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Defining Technology for Exploration, Drilling and Production August 2010

www.worldoil.comGulf Publishing Company

NORTH AMERICAN OUTLOOK Drilling rebounds, led by shales GOM rig market outlook

SAND CONTROL TECHNOLOGY

DRILLING HAZARD MANAGEMENT

DEVELOPING THE BARNETT

DRILLING HAZARD MANAGEMENT

3 Part Series

Drilling hazard management: Excellent performance begins with planningPart 1 of 3: Misalignment of well objectives can complicate mitigation efforts and induce drilling hazards by limiting the ability to apply adequate hydraulic horsepower and to manage ECD.

David Pritchard, Successful Energy Practices International; Patrick L. York, Scott Beattie and Don Hannegan, Weatherford

DRILLING

A drilling hazard is defined as any event off the critical path of drilling operations. Drilling hazard manage-ment focuses on wellbore stability and consequential hazards such as stuck pipe, fluids loss and equivalent circulat-ing density (ECD) management. These events lead to non-productive drilling time in the least case, or catastrophic wellbore failure and loss of well control in the worst cases. Drilling hazard man-agement requires understanding the un-certainty of the drilling margin: i.e., the safe applied ECD between the in situ pore pressure and/or stress equivalence and the fracture gradient as a result of the overburden.

Complex wells require multidisci-plinary alignment to ensure and sus-tain performance. Aligning objectives is necessary to manage drilling hazards and associated mechanical risk critical to successful well execution. For exam-ple, geological uncertainties may require the ability to sidetrack a hole, yet a slim monobore solution is required to reduce drilling costs. These objectives usually conflict. It is important to understand disciplinary tradeoffs necessary to ensure drilling performance.

BASIC PRACTICESDrilling hazard management (DHM)

is the practice of managing the me-chanical and efficiency risk of all drill-ing operations. (Within this article, we will deal only with DHM related to the risk of mechanical success, not risks as-sociated with health, safety and the en-vironment.) Managing these risks re-quires applying the best practices and mitigating technologies to successfully reduce the risk profile while improving the risk-adjusted cost of applying such

mitigants successfully. Because hazards may include mechanical failure and hu-man error in addition to geology, under-standing the totality of drilling data is necessary to avoid inducing risks and to enable implementation of the most ap-plicable mitigation measures.

One such example of DHM is simply to apply casing seat optimization to the maximum uncertainties of the drilling margin predictions. Predictions are al-ways uncertain in the Earth model, but a well can be planned accordingly. Plac-ing the seat at the maximum safe ECD point of the overburden fracture gradient ensures that the next hole section can be drilled to maximum depth and reduces the risk of issues such as ballooning in the next interval.

Another example involves the prac-tice of planning an increase in mud

weight at the base of an intermediate casing string before drilling out the shoe, especially in high-pressure/high- temperature operations, Fig. 1. Mud is usually weighted up because higher pressures are anticipated at greater depths, but this practice actually masks drilling conditions and negatively im-pacts drilling performance by increas-ing the confining stress of the mud weight column. This increase also cre-ates unnecessary bit wear, resulting in premature trips with associated swab and surge that further impact wellbore stability. This practice is often defended as the safest approach, but in reality, a safer and more effective action would be to drill out the casing shoe with the same mud weight as was used to set the casing. This should be followed with a full leak-off test to obtain the safest

20,0000 8 10 12

Mud weight, ppg14 16 18 20

18,000

16,000

14,000

12,000

1983

10,000

TVD,

ft

8,000

6,000

4,000

2,000

0

1985 2001 2007

Fig. 1. Plotting mud weight versus vertical depth for four historical wells shows the evolution of mud weighting schemes from the 1980s to the present.

August 2010 World Oil

Originally appeared in:August 2010 issue, pgs 75-84. Posted with permission.

DRILLING

ECD that the next hole section can tol-erate, and then drilling ahead, raising mud weight as conditions dictate.

Another DHM example involves the uncertainty of pore pressure prediction.

This uncertainty can lead drillers to ex-ceed the drilling margin, or the safe enve-lope that can be drilled without danger of well control events, fluid losses, balloon-ing or fracturing of the well.

MULTIDISCIPLINARY PLANNING Alignment of multidisciplinary ob-

jectives begins with a stage, gated well-planning process. The initial phase of the process is where the well is formulat-

Well objective Measure Key uncertainty Comments Conflicts Actions

HSE incident free Contractor and toperator HSE metrics

Rig availability Three rigs meet availability criteria, two have poor incident-free operations record

Timing for best-metrics rig

Investigate needed training andimprovements on other rigs

Drill first quarter 2010 Lose concession Rig availability Must have at least 2,000 hydraulic hp (hhp) and backup pump for target section

Only Rig 2 has hhp requirements, no zero-discharge capabilities

Investigate needed training and improvements on other rigs

Authorization-for-expenditure (AFE) approval

Funding AFE Asset manager says over $100 million is outside of budget

Low-cost well Need to prioritize objectives

Low-cost well Top quartile in regional cost/well (metrics)

Well design Assets want simple, small-diameter monobore to reduced cost

Completions engineers want gas lift and intelligent completions

Need to prioritize objectives

Ability to sidetrack well

Dry hole at location

Well design Small monobore will not accommodate sidetrack

Low-cost well Need to prioritize objectives

Production rates of 10,000 bopd

Production rate Well design Completion production rate targets

Small monobore will not accommodate minimum production rate

Will need to fracture well for max. rate, small wellbore will not accommodate hhp

Primary geological target: 12,000 ft TVD

Intersect target at optimum depth

Well path—faults Tight well path requires significant geosteering (cuttings beds and key seats, high torque/drag)

Low-cost well Priorities drive well cost

Secondary geological target: 11,750 ft TVD

Intersect target at optimum depth

Well path—faults Tight well path requires significant geosteering

Low-cost well Priorities drivewell cost

Core secondary target

Successful core for future evaluation

Target 2 depth Requires trips, impacts wellbore stability, increases success risk case

Low-cost well Priority drives well cost: What is the overall cost/benefits for the well?

Run conventional logs on drill pipe (DP) in extended reach/horizontal

Successful log evaluation

DP-conveyed logs Requires trips, impacts wellbore stability, increases success risk case

Low-cost well Tradeoff is LWD: What are the risk-adjusted cost/benefits?

Time Requires trips, impacts wellbore stability, increases success risk case


Wellbore stability

Requires trips,impacts wellbore stability, increases success risk case


Drill five additional wells if successful on same footprint

Successful logs and production test

Production test Well path and footprint must consider future wells

Low-cost well and future development

Tradeoff is future development cost

Ensure wellbore stability

Achieving hole section

Drilling margin/faults

Could require drilling with liner

Lost well hole sections

Could require two intermediate casing strings (well cost)

Minimum unscheduled events (hazards: ballooning, susceptible shales) and NPT

Drilling margin/faults

Could require drilling with liner

Low-cost well and sidetrack capability

Requires real-time monitoring and contingency plans

Ensure top-quartile rotating performance

Improved critical-path time (metrics)

Rock geomechanics

Requires compiling geomechanics log

Geologists won’t release logs on prior well

Develop a plan for rock log that ensures confidentiality

No formation damage

Productivity index Formation sensitivity

Reservoir engineer requires oil-based mud

Low-cost well, impedes logging evaluation, and no rigs have zero-discharge capabilities

Align fluids with geoscientitists; under-stand costs/benefits of requirements

Overall well plan: appraisal well—12,000 ft TVD, 20,000 ft MD; extended reach horizontal well—surface, intermediate casing at 10,000 ft TVD for stability, productivity to TVD; section 1—surface, section 2—intermediate, section 3—production.

TabLe 1. Typical project objectives and alignment process where conflicts are obvious


DRILLING

ed and objectives are determined. Well objectives should be specific, measur-able, achievable, relevant and timely.

Often the root cause of failure lies with objectives that are not initially aligned and understood by the disciplines or stakeholders. Well planners must guard against developing objectives that are not measurable, often conflict, and are not mutually achievable. The following ob-jectives for a 12,000-ft TVD, 15,000-ft MD directional well do not follow the well objective criteria listed above:

• Right-size initial flow capabilities• Adequate hole size for evaluation,

coring and completion• Completions free of formation

damage• “Rigless” intervention capabilities• Minimal complexity• Directional well with a target on-

bottom radius of 200 ft• Multiple targets• Design life• Good reservoir surveillance• Provision for a future sidetrack• Minimal number of casing strings• Small, low-cost monobore• Optimization of costs• Ability to frac stimulate the well• ESP artificial lift system.For example, a small wellbore does

not lend itself to fracture stimulation, has limited if any automated reservoir surveillance capabilities, and has limited sidetrack capabilities. Furthermore, the number of casings necessary to reach TD may prevent fracturing, high initial production rates and optimum installa-tion of artificial lift systems. Maintain-ing a stable wellbore becomes especially challenging in directional sections with small hole size, which prevents the drill-er from applying enough horsepower to clean the hole. A small hole also com-plicates the ability to slide and achieve a smooth hole.

These design objectives induce wellbore stability issues and can impact the following issues:

• Poor drilling performance as a re-sult of reduced hydraulic pumping rates

• Bit wear• Bottomhole steering difficulties,

with excessive geosteering creating a tor-tuous well path

• Inability to apply mud weight and effectively manage ECD in a slimhole environment.

The objectives listed above for this well result in many conflicts too dif-ficult to manage, and thus cannot suc-cessfully be achieved in the same well.

Misalignment of objectives can compli-cate mitigation efforts and often results in inducing drilling hazards by limiting the ability to apply adequate hydraulic horsepower and to manage ECD.

ALIGNING OBJECTIVESDeveloping specific, measurable,

achievable, relevant and timely objectives requires alignment from all stakeholder disciplines to determine which well design alternatives can best be accomplished. This multidisciplinary process requires understanding the tradeoffs, conflicts and compromises that are necessary between the “nice-to-haves,” “wants,” “needs” and “must haves.” Prioritizing objectives is the first step of a process to ensure initial dis-ciplinary alignment.

Mapping a process to define ranges of measures for the objectives is the ini-tial step in the process. This process is facilitated by capturing the ideas and committing to an auditable trail to en-sure decision quality. Table 1 shows an objective alignment process where all the objectives meet the above criteria. Further qualification and quantifica-tion of the objectives are required, with the desired outcome being a prioritized list of objectives, after which the design process begins. DHM cannot occur until, at a minimum, objectives are pri-oritized, which leads to alternative well design considerations.

Failure to align objectives at the onset of well planning usually results in execu-tion issues that are counterproductive to good performance and sustained learn-ing. As an example, excessive geosteering can complicate the well path and actually create drilling hazards. Target boxes must be agreed on in the initial well planning stages and ensured during execution. A target box is a window around the en-tire directional section that limits or pre-scribes the limits of geosteering.

Although a large amount of geosteer-ing may be agreed to by the stakeholders, there is a tradeoff in the risk of successful execution and, at the minimum, a nega-tive impact on performance and well cost. Many things can change, such as the design of the bit and BHA. Multiple BHA and bit combinations are necessary to achieve this objective, requiring trips and inducing wellbore instability. All of these tradeoffs must be understood, quantified and risk-assessed to ensure multidisciplinary alignment and ulti-mate decision quality.

Examples such as this are also where total well engineering comes into play,

as opposed to “widget” engineering—engineering a single product or service that does not consider the total well and its objectives. A bit designed for a build-and-hold angle does not work well when geosteering is required, nor does a tight or locked assembly to ensure holding angle, even with adjustable stabilization. These individual “widget” engineering designs are in conflict.

IMPACT OF UNCERTAINTIESUncertainties drive risk in everything.

For example, the weather is an uncer-tainty. If the objective is to play golf, the more that is known about the forecast, the more narrow the range of uncer-tainty. The same philosophy applies to managing hazards and risk for any drill-ing and completion operation.

It is first necessary to understand how uncertainties impact risk. Uncertainties represent the unknowns in any drilling operation. An important aspect of un-certainties is to know whether they can be eliminated by way of decisions, or if at least their range can be narrowed. Eliminating or narrowing uncertain-ties is a multidisciplinary process. De-cisions to eliminate uncertainties can include the rig selection process, post-ing a locked basis of design or deciding bottomhole targets and locking them into the well path.

The uncertainties that create the most problems and ancillary risks relate to the drilling margin. At the onset, establishing the safe drilling margin is an unknown prediction of pore pressure and fracture gradient. While predictions may come from many sources, they are never abso-lute. If the plan is to “nail” predictions to ensure good drilling performance, then success will not be sustained.

Risk occurs at the boundaries of the margin. For example, if the ECD is too high, fluid losses with varying conse-quences can occur. If the mud weight is too low, well control can be lost, also with varying consequences. In the plan-ning phases, the key to narrowing the drilling margin’s range of uncertainty is to ensure that predictions are as reliable as possible and are adjusted with actual his-torical data, such as the mud weight that was applied in a well where fluid losses actually occurred. There are many other techniques that can be used, including improving predictions while drilling, such as D exponents (drilling exponents normally compiled in mud logs).

For the planning phase, once the pre-dictions are as accurate as possible, alter-


DRILLING

native models can be developed that deal with the well objectives and uncertainties, and then manage the risk or hazard.

The first step toward managing haz-ards and risk, then, is to narrow the range of drilling uncertainties by devel-oping a multidisciplinary uncertainty management plan. This plan should be developed in concert with specific, measurable, achievable, relevant and timely objectives in the initial concept phase of planning.

Consider the objectives listed in Table 2 for a hypothetical well, which conform to the requirement of being specific, measurable, achievable, relevant and timely. For these objectives, the key uncertainties are the cost of well to best accomplish them; the production rate range and the productivity index of the reservoir; drilling hazards such as fluids losses and stuck pipe; the height and thickness of the Target 1 reservoir; and the ability to geosteer within the tight target box. The last two uncertainties

dictate alternative well models.Table 2 illustrates how these uncer-

tainties can impact the models (Fig. 2) and the resolutions required to deter-mine the best-fit model for the final well design. The design of any well alterna-tive begins with the recognition that the uncertainties of the drilling mar-gin must be honored. Each casing seat must address the maximum force it can exert against the fracture gradient with safe tolerance at its vertical depth of de-ployment. The summation of the forces must balance; that is, the force of the ap-plied ECD must equal the force exerted by the overburden fracture gradient of the earth in the wellbore.

Ignoring force balance when setting casing will result in a casing seat that is not at optimum depth and that, there-fore, will not facilitate an optimum depth for drilling the next hole section. This deficit continues to compound with each successive casing seat. This is especially critical in narrow-margin

drilling operations, especially in HPHT and deepwater environments. In the lat-ter, the loss of overburden due to water depth plays a critical role in the top hole sections of the well.

Figure 3 depicts the optimum place-ment of casing seats that are normally inserted to the top of salt in a subsalt deepwater environment. Applying this methodology enables the optimum depth of each casing string, minimizing the number of casing strings required to complete the well. Managing the uncer-tainty of the drilling margin minimizes the occurrence of boundary risks and should be an initial principle of well plan-ning and drilling hazard management.

Figure 4 shows the “stacking” effect created by the failure to optimize cas-ing seats in the deepwater environment. It also indicates where the casing seats should be to optimize the uncertainties of the drilling margin.

In narrow-drilling-margin opera-tions, the challenge is to optimize casing

Objective Uncertainty Model 1 Model 2 Model 3 Model 4 Conflicts, comments, requirements

Low cost (less than $5 million)

Requires budgetary estimates for all models

Needs budgetary cost estimates, this model being the most cost effective, but limits depth of artificial lift (gas lift mandrels)

Least expensive; smaller casings

Moderately expensive, but size of casing may prohibit lift capabilities

Most expensive

Further engineering to determine casing sizes needed to meet cost goals, hazards management and lift requirements

Target 2 pore pressure

Pore pressure in open hole in Target 2

This model does not allow for any casing contingency of the margin, which will be very difficult to manage while drilling deeper

This model does not allow for any casing contingency of the margin and cannot be managed while drilling deeper

Allows for isolation of Target 1 while drilling Target 2

Allows for isolation of Target 1 while drilling Target 2

This known hazard requires further engineering; consider designing for maximum casing sizes, but if the Target 2 reservoir pressure is not as depleted as suspected, it could be possible to drill without the liner; design must accommodate this hazard

Rig schedule Rig may not have enough hp to execute this hole sec-tion (hole cleaning and hookload)

Evaluate all models for maximum hookload and optimum hole cleaning rates for the given BHAs and fluid systems

Target 1 production of 0–5,000 bopd

Casing might not be large enough to provide production rate criteria

Casing might not be large enough to provide production rate criteria

Casing might not be large enough to provide production rate criteria

This model should provide for rate criteria and hazard management

All models should be evaluated for rate capabilities

Remaining in target box for Target 1

Geosteering; hole cleaning

Slim hole will com-plicate hole cleaning hydraulics and ability to geosteer

Hole cleaning capabilities should be evaluated for all models to avoid inducing hazards

Gas lift at 8,000 ft TVD (min.) to 9,000 ft TVD (max. for max. drawdown)

Casing sizes need to be evaluated

Improves lift capabilities; deeper and large casing

Improves lift capabilities; deeper and large casing

Lift capacity should be evaluated for each casing size and the deeper capabilities of Models 3 and 4

TabLe 2. Developing an uncertainty management plan for the well models in Fig. 2


DRILLING

seats despite the fact that predictions of the drilling margin boundaries (fracture gradient on the high side, pore pressure on the low side) are never accurate, due to the complexity of the Earth model. Any particular casing string must be designed for its depth as if predictions are absolute, and casing specifications must have a design tolerance to drill and set deeper if conditions dictate. This is why actual drilling conditions must be monitored and why it is important to understand “well listening” as a neces-sary condition of casing seat optimiza-tion. Planned depth becomes the maxi-mum predicted depth, plus more if hole conditions dictate. The contingency becomes a shallower setting depth. It is critical to ensure that the applied ECD plus safe tolerance is optimized for the given vertical depth, as dictated by ac-tual drilling conditions.

A useful predictive tool is pressure while drilling (PWD), coupled with ahead-of-the-bit trend predictions such as D exponents and seismic data. How-ever, even tools such as PWD and seis-mic data will not predict stress, and there is a distinct difference between stress and pore pressure. Stress is a vector and is imposed on the borehole by variables such as tectonics, faults or creeping salt diapers. These vectors can be quite dif-ferent from pore pressure both in mag-nitude and in direction.

Pore pressure can be normal, yet stress can be much higher, but both re-quire the same solution to stabilize the borehole: casing or mud weight. The uncertainty of this dynamic is critical in HPHT and deepwater environments. One reliable predictor of stress is D exponent trends, which represent the specific energy supplied to the drilling string and to the bit as well as the total of dynamic drilling conditions.

Casing optimization begins with the design and ends with understanding and properly interpreting actual drilling conditions to arrive at the correct set-ting depth. In terms of drilling hazard management, a mistake often made is to set the casing at a predetermined depth regardless of drilling conditions. Casing seat tolerance not high enough for the next hole section results in the prema-ture setting of another string of casing or drilling liner. This makes all risks more difficult to manage and routinely results in expending unnecessary casings. The typical mitigant is then to set the liner or full string of casing and hope for bet-ter results, shifting the uncertainties and

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,5008 9 10 11 12 13 14

TVD

(bel

ow k

elly

bus

hing

), ft

Pressure/fluid densities, ppg

Fracture gradient Pore pressure mid-supra salt

Top of salt ~ 6,700 ft

String 1 designcasing seat

Leak-off for String 2

Seafloor

String 2 design casing seat

Source: US patentapplication 12635511

Fig. 3. Optimum casing seat placement in a subsalt deepwater environment.

Surface casing: 95⁄8-in. set at 3,000 ft TVD/MD

Intermediate casing: 7-in. set at 9,000 ft TVD/MD

Kickoff point (KOP): 9,500 ft TVD/MDBuildup rate (BUR): 3°/100 ftlong radius Target 2: Est. 11,000–11,250 ft TVD

Target 2: Est. 11,000–11,250 ft TVD



Production string: 5½-in.to surface

Target 1: Est. 11,750–12,000 ft TVD(17,000 ft MD)




Model 1

Model 2

Surface casing: 7-in. set at 3,000 ft TVD/MD

KOP: 8,550 ft TVD/MD


Intermediate casing: 5½-in. set at 8,500 ft TVD/MD

Tangent section forgas lift beginning at9,000 ft TVD



Model 3




Intermediate casing: 7-in. set at 8,500 ft TVD/MD

Model 4



Production string: 7-in.to surface

Intermediate casing: 11¾ in. set at 8,500 ft TVD/MD

95⁄8-in. liner

Fig. 2. Example well models for the objectives listed in Table 2


DRILLING

risk yet deeper. The shallower the depth at which the hazard can be managed, the better the risk profile, drilling perfor-mance and cost, and the safer the well.

NEXT INSTALLMENTPart 2 of this series will address risk

management and avoidance through proactive interpretation of real-time data, or “well listening.” Listening to the well while drilling is fundamental, and is de-fined simply as recognizing, integrating and correctly interpreting all drilling dy-namics, weight on bit, rotational speed, ECD and shale shaker cuttings to assist in making the correct proactive decisions during operations. Whereas the advent of real-time data while drilling has in some cases become a “crutch” for drillers, result-ing in misinterpretation of issues such as background gas, this technology can also assist in well listening and, thus, facilitate correct decision making and application of best practices. WO

THe aUTHORS

David Pritchard is a pe-troleum engineer with 40 years of industry experi-ence, including manage-ment and supervision of worldwide drilling and production operations. He has consulted for an array of national and in-ternational independents,

major companies and service providers. He has conducted technical audits and developed well plans leading to improved well execution for complex and HPHt wells. As owner of Prit-chard Engineering and Operating, Mr. Pritchard developed, participated in and operated a num-

ber of oil and gas properties in the ArkLatex re-gion of the us, resulting in the successful dis-covery of over 500 Bcf of natural gas reserves. He holds a Bs degree in petroleum engineering from the university of tulsa.

Pat York is the Director of Commercialization and Marketing for Weatherford’s solid Expand-ables and Drilling Hazard Mitigation product/service lines. He has 38 years of oil and gas industry experience. Before joining Weather-ford, Mr. York was Vice President of Commer-cialization and Marketing for Enventure global technology after tenures with Halliburton and Dresser Atlas. He earned a Bs degree in elec-trical engineering at Northwestern state uni-versity in 1972 and pursued his MBA degree there in economics and management before launching his oilfield career.

Scott Beattie has 22 years of oilfield service ex-perience. After spells with Halliburton and Baker Oil tools, he has spent the past 14 years with Weatherford in various technical and operational roles, primarily supporting drilling technologies. Mr. Beattie’s latest assignment is in Kuala Lum-pur, Malaysia, as global Business unit Manager for Drilling with Casing. Mr. Beattie is regarded as a subject matter expert in casing-drilling appli-cations and engineering and is a key member of Weatherford’s Drill Hazard Mitigation team. He is a co-inventor of several onshore and subsea casing-drilling technologies.

Don Hannegan is the Drilling Hazard Mitigation technology Development Manager for Weath-erford. He received World Oil’s 2004 Innovative thinker Award for his role in conceiving and de-veloping specialized equipment and concepts applicable to managed pressure drilling of chal-lenging and complex wells. He also was an sPE Distinguished Lecturer for 2006/2007, and is a charter member of the IADC uBO/MPD Committee and a founding officer of the Arkan-sas sPE section. He was recently appointed by the university of texas Petroleum Engineering Extension service (PEtEX) to serve as lead au-thor of a textbook to be titled Drilling Hazard Mitigation Tools & Technology.

Shallow waterflow predicted

Hydrocarbons predictedbetween String 3 and

top of salt

Conventional String 4


ConventionalString 2


Optimum seat for String 1

Optimum seat for String 2

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,5008 9 10 11 12 13 14

TVD

(bel

ow k

elly

bus

hing

), ft

Pressure/fluid densities, ppg

Seafloor

Top of salt ~ 6,700 ft

Fracture gradient Pore pressure mid-supra salt

Source: US patentapplication 12635511

Fig. 4. “Stacking” effect of non-optimized casing seat placement versus optimized placement in a subsalt deepwater environment.

Article copyright © 2011 by gulf Publishing Company. All rights reserved. Printed in u.s.A.

Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.

ADVANCES IN DRILLINGSpECIAL FoCuS:

Drilling hazard management: The value of risk assessmentPart 2 of 3: Correctly interpreting drilling dynamics enables operators to make the right proactive decisions during operations.

David Pritchard, Successful Energy Practices International; Patrick L. York, Scott Beattie and Don Hannegan, Weatherford Intl.

Attaining success with drilling hazard management (DHM) depends on recog-nition of the project’s risks. If executed effectively, the process yields a compre-hensive awareness that provides a foun-dation not only to mitigate risk but also to optimize operations. Risk assessment can be conducted for any operation. This article presents a flexible, iterative process that allows evaluation of planned mitigations that may create further risks. The implementation of this process can be used to critically challenge each facet of the well design.

Risk assessment should be applied at the following stages of the well planning process:

• Analysis: Evaluating design alter-natives for potential risks, hazards and benefits facilitates selection of the best approach.

• Design: The “basis of design” doc-ument provides specifics of the selected alternative and requires more focused evaluation.

• Execution: Risk assessments of all procedures, logistics, communica-tions, etc., should be conducted to en-sure that all risks are managed, to help minimize non-productive time and to sustain performance.

• For any change in the scope of the operation, the “management of change” document should be accompanied by a risk assessment of any new procedures, practices or technologies. (Within this article, we will deal only with risk of me-chanical success and efficiency risk, not risks associated with health, safety and the environment.)

Three alternative responses succinctly sum up how risk can be managed: accept, mitigate or avoid. Accepting a risk means that the likelihood and consequence of the risk event actually happening ranks

so low that it is an acceptable risk to un-dertake. This likelihood is commonly referred to as “as low as reasonably prac-tical” (ALARP). Mitigating means that the risk, as currently understood, is not acceptable and requires new or addition-al intervention. These new mitigations can come in the form of best practices, policies, procedures, techniques and technologies that better manage the risk. Avoiding usually requires revising the well design or mitigant in place or elimi-nating a step or task.

Using a risk matrix as a guidance tool enables the team to select any action that it determines to be reasonable and appropriate for the operation. A matrix provides a vehicle for documenting and organizing what is important to better understand the risk profiles of the opera-tions and manage accordingly. Decisions are guided by company policies, rules or regulations, as well as those of the rel-evant regulatory authorities.

PREPARATIONFactual information, a clear scope and

well-defined objectives are needed to con-duct a focused risk assessment. The first step of the process is to perform due dili-gence and collect all pertinent data avail-able. Adequate data collection should in-clude the most current information from all sources and stakeholders. Data can come from multiple sources including, but not limited to, local, regional and global well histories, reports, studies and personal experiences.

Risk assessment success depends on the quality and range of the participants’ knowledge and experience. A broad knowledge base and a wide range of ex-pertise produce better results. Drilling engineering peers and personnel of other disciplines, such as geoscientists and reser-

voir and production engineers, should be integral sources of input during discussion and planning. Providers of critical services should also be included in the process.

The degree of rigor applied to the risk assessment process should be commensu-rate with the complexity of the well. Al-though the process can be tedious, it be-gins by defining the scope of each separate risk assessment session, the sum of which make up the process. All stakeholders in-volved need to provide their expertise; it is important for the stakeholders of various disciplines to fully understand the impact of their own objectives, procedures and requirements and to be prepared to brain-storm on any given operational task.

Understanding the scope of each ses-sion allows the stakeholders to use their own experiences and knowledge to dis-cern possible and probable risks and haz-ards. Asking “what if ” opens the session to speculative scenarios. If, for example, the session scope is risk assessment of tripping the drillstring, the “what ifs” would include such risks as stuck pipe, loss of circulation and swabbing. Partici-pants prepared to bring their experiences and knowledge to identify risks and haz-ards help the team use time efficiently, stay within the scope, and compile a comprehensive assessment.

CONDUCTING RISK ASSESSMENT SESSIONS

The initial risk assessment session should be conducted in a multidisci-plinary environment to collect risks and associated consequences from the stake-holders. All participants should be given an opportunity to identify their risks and consequences, which can be accomplished through simple brainstorming. Once the “what ifs” are identified, consequences can be determined by asking “so what.”

Originally appeared in:

October 2010 issue, pgs 43-52. Posted with permission.

OctOber 2010 World Oil

SpECIAL FoCuS ADVANCES IN DRILLING

Identification of potential risks and their consequences constitutes the risk regis-ter—i.e., the full list of “what ifs” and “so whats” associated with all operations.

Adherence to a few basic rules can help ensure an effective session. They include appointing an unbiased facilita-tor and an excellent scribe; reviewing the risk assessment tool and its capabilities; and defining and communicating the session’s scope before beginning. In addi-tion, it is important to maintain reason-able time limits for sessions; experience suggests that anything over two hours can be counterproductive. The risk reg-ister should be completed offline by the engineer or another person responsible for the project or well. Do not debate or wordsmith the brainstorming session; simply allow each person to offer his or her ideas and record them in the register. Work out granularity and details offline. The idea of a brainstorming session is to record, simply and concisely, the risks and associated consequences that collec-tively constitute the risk register.

RISK ASSESSMENT PROCESSThe risk assessment process is dynamic

and should be continually reviewed and updated with the most current informa-tion. Because a consequence can also be-come a new risk, the assessment process can be somewhat circular in nature. For example, if the risk is fluid loss and the consequence is stuck pipe, this conse-quence becomes a new risk that generates a new consequence, such as that the pipe becoming irretrievably stuck. The key to addressing circular issues is managing the worst-case risk event first. This approach usually resolves circular issues and the original risk itself. The risk then eventual-ly becomes mitigated and thus managed.

Sometimes risk can be superfluous, or deemed so by some of the stake-holders. For example, a driller might be concerned about the risk of sticking a wireline tool given hole conditions, while a geologist might not think it is a problem. Nevertheless, these risks should always be recorded and evaluated. The process, particularly if the worst-case risk events are evaluated first, often removes the superfluous issues by default.

Another issue that sometimes arises focuses on the costs used to determine the risk-adjusted value of a new mitigant. This issue should be raised in the early, brainstorming risk assessment sessions, but only using rough numbers, since these sessions should be high-level discus-sions. Dwelling on minutia at this point leads to losing sight of the scope. If more granularity is required, a subsequent risk-assessment session can be scoped, com-municated to all stakeholders, and con-ducted on that singular focus. Over time, granularity and objectivity improves, but keeping the multidisciplinary brain-storming sessions at a high level is neces-sary to establish an initial baseline.

The risk assessment process should also determine and justify tradeoffs among geoscientists, reservoir engineers, production engineers and drilling en-gineers. Accommodating stakeholders from each of these disciplines is funda-mental to the process and one of the rea-sons why it is necessary to assess any risk mitigant. Total cost of ownership means that the various disciplines understand the tradeoffs that occur in well planning designs and, ultimately, execution of the well. For example, directional well targets in slimhole profiles have specific risks as-sociated with hole cleaning. The geosci-entists need to understand this issue and

how the associated risks impact the cost of the well. Risk assessments become a decision quality tool and therefore assist in evaluating alternative well models.

The risk matrix. Acceptable forms of risk matrices can range from a very sim-ple categorization of risk by high, medi-um and low risk of occurrence to a more granular tabular matrix for probability on one axis and severity of consequence on the other. In general, the more granu-lar the matrix, the more valuable it is in terms of defining, ranking and managing risks. Table 1 depicts a typical industry risk matrix.

The risk matrix can be adjusted for levels of likelihood or probability and costs. Identifying costs associated with consequences is important to evaluate the added value and risk-adjusted costs of any new mitigant. The only exception is for health, safety and environmental (HSE) risk, because it is not possible to monetize the value of human life. Adjustments to the matrix axis should be based on rel-evant best fits for any given project. For example, if an operation is in deep water, costs should be those that are relevant to the operation itself. Probabilities are more subjective, but percentages of occurrence should be based on the experience and knowledge of, and agreed to by, the team conducting the risk assessment.

In general, the same matrix should be used for successive operations at a given project or well, to provide continuity, so long as the relative values remain repre-sentative of the project or well over time. If these values change significantly, then a new matrix may be warranted.

The risk assessment process tool. It is important to capture risks in

Probability Likelihood indices

> 40% 1 Likely

Dec

reas

ing

likel

ihoo

d

6 5 4 3 2 1

20−40% 2 Occasional 7 6 5 4 3 2

10−20% 3 Seldom 8 7 6 5 4 3

5−10% 4 Unlikely 9 8 7 6 5 4

< 5% 5 Remote 10 9 8 7 6 5

< 1% 6 Rare 10 10 9 8 7 6

Consequence indices (examples can be adjusted for local costs)

Increasing consequence/impact

6 5 4 3 2 1

Incidental Minor Moderate Major Severe Catastrophic

Consequence description (rig or equipment damage/downtime, mechanical damage/downtime)

Half day lost ($100K)

Day lost ($100K−$250K)

Loss of hole section

($250K−$1M)

Loss of more than 1 hole section

($1M−$5M)Loss of well ($2M−$20M)

Loss of rig (> $20M)

TAbLE 1. Typical industry (success) risk assessment matrix



a tool that can be used to conduct and record the entire risk assessment pro-cess. The process must be auditable and sustainable. Table 2 represents a typical

industry risk assessment tool populated with step-wise aspects of the process. The table uses actual examples to illus-trate key points.

EXECUTION PHASE AND WELL LISTENING

In the execution phase of well opera-tions, DHM begins with understanding

Hole section 4: 12–14-in. sectionRisk 1: Fluid loss in hole section

1.01 1.02 1.03 1.04 1.05 1.06

Consequences Non-productive time

Slight losses Severe losses re-sulting in 4 days to cure, squeeze

and drill out

Whole mud losses resulting in loss of hole

section and re-quiring sidetrack

Well control Blowout

Existing mitigation(s) in place Mud program, lost-circulation procedures and materials, BOP equipment, pit

drills

Mud program, lost-circulation procedures and materials, BOP equipment, pit drills, applied

controlled drilling


controlled drilling


controlled drilling


controlled drilling

Mud program, lost-circulation procedures and materials, BOP equipment, pit

drills

Likelihood of occurrence with existing mitigation(s) in place1 100% 100% 40% 100% 10% 5%

Likelihood (ranking 1–6) 1 1 2 1 4 5

Consequence (ranking 1–6) 6 6 3 3 2 1

Risk ranking factor2 6 6 4 3 5 5

Risk response choice: accept, mitigate, avoid

Accept Accept Avoid Avoid Mitigate Mitigate

Mitigation(s) needed3 Add pressure-while-drilling

(PWD) for proactive ECD management

Add pressure-while-drilling






Cost of mitigation(s) needed $500,000 $500,000 $500,000 $500,000

Likelihood of occurrence with mitigation(s) needed in place 20% 5% 1% 1%

Likelihood (ranking 1–6) with mitigation(s) needed in place 3 5 6 6

Consequence (ranking 1–6) with mitigation(s) needed in place 3 3 2 1

New risk ranking factor4 5 7 7 6

Extra time if event occurs, hr 96 96 96 73

Extra cost if event occurs $4 million $4 million $3 million $3 million

Risked time, hr5 19.20 4.80 0.73 0.74

Risked cost5 $800,000 $200,000 $30,000 $30,000

Benefit-to-cost ratio6 1.60 7.60 0.54 0.24

Comments This indicates that not only is the risk profile improved, but also, on a risk-adjusted basis, the cost of the new mitigant

adds value to the operation.

This indicates that not only is the risk profile improved, but also, on a risk-adjusted basis, the cost of the new mitigant

adds value to the operation.

This further justifies the new

mitigant.

This further justifies the new

mitigant.

1 Probability percentage of occurrence based on data or experience. 2 Ranking from the risk matrix; risk response choice is suggested by color, and action is determined by the team.3 With intent to reduce the probability of the risk occurring.4 With needed mitigation(s) in place, based on lower probability of the risk occurring (consequence generally remains the same); not improvement in risk profile.5 Risk-adjusted lost time and cost if the event still occurs (normally, total NPT off the critical path to the time on the critical path); associated costs are the total daily cost of operations.6 Added value of the new mitigant represented by its discrete cost as a function of reduced risk; the value for the worst-ranked risk indicates that the mitigant has added value.

TAbLE 2. Typical industry risk assessment tool



and making the correct proactive deci-sions regarding the totality of the drilling dynamics. The art of “listening to the well” involves simply recognizing, integrat-ing and correctly interpreting all drilling dynamics—weight on bit, drillstring ro-tational speed, equivalent circulating den-sity (ECD) and shale shaker cuttings—to assist in making the correct decision while executing drilling operations.

For example, indicators that the ECD is too low include the following:

Unexpectedly high rate of penetra-tion (ROP). A mud weight that is too low can have the net effect of removing the force at the bit, allowing the forma-tion being drilled to fail more easily, thus increasing ROP.

Torque/drag increase. Removal of mud weight force can cause the formation to collapse inward, thereby creating lateral forces on the bit, BHA and drillstring.

Cavings (particularly concave or splintered). Recognizing the types of cuttings over the shaker is critical to drilling data interpretation. Cuttings from a shale section where the wellbore is approaching failure will characteristi-cally appear concave (the shape of the hole) or splintered.

Flowrate increase. Decreased force of the mud weight can create underbal-anced conditions, allowing fluid influx into the wellbore.

Shut-in drill pipe pressure and/or well control. This is an obvious condi-tion of well control events or formations trying to feed into the wellbore.

Drilling break gas failing to “fall out” after circulating. This indicates in situ gas feeding into the wellbore from a permeable gas horizon.

BHA drift (principal stress vectors). Pseudo-induced stress can be caused by tectonics, salt diapers, faults, etc. Stress can be quite different from pore pres-sure in magnitude and is a vector. This phenomenon can have the net effect of trying to force the BHA in a principal direction if not correctly balanced with mud weight. Recognizing the difference between stress and pore pressure while drilling is crucial to interpreting dynam-ic drilling data.

Hole fill-up (sloughing or collaps-ing hole). Hole collapse can result in fill when off bottom and is quite common in softer formations.

Indicators of excessively high ECD include the following:

Unexpectedly low ROP. If the mud weight is too high, it can have the net ef-fect of adding confining force at the bit,

making the formation being drilled more difficult to penetrate; thus the ROP de-creases with poor performance.

High bit wear. Extraordinary mud weight force creates more confining stress on the rock, making the rock more difficult to drill.

Overly wet shale. Mud weight that is too high increases the instability of the shale section. Shale is not permeable but does respond to wetting through ionic exchange, much the same as clay on the ground that cracks when dry, then swells when hydrated. Overly wet shale reduces the net effect of inhibition, regardless of the drilling fluid. Even oil-based systems are never 100% water free.

Fluid loss. Mud weight that is too high creates unnecessary fluid losses and differential sticking, and exacerbates the risk of fracturing softer formations.

Indicators of other hazards include the following:

D exponents (changing drillability trends). This quantity represents real-time drilling analogs of specific energy applied to the bit or formation drillability. This data is normally and routinely com-piled in the mud log and can represent shifts in drilling trends from a normal to a stressed environment. Trend shifts are very reliable predictors of changes in the drilling environment. This data com-piled with other interpretations can be a clear indictor of the need to increase mud weight, especially in light of other interpreted data.

A common misunderstanding in the industry is that D exponents have no value with fixed cutters, when quite the opposite is true. This engineering-spe-cific energy algorithm is independent of bit type. Another value of these as trend predictors is that they can help forecast changes in wellbore stresses, which pres-sure-while-drilling (PWD) tools cannot. PWD tools measure only the net balance in the static and dynamic states.

Elliptical hole (principal stress vec-tors). An elliptical hole is normally an after-the-fact indicator, but recognizing this stress-induced hazard can help plan the next well to identify wellbore stability issues and assist in directional planning. This data can also be used to compare conventional pore pressure predictions to stress both in direction and in magnitude and to better deliver a reliable mud weight schedule and help improve predictions.

Fluffy, wetted shales (chemical in-stability). Chemical instability is com-mon in shale. Cuttings characteristics can be exhibited as “fluffy” or, in the worst

case, gumbo. This phenomenon can hap-pen in any mud balance condition and is exacerbated if the mud weight is too high. If wetting occurs with mud weight too high, reducing the mud weight can create further instability because wetted shale will relieve stress. Newly exposed shales undergo ionic exchange and are re-wetted. Once the applied mud weight is too high, it can be nearly impossible to correct this condition, as the hazard will compound itself.

LIMITS OF REAL-TIME DATAThe advent of real-time technologies

facilitates accurate decisions and best practices for any operation. However, the industry’s growing dependence on real-time data can foster a singular focus that sometimes results in misinterpretation of issues. For example, operators often re-spond to the commonplace occurrence of background gas by weighting up drill-ing systems arbitrarily. This reaction—or a reaction stemming from misinterpreta-tion of any of the above dynamics—is counterproductive to performance and can also induce dangerous drilling con-ditions. Good drilling practices revolve around interpretation of the totality of the data to make the correct decision while drilling; singular interpretation of condi-tions associated with any of the drilling dynamics can be counterproductive to maintaining a safe and stable wellbore, as illustrated with the following examples.

Ballooning (wellbore breathing). Ballooning is a phenomenon that of-ten occurs as a consequence of exces-sively high ECD. Resultant flowback when pumps are shut down can often be confused with influx caused by a pore pressure that is greater than mud bal-ance. This interpretation is often further complicated by gas entrained in shale, common especially in mottled shale. “Weighting up” the mud to counter the shale gas can further complicate balloon-ing. Arbitrarily increasing mud weight in the presence of shale gas alone can result in the extension of natural fractures or fracturing of the formation below or at the shoe, sometimes with catastrophic consequences.

Failure to distinguish ballooning from a well control event is a common mistake made in drilling operations. It is also one of the leading causes of unnecessarily ex-pending casing strings in narrow-margin drilling operations such as occur in high-pressure/high-temperature and deepwa-ter environments.


In a typical case in an actual well, high ECD resulted in ballooning, and a subsequent increase of the mud weight resulted in the extension of existing frac-tures. The higher ECD further exacer-bated wellbore instability by increasing the cyclic bleed-offs. Ultimately, the mud weight increase fractured the for-mation, and massive and unsafe fluid losses were sustained before control of the well was regained.

The sequence of events began with the setting of casing at 11,370 ft with 1.7-sg mud weight. This mud weight was arbi-trarily increased in the shoe track to 1.9 sg before drilling ahead. ECD management became difficult, with frequent ballooning events. Frequently conducted flow checks showed no flow. All other drilling dynam-ics were normal; there was no torque or drag, and cuttings appeared normal.

As background gas increased in the shale interval, the mud was weighted up several times without conducting any flow checks. Gas alone is not a rea-son to increase mud weight; since shale does not have transmissibility but does have porosity, entrained gas is common and cannot be weighted out, especially in highly mottled shale. Entrained gas

always arrives with the cuttings and ex-pands according to Boyle’s law, no mat-ter the mud weight.

Drilling in shale continued from 13,300 ft to 14,000 ft, with increasing background gas. The well was circulated and conditioned with no fill. The BOP was closed with no flow and no pressure observed, and control was circulated through the choke. No torque spikes, drag or fill were observed, and cuttings still appeared normal. Mud weight was increased to 2.0 sg while circulating on the choke.

The shut-in drill pipe pressure of 340 psi was bled back with no further flow or pressure. The BOP was closed with 340 psi, then opened. The well briefly had a small initial flow and then shut in with no pressure. The well was opened and found to be stable with no flow. Shut-in pressure was not measurable. The well was circulated and conditioned, and the mud weight was further increased to 2.3 sg, and later to 2.45 sg with immediate and massive fluid losses. Ballooning-in-duced fracturing occurred after the mud weight increase. Three days of circulat-ing and conditioning back to 2.1 sg was necessary to stabilize the well.

A decision was made to run liner once the well was stable. The pore pressure/fracture gradient curves were observed to be normal. It was determined that, other than background and connection gas, which bled off, there had been no reason initially to increase the mud weight.

In this well, properly managing ECD and recognizing ballooning as a conse-quence of high ECD could have allowed the well section to be drilled deeper. The misinterpretation of ballooning required the setting of a liner before planned and caused the loss of a casing point. The consequences could have been much worse—wellbore collapse or even a shal-lower formation influx from an under-balanced formation.

When ballooning is recognized, care must be taken to avoid unnecessarily weighting up. Instead, trapped pressure must be bled back. Figure 1 represents an actual case where ballooned pressure was recognized and successfully bled back.

Fluid loss. Fluid losses can range from slight to catastrophic and result in wellbore failure or well control events. They primarily occur because the ECD is outside the safe drilling margin de-fined by the overburden fracture gradi-ent on the high side and the in situ pore pressures and stress of the formations on the low side. These boundaries can be exceeded as a result of ballooning or, in porous formations, because an unneces-sarily high mud weight is applied. Main-taining the ECD low enough to ensure fluid volume integrity yet high enough to maintain wellbore integrity is critical, and requires well listening.

Sometimes losses can be acceptable and sustained. In these cases, recognizing the types, relative volumes, classes of li-thology, and placement of proper lost-cir-culation material (LCM) is critical to the successful management of fluid losses.

The best practice and first line of de-fense is to avoid overweighting the hole and thereby prevent ballooning events. Typical fluid loss decision tree processes can and should be created. Table 3 is an example of the foundation of a fluid-loss control application process.

Stuck pipe. Stuck pipe is a drilling haz-ard that can be associated with balloon-ing and fluid losses. Recognizing and avoiding stuck pipe requires some of the same well listening techniques as used for other hazards. Generally, stuck pipe is avoidable if drilling margins are honored and listening guidelines are observed.

Solution set

1. Avoid applying excessive mud weight; improve hydraulics and overall ECD including improved hole cleaning and controlled drilling.

2. Flush or spot 1–3% fibrous and/or flaked LCM pill, or add 1–3% fibrous and/or flaked LCM to circulation mud.

3. Flush or spot 1–3% sized calcium carbonate pill, or add 1–3% sized calcium carbonate to circulation mud.

4. Spot and/or squeeze 8–12% LCM pill (mixture of fibrous, flaked and granular LCM).5. Apply cement spot and/or squeeze.6. Specialty techniques such as chemical pig or gunk squeeze.7. Blind drilling.8. Improve mud cake by adding asphaltic material.

Application

Type of formation

Sandstone Coal

Type of loss Congl.Shale

(or silty shale)

Low por. Med. por. High por. Frac-

turedSmall

fissuredFrac-tured

Seepage only 1,2 1 1,3 1,3 1,3 1,3 1,8 1,8

Small losses 1,2 1,2 1,3 1,3 1,3,2 1,3,2 1,8,2 1,8,2

Medium losses 1,4 1,4 1,3,6 1,3,2,5 1,3,2,5 1,3,2,4,5 1,2,4 1,2,4,5

High losses 1,4,5 1,7,4,5 – 1,3,5,6 1,3,5,6 1,4,5,6 1,4,5 1,4,5

Uncontrolled losses 1,7,4,5,6 1,7,4,5,6 – – 1,7,4,5,6 1,7,4,5,6 1,4,5,6 1,4,5,6

TAbLE 3. Generic lost-circulation control methodology




Some causes of stuck pipe that might have little to do with the drilling margin are coal sections; shale welling (gum-bo); hole packoffs around the BHA; under-gauge hole; wellbore geometry (such as hole restriction in highly per-meable sections with high fluid loss); collapsed casing; cement blocks; junk; green cement; cuttings beds or buildup, especially in high-angle holes; and salt, causing plastic flow. Prevention of stuck pipe in each of these scenarios requires an awareness of overall hole conditions; of course, some are unavoidable, such as unknown collapsed casing. Nonetheless, they should all be considered as poten-tial risks and assessed.

The best practices to avoid stuck pipe are much the same as for ballooning and fluid loss—recognizing the conditions within the drilling margins and events and reacting correctly. Other factors that should be considered include BHA and drillstring configuration, as well as the inhibitive characteristics of the forma-tions being drilled.

NEXT INSTALLMENTPart 3 addresses the integration of

mitigation into the well design. Manag-ing drilling hazards requires understand-ing how practices and technologies can improve the risk profile and add value—i.e., demonstrate a positive cost-benefit balance from a risk-adjusted perspective. Any new mitigant must decrease the like-lihood 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 various technologies can improve the abil-ity to mitigate and manage risk and im-prove the ultimate value of the well. WO

THE AuTHoRS

David Pritchard is a pe-troleum engineer with 40 years of industry experi-ence, including manage-ment and supervision of worldwide drilling and pro-duction operations. He has consulted for an array of na-tional and international inde-pendents, major companies

and service providers. As owner of Pritchard engineering and Operating, Mr. Pritchard devel-oped, participated in and operated a number of oil and gas properties in the ArkLatex region of the US. He holds a bS degree in petroleum en-gineering from the University of tulsa.

Pat York is the Director of commercialization and Marketing for Weatherford Intl.’s Solid ex-pandables and Drilling Hazard Mitigation prod-uct/service lines. He has 38 years of oil and gas industry experience. before joining Weather-ford, Mr. York was Vice President of commer-cialization and Marketing for enventure Global technology after tenures with Halliburton and Dresser Atlas. He earned a bS degree in electri-cal engineering at Northwestern State Univer-sity in 1972 and pursued his MbA degree there before launching his oilfield career.

Scott Beattie has 22 years of oilfield service ex-perience. After spells with Halliburton and baker Oil tools, he has spent the past 14 years with Weatherford Intl. in various roles, primarily sup-porting drilling technologies. Mr. beattie’s latest assignment is in Kuala Lumpur, Malaysia, as Global business Unit Manager for Drilling with casing. He is a key member of Weatherford In-tl.’s Drill Hazard Mitigation team.

Don Hannegan is the Drilling Hazard Mitigation technology Development Manager for Weath-erford Intl. He received World Oil’s 2004 Inno-vative thinker Award for his role in conceiving and developing specialized equipment and con-cepts applicable to managed pressure drilling of challenging and complex wells. He was re-cently appointed by the University of texas Pe-troleum engineering extension Service (PeteX) to serve as lead author of a textbook to be titled Drilling Hazard Mitigation tools & technology.

17.3

16:4

7:45

17:1

2:45

17:3

7:45

18:0

2:45

20:2

7:30

17:5

2:45

19:1

7:30

16:4

7:30

19:0

7:30

20:3

2:30

20:5

7:30

21:2

2:30

21:4

7:30

17.4

17.5

17.6

Flow checkflowing

17.85 ppg

17.70 ppgBleed off fluid(5 bbls)

Pressure buildup on shut-in

Time, hh:mm:ss

Source: Swanson, B.W. et al., SPE 38480, 1997

Circulate to reduce mudweight from 18.3 to 17.8 ppg

17.7

17.8

Equi

vale

nt m

ud w

eigh

t, pp

g

17.9

18.0

18.1

18.2

18.3

18.4

Fig. 1. Successful bleed-back of ballooned, or trapped, pressure.

Article copyright © 2011 by Gulf Publishing company. All rights reserved. Printed in U.S.A.


DRILLING

Drilling hazard management: Integrating mitigation methodsPart 3 of 3: Many drilling hazards can be mitigated or avoided using casing or liner drilling, managed pressure drilling or solid expandable liner technologies.

David Pritchard, Successful Energy Practices International; Patrick L. York, Scott Beattie and Don Hannegan, Weatherford

Managing drilling hazards requires understanding how the incorporation of mitigating practices and technologies into the well design can improve the risk profile and add value. To achieve this understanding, risk assessment must be applied to the mitigating practices and technologies under consideration. From a drilling hazard management (DHM) perspective, add-ing value means improving both the risk profile and the cost-benefit balance of the overall operation from a risk-adjusted perspective. Any new mitigant must 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 can improve the ulti-mate value of a well.

APPLYING FIT-FOR-PROBLEM TECHNOLOGYThe many and varied technologies available to assist in

drilling complex wells are often underutilized. In light of the workloads imposed on today’s drilling engineers and well su-pervisors, it has been easy to apply familiar tools that have gen-erally worked in previous well situations rather than investigate and apply the most fit-for-problem technology. Conversely, applying technology for technology’s sake is seldom the best approach; often, implementing good drilling practices may be the best solution to the current challenge.

As highlighted in the two previous installments of this ar-ticle series, the most prudent approach involves two steps: first, identify well objectives that are specific, measurable, achievable, relevant and timely, or sMArT; second, develop a thorough understanding of the uncertainties and risk mitigants.

studies conducted over the past decade have shown that about 50% of drilling hazards resulting in nonproductive time (NPT) can be either avoided or mitigated using good drilling practices such as “well listening.”1 Most of the other half of drilling hazards can be mitigated or avoided through the use of drilling with casing (DWC)/drilling with liner (DWL), man-aged pressure drilling (MPD) or solid expandable technologies. These technologies are only a few of many in the drilling profes-sional’s tool box, and none should be considered a panacea.

Because multiple resources exist that detail the workings of these technologies,2–4 this article provides only a brief review of how they work, then focuses on how DWC/DWL, MPD or solid expandable systems 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.

Drilling with casing/liner. DWC or DWL 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, the casing string is used as the drillstring instead of drill pipe. 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 about 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.

4,0000 1 2 3 4 5

Drilling time, days

MD,

ft

6 7 7 9 10

3,500

3,000

2,500

2,000

1,500

1,000

500

0

Run 85⁄8-in. liner

Drill 17½-in. hole,cement and clean out133⁄8-in. conductor

Drilling curve for wellDrilling curve with DWC

Fig. 1. An example illustrating flat time reduction due to DWC.

Originally appeared in:December 2010 issue, pgs 49-55. Posted with permission.

December 2011 World Oil

DRILLING

Reducing drilling flat time. A key benefit of DWC is time reduction. The time associated with tripping pipe and run-ning casing, including much of the circulation time involved, is removed. Connection time savings alone are about 12%, assuming 3.5 min. for 90-ft drill pipe and 5 min. for 40-ft cas-ing with an on-bottom rate of penetration (rOP) of 50 m/hr. At 100-m/hr rOP, the savings increase to 18%.5

DWC also eliminates other NPT involved in operations such as reaming, circulating high-viscosity pills and conductor cleanout runs. Other potential savings result from the reduced incidence of unscheduled events like hole collapse when using DWC. Typical total time savings from DWC range from 30% to 50% of the time from section spud to leakoff test, Fig. 1.

Getting casing to bottom. DWC eliminates the tripping of drillstrings and conventional casing-running operations, as well as the resultant deterioration of time-dependent forma-tions. The fact that the casing is always on bottom ensures that where the drillable casing bit reaches is where it can be cased.

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 stabil-ity problems and well control incidents. Elimination of pipe tripping prevents the occurrence of these problems.

Drilling depleted zone and overcoming lost circulation. Lost circulation is a frequent occurrence in mature fields and areas with weak formations. It is a contributing factor to an-other serious problem that plagues drillers: stuck pipe.3

It might appear that DWC would increase this risk because the casing could get stuck before reaching the planned casing point. One would also expect lost circulation to be a poten-tial 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 that DWC significantly reduces lost circulation. The exact mechanism that provides this benefit is subject to debate, but there is strong evidence that it results from the smearing of drilled cuttings and mud solids into the borehole wall, creat-ing a plastering effect that mechanically builds an imperme-able filter cake.6

Many case histories, published papers and documented results 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.

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 is also less prone to vibrations, reducing the mechanical impact damage on the borehole wall. Drillstring vibrations have been attrib-uted to borehole stability problems and oval-shaped holes.

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 the elimination of hammering operations. Loading and rig-ging up pile hammers is often considered to be one of the most hazardous operations carried out on the rig floor.

Reducing rental costs. DWC eliminates the need for con-ventional bottomhole assembly (BHA) components, and can eliminate the need for one or more strings of drill pipe.

Improving hydraulics. The annulus between the BHA/cas-ing OD and borehole ID is reduced in DWC; thus, under the same operating conditions, DWC delivers higher annular ve-locity than conventional drilling. The improvement ranges 81–134%, averaging 110%. As a rule of thumb, the DWC annular velocity is roughly double the conventional annular velocity.

Managed pressure drilling. MPD is an advanced form of primary well control usually employing a closed and pressuriz-able circulating mud system, which facilitates drilling with pre-cise management of the wellbore pressure profile.

The primary objective of MPD is to optimize drilling pro-cesses by decreasing NPT and mitigating drilling hazards, and to enable drilling of otherwise technically or economically un-drillable high-complexity prospects.

MPD’s specialized equipment and techniques have evolved since the mid-1960s on thousands of Us land drilling programs and are considered status quo by many who pioneered the root concepts. Compared to conventional rotary drilling with joint-ed pipe and weighted mud, MPD applications have established a commendable well control incident track record.7

Because MPD addresses NPT, the technology is of great-est potential benefit to offshore drilling programs where cost of lost drilling time is much higher than onshore. Although MPD has 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 technol-ogy in the offshore.

Nevertheless, since MPD technology and enabling tools were introduced to offshore drilling decision makers in 2003, there have been hundreds of applications globally in marine environments, from both fixed and floating rigs.

Drilling-related issues such as excessive mud cost, slow rOP, wellbore ballooning/breathing, kick-detection limitations, dif-ficulty in avoiding gross overbalance con-ditions, differentially stuck pipe, risk of twist-off and resulting well control issues contribute to defining the offshore indus-try’s need for MPD technology. Kick-loss scenarios that frequently occur when drill-ing into narrow or relatively unknown downhole pressure environments also

135⁄8-in. csg.w/monobore tieback shoe

75⁄8 x 95⁄8-in.expandable openhole liner

11¾ x 135⁄8-in.expandable liner extension

8½-in. expandable openhole clad

30-in.drivepipe

30-in.drivepipe

18-in. csg.

133⁄8-in. csg.

11¾-in. csg.

11¾-in. csg.

7-in. csg. 7-in. flush joint csg.

95⁄8-in. csg.

95⁄8-in. csg.

26-in.csg. 20-in. csg.

16-in. csg.

16-in. csg.

Conventional casing design Expandable casing design

Fig. 2. Wellbore slimming through the use of solid expandable openhole systems.


define a requirement to deviate from conventional methods. Excessive drilling flat time and HsE issues further indicate the necessity for a technology that addresses the root causes.

Each of the four variations of MPD is applicable to spe-cific drilling-related challenges or hazards. On some complex wells, combinations of the variations may be required to bet-ter address trouble zones from spud to TD. 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 bottomhole pressure is applicable to narrow or relatively unknown drilling windows, HPHT wells, pressure fluctuation-induced wellbore instability, ballooning/breath-ing and well control scenarios.

Pressurized mud-cap drilling is applicable to severe loss circulation and/or drilling into sour formations.

Dual-gradient drilling, with or without a marine riser, is applicable to depleted formations and to avoid gross overbal-ance associated with a tall column of annulus returns in deep-water riser systems. Hydraulically speaking, dual gradient tricks the well into thinking the rig is closer than it is—by removing some of the mud and cuttings weight, creating two or more pressure-versus-density gradients via injection of light liquids, subsea pumps, downhole pumps or combinations thereof in the annulus returns path.

Returns flow control is simply drilling with a closed-an-nulus returns system immediately under the rig floor for HsE purposes only.

Solid expandables. solid expandable systems were initially developed to reduce drilling costs, increase production of tub-ing-constrained wells, and enable operators to access reservoirs that could otherwise not be reached economically.

Although the first related patent was issued in 1865, it wasn’t until the mid-1900s that operators in the 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.

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

In downhole applications, solid expandable technology reduces or eliminates the telescopic profile of the wellbore, Fig. 2. In 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 com-promising a casing point as designed in the drilling plan.

In an openhole environment, the most common applica-tion runs a solid expansion system, expands it and ties it back to the previous casing string. This structural approach facili-tates the extension of the previous string of conventional cas-ing while minimizing the slimming of the well profile during well construction.

The type and size of system used in a project depends on the conditions that demand mitigation. Unexpected problems may require the application of a one-off installation, which is especially common in exploratory wells. Offset data can iden-tify 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• Overexposed hole as a result of drilling issues, equipment

failures, prolonged tripping, etc.• Overpressured formations• Underpressured formations• Close fracture-gradient/pore-pressure tolerances• Poor isolation across multiple zones• Remediation for casing that was inadvertently set shallow.

In contrast to a last-resort application, expandable systems may be used as a fundamental casing string as an integral part of the well’s basis of design. 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 basis of design 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 well planning.

MITIGATING COMPLEX WELL CHALLENGESThe following real-well example illustrates the effective

planning and application of the technologies discussed above. This well was one of a set of wells to be drilled through very complex formations near the foothills of a mountain range.

Defined goals for the well included the following:• Maintain less than 2° inclination at casing point (about

2,000 ft).• Drill Section 1 formations to about 6,600 ft MD. Build

angle from 2,000 ft (kickoff point) to 22° inclination.• Drill Sections 3 and 4 to the top of pressure ramp to about

13,000 ft MD. Directionally drill tangent section from 7,000 ft to about 11,400 ft, and then continue drop section with dogleg severity of 1°/100 ft, keeping direction to the east.

• Run LWD tools to obtain accurate geological data.• Stay vertical (less than 3° inclination) and maintain azi-

muth to reach the target according to the drilling plan. • Drill, core, log and isolate Target 1 high pressure and con-

sider 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.As discussed in the first installment of this article series, these well goals do not meet the standard of sMArT well objectives.

The seismic and offset well information indicated complex geology; depth uncertainty due to seismic resolution; trajectory passing up, down and cross-dip; and uncertainty in the types of hydrocarbon present. The geological complexity was such that the same formations were encountered several times by the pro-spective wellbore due to severe faults and geophysical events that occurred during and subsequent to their deposition, Fig. 3.

Purpose of technical limit analysis. The initial well re-quired about 360 days to drill. After implementing good drill-ing practices and without applying technology mitigants, this time was reduced to 216 days. However, the subsequent tech-nical 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 existed and what created them• How well design would impact hazard risk management• The geotechnical environment


DRILLING

• Practices and technologies that could mitigate the hazard• Performance measurements to be utilized• The framework for choosing the correct mitigation(s)• Future recommendations for alternative solutions.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 analog well• Where the NPT had been expended• How much time could be saved with improved practices

and technologies• What the hazards were and why they occurred• A baseline for technical-limit time iterations (i.e., to sus-

tain learning).

risk/consequence profiles of all hazards had to be developed; these would provide a baseline to derive a risk-assessed cost-benefit analysis of the hazard mitigants.

Technical-limit engineering using both good drilling prac-tices and a variety of cutting-edge technologies indicated that drilling time to TD could be reduced by almost half, from 216 days to 115 days, Fig. 4.

Reducing risk and improving drill time. The following summarizes the opportunities that exist to improve the well eco-nomics through the applications of the DWL, MPD (pressur-ized mudcap) and solid expandable technologies.

Drilling the top hole section with casing ensures vertical-ity and stability, and uses a rock strength that is well within the range of cutter technology. It removes three days’ drilling time and enables the ability to extend the shoe depth. In addition, using DWC in this application improves leakoff tolerance for the next hole section and simplifies the drilling margins.

Using DWL as a “hole cleaning while drilling” method, after conventionally drilling the last two hole sections for the drill-ing liners, ensures that these liners successfully reach their total depths. Additionally, this application facilitates well stability un-der MPD conditions while minimizing running and cementing risks, lost time, NPT and flat time.

Using pressurized mudcap drilling from the top of the hole down eliminates the risk of up to 33 days’ lost time; the risk-adjusted cost-benefit balance is at least a 11 times better than using conventional drilling alone in the top hole section. Applying this MPD method also elimi-nates the risk of losing over 13,500 bbl of expensive oil-based mud in the top hole. Additional benefits include better control of confining stresses while accepting losses; elimination of the need for turbine drilling with im-pregnated bits, especially where temperature is not an is-sue; and the ability to use cheap, expendable water-based mud—because losses become non-consequential, cut-tings cure loss zones and the cap controls cavings. Figure 5 indicates the areas of the well where the DWC/DWL and pressurized mudcap were applied to the trouble zones.

The application of openhole expandable liner in either 7⅝-in. x 9⅝-in. size (resulting in a post-expanded ID of about 7½ in.) or a 8½-in. monobore size (resulting in a post-expand-ed ID of 8⅝ in.) allows a liner to be installed below the 9⅝-in.

W1a: 3,502 ft

Geo 2: 6,660 ft

T/Cv: 7,728 ft

Marker 1:10,095 ft

W1b:11,004 ftW1a: 11,632 ft W1b: 11,851 ft

Top Marker 1:12,874 ft

Top Cv: 13,407 ft

18

0 10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

180

190

200

210

220

MD,

thou

sand

ft

Drilling time, days

Actual time vs. daysTechnical limit timePore pressureCollapseMud weight

16

14

12

10

8

6

4

2

0

Marker 2: 14,318 ft

Top Pay 1:15,011 ft MD

Definitions:ILT: Invisible Lost Time, or inefficiencies such ascontrolled drillingRLT: ILT plus Wasted Time (Unnecessary bit trips,casing set short, etc.) Technical Limit removes allNPT and RLT

Technical limit:115 days

Actual time:216 days

Fig. 4. Comparison of conventional and technical-limit drilling curves.

W1a: 3,502 ft

DWC: 20-in. casing

Pressurizedmudcap 17½-in.:

Set 135⁄8-in.

Three cement plugsand 16 days tomitigate losses

This stressed area created 33 days ofwasted time and 13,574 bbls OBMlost:

builds case for pressurized mudcap

Geo 2: 6,660 ft

T/Cv: 7,728 ft

Marker 1:10,095 ft

W1b:11,004 ftW1a: 11,632 ft W1b: 11,851 ft

Top Marker 1:12,874 ft

Top Cv: 13,407 ft

18

0 10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

180

190

200

210

220

MD,

thou

sand

ft

Drilling time, days

Actual time vs. daysTechnical limit timePore pressureCollapseMud weight

16

14

12

10

8

6

4

2

0

Marker 2: 14,318 ft

Top Pay 1:15,011 ft MD

Fig. 5. Drilling curves with DWC/DWL and pressurized mudcap drilling technologies applied in the upper hole sections.

Fig. 3. Geological map of the example well.


Risk 1: Fluid loss in hole sectionRisk 2: Stuck pipe in hole section

1.01 1.02 1.03 1.04 2.01 2.02 2.03

Consequences Non-productive time

Slight losses Severe losses resulting in 25 days to cure, with 7 days to squeeze and drill out. Loss of 15,000 bbl OBM

Severe losses resulting in 25 days to cure, with 7 days to squeeze and drill out. Loss of 15,000 bbl OBM

NPT but able to retrieve drillstring suc-cessfully

NPT; retrieve drillstring by fishing

Pipe irretriev-ably stuck; cut, plug and sidetrack; loss of required hole size

Existing mitigation(s) in place Mud program, lost-circulation procedures and materials, BOP equipment, pit drills

Mud program, lost-circulation procedures and materials, BOP equipment, pit drills, applied controlled drilling



Mud program, lost-circulation procedures and materials, BOP equipment, pit drills, spiral drill collars

Mud program, lost-circulation procedures and materials, BOP equipment, pit drills, spiral drill collars


Likelihood of occurrence with existing mitigation(s) in place1

100% 100% 100% 100% 40% 25% 25%

Likelihood (ranking 1–6) 1 1 1 1 2 2 2Consequence (ranking 1–6) 6 6 3 3 6 4 3

Risk ranking factor2 6 6 3 3 7 5 4

Risk response choice: accept, mitigate, avoid

Accept Accept Avoid Avoid Accept Accept Avoid

Mitigation(s) needed3 Drill the 16-in. section with a drilling liner to mitigate losses and maintain stability; rock compressive strength is well below drill shoe design limit

Water-based mud and man-aged pressure drilling

Set the prior casing string with an over-sized shoe and use expandable drilling liner to conserve hole size

Cost of mitigation(s) needed $250,000 $500,000 $500,000

Likelihood of occurrence with mitigation(s) needed in place 1% 1% 1%

Likelihood (ranking 1–6) with mitigation(s) needed in place 6 6 6

Consequence (ranking 1–6) with mitigation(s) needed in place

3 3 3

New risk ranking factor4 8 8 8Extra time if event occurs, hr 600 600 96

Extra cost if event occurs $5.85 million $5.85 million $4 million

Risked time, hr5 6.00 6.00 0.96

Risked cost5 $58,500 $58,500 $40,000

Benefit-to-cost ratio6 2316.6% 1158.3% 192.0%

Comments The cost savings if the event occurs as before are: No loss of OBM; $3 million plus 25 days saved at $100,000/day plus 7 days cement remediation

The cost savings if the event occurs as before are: No loss of OBM; $3 million plus 25 days saved at $100,000/day plus 7 days cement remediation

This indicates that not only is the risk profile improved, but also, on a risk-adjusted basis, the cost of the new solid expandable miti-gant adds value to the operation.

1 Probability percentage of occurrence based on data or experience. 2 Ranking from the risk matrix; risk response choice is suggested by color, and action is determined by the team.3 With intent to reduce the probability of the risk occurring.4 With needed mitigation(s) in place, based on lower probability of the risk occurring (consequence generally remains the same); not improvement in risk profile.5 Risk-adjusted lost time and cost if the event still occurs (normally, total NPT off the critical path to the time on the critical path); associated costs are the total daily cost of operations.6 Added value of the new mitigant represented by its discrete cost as a function of reduced risk; the value for the worst-ranked risk indicates that the mitigant has added value.

TabLe 1. Risk analysis conducted on the example well for liner drilling, mud-cap drilling and expandable drilling liner


DRILLING

conventional casing string. This expandable solution allows for mitigating the trouble zone while enabling the running of a 7-in. (or smaller) string of conventional casing, adding an ex-tra casing string without loss of hole size. However, within the 8½-in. hole section (which requires under-reaming the hole section over the trouble zone by 1 in. if the expandable liner is to be installed) the formation is extremely hard. This was evidenced by highly worn impregnated bits; stabilizers out of gauge; difficult conventional reaming and torquing; drillstring stalling (not turbine); highly worn turbine bearings; a high percentage of sandstone in cuttings; and the fact that overbal-ance was greatest when pore pressure was at its lowest values.

To effectively evaluate the uncertainties of using each tech-nology being considered, a comprehensive risk analysis must be preformed including the technology and its particular ap-plication within the well. Table 1 presents the risk analysis conducted on the example well for liner drilling and mud-cap drilling (to mitigate risk of fluid loss) and the use of expand-able drilling liner (to mitigate risk of stuck pipe).

CONCLUSIONThe key to mitigating and managing risk lies in understand-

ing the importance of a stage-gated planning process, develop-ing sMArT objectives, and acknowledging and defining possi-ble uncertainties and risk applied to practices and technologies. successful drilling hazard management 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. risk assessment should be conducted for any operation, and the process implemented should be used to critically challenge each facet of the well design.

To this end, it is important to understand how practices and technologies can improve both risk management and the ulti-mate value of the well. WO

LITERATURE CITED 1 York, P. et al., “Eliminating non-productive time associated with drilling trouble zones,” OTC 20220

presented at the Offshore Technology Conference, Houston, May 4–7, 2009. 2 Al-Umran, M. et al., “New 5½ in. solid expandable systems provide effective technology for successful

workover project in saudi Arabia,” sPE 08057 presented at the sPE saudi Arabia section Technical sym-posium, Alkhobar, saudi Arabia, May 10–12, 2008.

3 Jianhua, L. et al., “Use of liner drilling technology as a solution to hole instability and loss intervals: A case study offshore Indonesia,” sPE/IADC 118806 presented at the sPE/IADC Drilling Conference and Exhibition, Amsterdam, March 17–19, 2009.

4 Nas, s. et al., “Offshore managed pressure drilling experiences in Asia Pacific,” sPE/IADC 119875 pre-sented at the sPE/IADC Drilling Conference and Exhibition, Amsterdam, March 17–19, 2009.

5 scott, r. et al., “Pushing the limit of drilling with casing,” OTC 16568 presented at the Offshore Technol-ogy Conference, Houston, May 3–6, 2004.

6 Watts, r. D. et al., “Particle size distribution improves casing-while-drilling wellbore strengthening re-sults,” sPE 128913 presented at the 2010 IADC/sPE Drilling Conference and Exhibition, New Orleans, Feb. 2–4, 2010.

7 Jablonowski, C. J. et al., “The impact of rotating control devices on the incidence of blowouts: A case study for onshore Texas, UsA,” sPE133019-Ms presented at the 2010 Trinidad and Tobago Energy re-sources Conference, Port of spain, Trinidad, June 27–30, 2010.

THe aUTHORS

David Pritchard is a petroleum engineer with 40 years of experience, including management of worldwide drilling and production operations. He has consulted for an array of independents, major companies and service providers. As owner of Pritchard engineering and Operating, mr. Pritchard developed, participated in and operated a number of oil and gas properties in the ArkLaTex region of the US. He holds a bS degree in petroleum engineering from the University of Tulsa.

Pat York is the Director of commercialization and marketing for Weath-erford Intl.’s Solid expandables and Drilling Hazard mitigation product/service lines. He has 38 years of oil and gas industry experience. before joining Weatherford, mr. York earned a bS degree in electrical engineer-ing at Northwestern State University in 1972 and pursued his mbA de-gree there before launching his oilfield career.

Scott Beattie has 22 years of oilfield service experience. After spells with Halliburton and baker Oil Tools, he has spent the past 14 years with Weatherford Intl. in various roles, primarily supporting drilling technolo-gies. mr. beattie’s latest assignment is in Kuala Lumpur, malaysia, as Global business Unit manager for Drilling with casing. He is a key mem-ber of Weatherford Intl.’s Drill Hazard mitigation team.

Don Hannegan is the Drilling Hazard mitigation Technology Develop-ment manager for Weatherford Intl. He received World Oil’s 2004 In-novative Thinker Award for his role in conceiving and developing special-ized equipment and concepts applicable to managed pressure drilling of challenging and complex wells. He was recently appointed by the University of Texas Petroleum engineering extension Service (PeTeX) to serve as lead author of a textbook to be titled Drilling Hazard Mitigation Tools & Technology.

Article copyright © 2011 by Gulf Publishing company. All rights reserved. Printed in U.S.A.


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