breakouts

Successful cores and logs as well as isolation before drilling into depleted secondary target

Pressure low (10 PPG) to high stress equivalence of up to 18 PPG at base in

Very difficult environment. Must have means to see pressure stress ramps while drilling

Low cost well, sidetrack capability and contingencies for failure

Risk mitigant critical for high differential pressures

Intersect target at optimum depth

High pressure to 18 PPG Tight well path requires significant geo-steering

Low cost well This priority drives well cost – prioritize objectives and consider value of risk vs. benefit to well

Successful log evaluation DP conveyed logs if necessary

Require trips, impact well bore stability, increases success risk case

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

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


Wellbore stability Requires trips, impacts well bore stability, negatively impacts success 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/DwL

Using 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, after

conventionally drilling the last two hole sections for the drilling liners, ensures that these liners successfully reach its total depth. Additionally this application facilitates well stability under MPD conditions 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, a

comprehensive risk analysis must be preformed including the technology and its particular application 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 a factor of 11 over conventional in top hole alone.

Eliminates risk of losing over 13,500 bbls expensive oil-based mud in the top hole.

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 the

MPD technology.

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

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ces

Exis

tin

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itig

atio

ns

in

pla

ce

Lik

eli

ho

od

(%

Pro

ba

bil

ity)

of

Occu

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ce w

ith

E

xis

tin

g M

itig

ati

on

s (I

N

PL

AC

E)

Lik

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od

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kin

g

(1-6

)

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en

ce

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kin

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(1-6

)

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k R

ank

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r

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esp

on

se C

ho

ice:

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t, M

itig

ate

, aV

oid

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igati

on

s

Co

st o

f M

itig

ati

on

s

Lik

eli

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od

(P

rob

ab

ilit

y,

%)

of

Occu

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ce w

ith

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itig

an

ts n

eed

ed

in

pla

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eli

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od

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kin

g

(1-6

)

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en

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an

kin

g

(1-6

) R

isk

Ran

kin

g F

acto

r (w

/

Mit

igati

on

s N

eed

ed

in

Pla

ce)

Ex

tra T

ime i

f eve

nt

occu

rs

(hrs

)

Ex

tra c

ost

if

the e

ven

t o

ccu

rs

Ris

ked

Tim

e

(hrs

)

Ris

ked

Co

st

Ben

efi

t C

ost

R

ati

o

Comments

1.00 Hole Section 2: 16" drilled out of 20"

1.01 Fluid

loss in hole

section

Non

productive time (NPT)

Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills.

100% 1 6 6 A

1.02 Slight losses Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills, applied controlled drilling

100 % 1 6 6 A

1.03 Severe losses resulting in

25 days to cure, with

seven days to squeeze

and drill out. Loss of

15,000 barrels of

oil-base mud.

Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills, applied controlled drilling

100 % 1 3 3 V

Mitigate this risk as the occurrence and consequences of the risk have not been acceptable and in some cases resulted in lost hole sections with high costs. The new mitigants to drill the 16" section with a drilling liner to mitigate losses and maintain stability. Rock compressive strength is well below the design limit of the drill shoe.

$250

,000

1 % 6 3 8

600.0

0

$5,8

50,

000

6.00

$58,5

00

2316

.6 %

The cost savings if the events occur as before

is: No loss of OBM: $3,000,000 plus 25

days saved @ $100,000/day plus 7

days of cement remediation.

•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 recognize exiting practices. •Each risk can have different consequences – the “so what?” •Probability of occurrence is based on data or experience. •Ranking from the matrix, Accept, Mitigate, or aVoid 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. •The discrete 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 the improvement 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 exposure. 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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Table 2.4 – Excerpt of risk assessment for the application of the pressurized mudcap drilling method of the MPD technology.

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Ex

isti

ng

Mit

igati

on

s in

p

lace

Lik

eli

ho

od

(%

Pro

ba

bil

ity)

of

Occu

rren

ce w

ith

E

xis

tin

g M

itig

ati

on

s (I

N

PL

AC

E)

Lik

eli

ho

od

Ran

kin

g

(1-6

)

Co

nse

qu

en

ce

Ran

kin

g

(1-6

)

Ris

k R

ank

ing

Facto

r

Ris

k R

esp

on

se C

ho

ice:

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t, M

itig

ate

, aV

oid

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igati

on

s

Co

st o

f M

itig

ati

on

s

Lik

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od

(P

rob

ab

ilit

y,

%)

of

Occu

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ce w

ith

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itig

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ts n

eed

ed

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(1-6

)

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an

kin

g

(1-6

) R

isk

Ran

kin

g F

acto

r (w

/

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igati

on

s N

eed

ed

in

Pla

ce)

Ex

tra T

ime i

f eve

nt

occu

rs

(hrs

)

Ex

tra c

ost

if

the e

ven

t o

ccu

rs

Ris

ked

Tim

e

(hrs

)

Ris

ked

Co

st

Ben

efi

t C

ost

R

ati

o

Comments

1.00 Hole Section 2: 16" drilled out of 20"

1.01 Fluid

loss in hole

section

Non

productive time (NPT)

Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills.

100% 1 6 6 A

1.02 Slight losses Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills, applied controlled drilling

100 % 1 6 6 A

1.03 Severe losses resulting in

25 days to cure, with

seven days to squeeze

and drill out. Loss of

15,000 barrels of

oil-base mud.


100 % 1 3 3 V

Mitigate this risk as the occurrence and consequences of the risk have not been acceptable and in some cases resulted in lost hole sections with high costs. The new mitigant will be water-based mud and managed pressure drilling.

$500

,000

1 % 6 3 8

600.0

0

$5,8

50,0

00

6.00

$58,5

00

1158.3

%

The cost savings if the events occur as before

is: No loss of OBM: $3,000,000 plus 25

days saved @ $100,000/day plus 7

days of cement remediation.


Deepwater Horizon Study Group – Working Paper Mitigating Drilling Hazards With Technologies

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

Figure 2.10 – Depth versus time drilling curves with DwC/DwL and pressurized mudcap drilling

technologies applied in the upper hole sections.

2.5.3 Application of Solid Expandable Systems

The application of either 7⅝ in x 9⅝ in openhole expandable liner (resulting in a post expanded inside diameter of ~7½ in) or a 8½ in monobore openhole liner (resulting in a post expanded ID of 8⅝ in) allows a liner to be installed below the 9⅝ in conventional casing string. This expandable solution allows for mitigating the trouble zone while enabling the running a 7 in (or smaller) string of conventional casing, adding an extra casing string without loss of hole size. However, within the 8½ in hole section (which requires under-reaming if the expandable liner is to be installed) the formation 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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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.

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Mit

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s in

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Lik

eli

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(%

Pro

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of

Occu

rren

ce w

ith

E

xis

tin

g M

itig

ati

on

s (I

N

PL

AC

E)

Lik

eli

ho

od

Ran

kin

g

(1-6

)

Co

nse

qu

en

ce

Ran

kin

g

(1-6

)

Ris

k R

ank

ing

Facto

r

Ris

k R

esp

on

se C

ho

ice:

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t, M

itig

ate

, aV

oid

Mit

igati

on

s

Co

st o

f M

itig

ati

on

s

Lik

eli

ho

od

(P

rob

ab

ilit

y,

%)

of

Occu

rren

ce w

ith

M

itig

an

ts n

eed

ed

in

pla

ce.

Lik

eli

ho

od

Ran

kin

g

(1-6

)

Co

nse

qu

en

ce R

an

kin

g

(1-6

) R

isk

Ran

kin

g F

acto

r (w

/

Mit

igati

on

s N

eed

ed

in

Pla

ce)

Ex

tra T

ime i

f eve

nt

occu

rs

(hrs

)

Ex

tra c

ost

if

the e

ven

t o

ccu

rs

Ris

ked

Tim

e

(hrs

)

Ris

ked

Co

st

Ben

efi

t C

ost

R

ati

o

Comments

1.00 Expandable liner for sidetrack operations

1.01 Stuck

pipe in hole

NPT but

able to retrieve drill

string successfully

Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills, spiral drill collars

40% 2 6 7 A

1.02 NPT:

retrieve drill string by

fishing

Mud program, loss circulation procedures and materials, Blowout prevention equipment, pit drills, spiral drill collars

25 % 2 4 5 A

1.03 Pipe

irrectrievably stuck. Cut,

plug, and sidetrack,

loss of required

hole size


25 % 2 3 4 V

Mitigate this risk as the occurrence and consequences of the risk havie not been acceptable and in some cases resulted in lost hole sections with high costs. The new mitigant will be to set the prior casing string with an oversize shoe and use an expandable drilling liner to conserve hole size.

$500

,000

1 % 6 3 8 96.00

$4,0

00,0

00

0.96

$14

0,0

00

192 %

This indicates that not only is the risk profile

improved, but in a risk adjusted basis, the

cost of the new SET mitigant adds value to

the operation.



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3 Conclusion

DHM 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 in understanding 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 sustain performance. Aligning objectives is necessary and critical to managing drilling hazards and achieving successful well execution. All disciplines must understand the trade-offs of their requirements and how the uncertainties of the earth model influence risk management and therefore the well design.

Attaining success with DHM depends on a cognizant and deliberate recognition of the project’s

risks. If executed effectively, the process yields a comprehensive awareness that provides a foundation to not only mitigate and manage risk but optimize operations. The basic premise of DHM is to eliminate, reduce, or prepare for risks and hazards by following a distinct process. The risk assessment process should be applicable to and conducted for any operation. The process implemented 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 improve

the ability to mitigate and manage risk and improve the ultimate value of the well. Any mitigant must decrease the likelihood of the occurrence of any hazard. The risk profile and risk-adjusted cost should be financially beneficial to the overall operation. DHM begins with well planning and excellence 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 Practical

BHA Bottom Hole Assembly

BOP Blow Out Preventer

BOD Basis of Design

BUR Build up Rate

CBHP Constant Bottom Hole Pressure

CBU Circulating "Bottoms Up"

CCI Cutting Carrying Index

DG Dual Gradient

DHM Drilling Hazards Management

DLS 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_acronyms


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Acronym Definition DwC Drilling with Casing

DwL Drilling with Liners

DWOP Drill the Well on Paper

ECD Equivalent Circulating Density

EMW Equivalent Mud Weight

EOW (R) End of Well (Report)

HAZOP Hazardous Operation (assessment session)

HES Health, Environment, Safety

HHP Hydraulic Horse Power

HPHT High Pressure, High Temperature

IADC International Association of Drilling Contractors

ID Inside Diameter

IFO Income from Operations

ILT Invisible Lost Time

JSA Job Safety Analysis

KOP Kick Off Point or Kick Off Plug

LCM Lost Circulation Material

LWD Logging While Drilling

M&E Mechanical and Efficiency

MD Measured Depth

MOC Management of Change

MPD Managed Pressure Drilling

MWD Measurement While Drilling

MWHH Mud Weight Hydrostatic Pressure

NPT Non Productive Time

OBM Oil-Based Mud

OD Outside Diameter

PDC Polycrystalline Diamond Compact (bit)

PMCD Pressurized Mud Cap Drilling

PPG Pounds Per Gallon

PT Productive Time

PWD Pressure While Drilling

RA Risk Assessment

RCD Rotating Control Device

RLT Removable Lost Time

ROP Rate of Penetration

SES Solid Expandable Systems

SMART Specific, Measurable, Achievable, Relevant, Timely

SPE Society of Petroleum Engineers

TD Total Depth

TVD True Vertical Depth

UE Unscheduled Events

VSP Velocity Seismic Profile

WT Wasted Time


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Table 4.2 – Key drilling definitions.

Term Definition

Basis 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 several consequences for any given risk of occurrence

Critical Path of Drilling Operations

The planned execution sequential path of drilling and completion operations with the steps 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 the critical operating path

Drilling Hazards Management

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

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

Drill the Well On Paper

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

Equivalent Circulating Density

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

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

Kick Tolerance

The maximum kick volume of fluid that can be taken into the wellbore and circulated out 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 density in use

Leak Off

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

Management of Change

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

Mitigant

A mitigant is any proactive use of best practices and/or technologies which reduces the risk of occurrence the hazard with an improved risk profile and risk adjusted cost benefits to the drilling operation. For the purpose of a risk assessment, mitigants are relegated 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 the probability or likelihood of occurrence of any indicated risk and corresponding consequence, or the risk event

http://www.glossary.oilfield.slb.com/Display.cfm?Term=formation

http://www.glossary.oilfield.slb.com/Display.cfm?Term=pressure

http://www.glossary.oilfield.slb.com/Display.cfm?Term=annulus

http://www.glossary.oilfield.slb.com/Display.cfm?Term=rock

http://www.glossary.oilfield.slb.com/Display.cfm?Term=leak%20off


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5 References

1. 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 ½ in. Solid Expandable Systems Provide Effective Technology for Successful Workover Project in Saudi Arabia” (paper SPE 08057 presented at the 2008 SPE 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 and Loss Intervals: A Case Study Offshore Indonesia” (paper SPE/IADC 118806 presented at SPE/IADC Drilling Conference and Exhibition, Amsterdam, Netherlands, March 17-19, 2009).

6. S. Nas, et al., “Offshore Managed Pressure Drilling Experiences in Asia Pacific” (paper SPE/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 presented at 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 and Loss Intervals: A Case Study Offshore Indonesia” (paper SPE/IADC 118806, presentation at the 2009 SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, March 17-19, 2009).

9. R. D. Watts et al., “Particle Size Distribution Improves Casing-While-Drilling Wellbore Strengthening Results” (paper SPE 128913 presented at the 2010 IADC/SPE Drilling Conference 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 of Blowouts: A Case Study for Onshore Texas, USA” (paper SPE133019-MS, presented at the 2010 Trinidad and Tobago Energy Resources Conference, Port of Spain, Trinidad, June 27-30, 2010).

part 3 of dhm series-mitigating drilling hazards with technologies · 2011-02-14 · deepwater...

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