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2 GRAHAM R. STRONACH, GERRE S. VODEN JR., JEFFREY S. HUBBARD, C.MICHAEL MING, J.CRAIG NORTHCUTT SPE 67192

bore deviation was measured using a conventional wirelessdrift system with survey validations using magnetic multi shot

and logging techniques.Williamson and Lubinski* developed a program for the

prediction of BHA performance that takes into account

formation characteristics and allows a wide range of BHAequipment to be analyzed. This program was selected as themethod that would be used for prediction analysis as it had anestablished track record for accuracy and was practical to use

in day to day operations.For each planned hole size to be drilled, (28, 20-1/2,

14-3/4, 10-5/8, 8-1/2 and 6-1/2 inches respectively), severalBHA configurations were considered and modeled to assesstheir suitability. Every modeled bottom hole assembly was

also reviewed to determine its sensitivity to changes information characteristics, weight-on-bit, drill collar diameter,wear on stabilization or enlargement of well bore diameter.

Results were plotted graphically for comparison purposes.Formation Characteristics(Fig. 2, 3). A formation deviationcontrol index (FDCI) was an important part of the analysis

process as was formation dip data. It was recognized thatinitial modeling results would have a higher margin of error.This margin would decrease as actual drilling assemblies used

were modeled to compare predicted versus actual results.Weight-On-Bit (Fig. 2). As a general rule, BHAs that wereleast sensitive to changes in weight-on-bit were selected. As a

result of this, packed hole type of assemblies were normallythe first choice. These would allow increased weight-on-bitand greater rates of penetration with less deviation tendencies.

In practice however, contingency pendulum assemblies wereused in certain zones when the restoring force of the pendulumeffect in combination with lower weight-on-bit was required

to maintain the hole angle as close as possible to zero (Fig. 1).(Fig. 2) compares the deviation characteristics of BHA Z, apendulum assembly versus packed hole assemblies, BHAs

X and Y. In these zones, the rate of penetration wassacrificed in order to maintain critical deviation control. Drill Collar Size. The effect of drill collar size was also

modeled to determine its impact on deviation tendencies. It iswell documented that maximizing the drill collars size andstiffness can significantly influence the deviation tendencies of

the BHA selected. BHA X and Y in (Fig. 2) haveidentical stabilizer positions but different drill collar

diameters. For this particular project, it was necessary todetermine an accurate consequence of drill collar size inrelation to deviation control. This was considered to be a keydriver in the drilling equipment selection process, which was

running concurrently. Stabilization Wear (Fig. 4). Abrasive wear on stabilizationpoints was considered to be a potential problem, particularly

in the Des Moinesian and Atokan (Granite Wash) intervals inthe 14-3/4 hole section. Wear on the stabilizers would result inincreased clearance which in turn would allow greater

deviation to occur. It was therefore important to model theimpact of increased clearance between stabilizer diameter andwell bore diameter. The result of this was used to optimize

stabilizer placement and set limitations on allowable wear.

The potential occurrence of abrasive wear was also a keyelement considered in the equipment selection process.

Initial modeling was completed approximately 60 days priorto the spudding of the well. This allowed sufficient time forthe core project group to review the results and also allowed

time for the verification of equipment and mobilization. Thecore project group included operator, drilling contractor andservice company representatives. This project included holesizes that were not as frequently used, and as such, placed

some limitations on equipment availability.

Equipment SelectionThe selection of fit for purpose equipment was also a keyelement in the planning process. The selection process had a

wide range of sub elements including:

Critical aspects of tubular designBHA component designShock tool use and placement

Drilling jar optimizationOptimized connections

Definition of inspection requirementsDefinition of inspection frequenciesEvaluation of inspection service providers

Assessment of repair facilitiesReview of repair procedures

The equipment selection process is illustrated in the appended

flow chart. (Fig. 6)

Tubular Design. A planner was developed as a tool to assistin tubular selection. The formulas used in the planner were in

compliance with API Recommended Practice 7G, 16th

Edition.The function of the planner was to provide an efficient methodof determining tubular requirements including drill pipe

tensile, torsional strength and collapse properties, minimumOD and ID requirements for drill pipe, heavy wall drill pipeand drill collars. The planner was also utilized to calculate the

weight requirements for the BHAs. As a general rule, neutralpoint safety factors of 1.15/1.25 were used for all rotaryBHAs.

BHA Component Design. For components used in the BHA,the design criteria broadly fell within the appropriatemanufacturer specifications. In the case of drill collars and

heavy wall drill pipe, this was already done within the tubulardesign planner. For stabilizers, special attention was paid toblade configuration, contact length and hardfacing type. Non-

rotating rubber sleeve stabilizers were also widely used in theupper sections of each BHA. The inclusion of these assisted incentralizing the drill string and reduced the bending stresses

incurred. Reamers were also selected for the abrasiveintervals. This included both rolling cutter type and those withfixed synthetic diamond inserts. The synthetic diamond insert

type reamers were used primarily on BHAs that included a

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ENGINEERED BOTTOM HOLE ASSEMBLY DESIGN AND EQUIPMENT SELECTION CRITERIASPE 67192 PROVE TO BE KEY FACTORS IN A CHALLENGING DRILLING ENVIRONMENT 3

down hole mud motor and PDC Bit. The use of syntheticdiamond reamers in conjunction with a mud motor and PDC

bit was intended to provide premium abrasion resistance,allowing the BHA and drill bit to remain in the hole for a

longer period of time. The use of synthetic diamond reamersalso effectively increased well bore contact directly adjacentto the bit. This was anticipated to be a benefit in minimizingthe deviation tendency of the BHA and improving well bore

quality.Shock Tools. Axial type shock tools were selected primarilyin the upper and intermediate hole intervals to reduce

damaging vibrations. The shock tool was typically placed in ahigher position, above the upper string stabilizer as priormodeling had shown that placing the shock tool closer to thebit would have a negative effect on controlling well boredeviation. (Fig. 5)Drilling Jars. Jars with both hydraulic up and down actuation

were selected and were included in BHAs for the 14-3/4 inchhole interval onwards. The BHAs selected allowed the drilling jars to be in placed in tension. Analysis software was used to

analyze and optimize jar placement and performance.Optimized Connections. For all components, connectionswere selected that would meet an acceptable range for

bending strength ratio (BSR) at both maximum andminimum diameter tolerances.

The need to establish and maintain consistent standards ofinspection was an integral part of the equipment selectionprocess. In order to achieve this, it was important to have clear

inspection requirements and frequencies. A tiered system from

1 to 3 was used to classify both inspection requirements andinspection frequency with Tier 1 being the more stringent

requirement with a higher inspection frequency. The initialcriteria was as follows:

Inspection Requirements

All BHA components Tier 1Drill pipe only Tier 2

Inspection Frequency Tier 2

A Tier 2 Inspection Frequency equated to a maximum of 250rotating hours between inspection on all BHA components.

The initial criteria established was subject to continual reviewas drilling operations progressed. Results of plannedinspections were reviewed and adjustments made to the

inspection requirements and inspection frequency asnecessary. In particular, while drilling the Des Moinesian andAtokan (Granite Wash) intervals in the 14-3/4 inch hole

section, abnormal damage was noted in the BHA resultingtemporarily in an increase in planned inspection frequency.

During planned inspections, technical support was also

provided at the rig site to interpret the results provided by theinspection services provider. The goal of this was to identifypossible root causes of equipment and connection damage

wherever possible and to implement corrective measuresimmediately at the rig site.

Repair facilities, convenient for the well location, were

evaluated prior to the start of drilling operations. The objectivewas to select facilities that would be utilized for all equipmentrepairs during drilling operations. These facilities wereassessed for their plant and equipment suitability, repair

processes and calibration of quality control equipment.Corrective actions were implemented prior to authorization ofequipment repair.

Engineering SupportHaving continuity of engineering support throughout theplanning, execution and post well analysis phases of thisproject was a fundamental requirement. A dedicated projectengineer was assigned to supervise the BHA prediction

modeling and equipment selection processes. In addition tothese duties, the dedicated project engineer also providedextensive support on a daily basis for ongoing operations.

Interpretation of inspection results and evaluation ofrejected components was provided at the rig site by the projectengineer. This was used proactively to implement preventive

measures whenever possible.Training for all rig floor personnel was also provided

during drilling operations. This training placed primaryemphasis on handling and care of drill stem and BHAcomponents, understanding inspection results, drill stemfailure prevention methods and lessons learned. It was

considered to be important that all involved in the drilling

operations were aware of the primary objectives, and had aforum to discuss observations and ideas.

Data acquired and reports generated before, during andafter drilling operations had also to be reviewed for accuracyand content before being entered into the data management

system.

Drill Stem Failure PreventionAs previously discussed, drill stem failures had been asignificant problem in the offset wells studied in the planningprocess. The two most important factors in drill stem failure

prevention were considered to be the prediction modeling andequipment selection processes. It was also consideredimportant that all rig floor practices used be evaluated to

assess their impact on drill stem failure prevention.Control of Make-Up Torque. The control of connectionmake-up torque is known to have a significant effect on

connection life and failure prevention. Prior to the start ofdrilling operations, a system for automating connection torquecontrol was installed on the rig floor adjacent to the drillers

console for ease of access. The system comprised of threeprimary components. (Fig. 7)

A load cell that electronically measures pull on the tongarm using compensated strain gauges.

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A torque controller unit that monitors the signal from theload cell and sends a command to the cathead air valvesto stop airflow at a pre-determined programmed torquevalue.

A cathead air control valve that stops airflow andexhausts air from the cathead clutch, immediately

stopping connection make-up.

The use of this system ensured that the risk of connection

under torque or over torque was eliminated. During drillingoperations, in the 10-5/8 inch hole section, this system was

temporarily replaced, as a new digital version becameavailable (Fig. 8).

The advantages of using the new system included:

Ease of programming and operation.

Greater accuracy. Optional retrievable history file.

An audible alarm also sounds to alert the rig crew that theconnection make-up has been completed.

Increased Make-Up Torque. During routine inspection, it wasnoted that some BHA component connections had indications

of shoulder separation. Some connections were also rejectedfor cracking in the thread roots that was consistent with afatigue mechanism. At this point, increases in make-up torque

were applied to increase shoulder loading in order to reducedamages associated with shoulder separation. The new revisedvalues were programmed into the automatic torque control

system and communicated to the rig floor personnel as aneffective preventive measure.

Data ManagementA large amount of data was generated during this project inthe planning, execution and post well analysis phases. The

management of data related to the BHA performance andequipment selection processes was therefore an importantissue that had to be considered. Effective data management

would greatly improve BHA performance comparisons, trackcumulative drilling data, track component inspection resultsby serial number and record general equipment commercial

data for materials management purposes.

A newly released system for data management was usedfor this project. This system was modular in construction, with

four primary modules being:

1. Component inspection results and inspection historyby serial number.

2. BHA design data, configuration and daily operatingparameters.

3. Analysis of drilling performance, establishingperformance benchmarks.

4. Tracking of drilling equipment utilization andcommercial data.

Modules 1, 2 and 4 were determined to be the mostappropriate for this project. Each module is programmed in a

common format and has comprehensive search capabilities. Inaddition, modules are linked to allow relational data to bereviewed easily.

Module 1. The inspection data gathered before, during andafter drilling operations was divided into drill pipe and BHAcomponent sub sections. After inspection was completed, theresults gathered were reviewed by the assigned support

engineer for accuracy and completeness of content prior toentry into the data management system. An inspection

database was therefore gradually established for all the itemsof drilling equipment used. Module 2. All activities related to the design and analysis of

the drill stem and BHAs used were documented in Module 2.This included BHA prediction modeling, BHA configurations, jar placement and drill stem strength criteria. During drilling

operations, daily drilling information was also entered inModule 2 to augment the data management system. Module 4. The primary use of Module 4 was to provide a

searchable database of equipment utilization, providers ofequipment or services and the applicable unit costs.

The data management system was also found to be animportant asset in the post well analysis process as itfacilitated the review process for the project. It is also

anticipated that the data management system will also providea significant benefit in the planning process for any futureprojects in the area.

Lessons LearnedBHA prediction modeling. In general the prediction modeling

for this project was accurate. A key goal of controlling wellbore deviation was achieved with rotary drilling assemblies. Apost-well analysis of the formation deviation control index

versus depth did however, show a greater margin of error thanwas originally anticipated from offset well studies in the upperand intermediate hole intervals. This finding will benefit any

future planning requirements for this area.Planned packed hole rotary assemblies were unable to

sufficiently control well bore deviation tendencies in sections

of the 14-3/4 inch hole interval. Contingency pendulumassemblies were required to maintain the necessary inclination

control over this interval.Effective BHA modeling and design also had a positiveimpact on drill bit performance and life. Drill bit life hadexceeded expectations based on offset wells studied and the

evaluation of dull bits utilized. BHA performance. The most significant problems in BHAperformance were encountered in the 14-3/4 inch hole section

in the Des Moinesian and Atokan (Granite Wash) formations.Severe abrasive wear and down hole tool damages attributableto fatigue occurred in this interval. The wear found on

stabilization had created excessive diametrical clearancesresulting in higher BHA deflections and higher bendingstresses. Fatigue fractures were also partially attributed to

inadequate connection shoulder loads and potentially short

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transition zones between drill collar size. To alleviate theproblem of fatigue fractures the following actions were taken

during drilling operations:

Increase of transition lengths when drill collar crosssectional areas changed to distribute stress over agreater length.

Addition of non-rotating stabilizers to support theupper areas of the BHA to reduce bending stresslevels and lateral vibrations.

Review and increase of connection make-up torque toincrease shoulder loads.

Review of operational practices with rig sitepersonnel.

Review and emphasis of allowable wear limits onstabilizers used.

The abrasive wear found on the stabilization points during thisinterval could not be effectively controlled using conventional

tungsten carbide hardfacing techniques. Alternative types ofhardfacing were also used but their performance results wereinconclusive.

(Fig. 9, 10) illustrates the benefits obtained with the additionof non-rotating stabilizers and increasing transition lengths atcross sectional changes.

Conclusions1. BHA prediction modeling techniques proved to be

successful in achieving the primary goal of controllingwell bore deviation.

2. A team approach between the operator, drilling contractorand service company representatives was important inunderstanding goals, objectives and critical requirements

for each party.3. The success of prediction modeling relied on thorough

planning prior to the start of drilling operations. Studyingoffset well data and establishing a deviation control indexwas an important part of the planning process.

4. A formal equipment selection process for drill stem andBHA components was critical in ensuring that the correctequipment design criteria and inspection requirements

were consistently applied.5. Dedicated engineering support for the BHA predictionmodeling and equipment selection processes was anecessity for the planning and execution stages of the

project.6. The addition of equipment and a controlled method of

connection torque assisted in reducing the risk of drill

stem damage or failures.7. The addition of non-rotating sleeve stabilizers in the

upper sections of the BHA was also important in

minimizing the risk of drill stem damage as they reducedthe dynamic stress levels.

8. A comprehensive system of data management providedan effective method for analyzing trends in BHA and

equipment performance. The data management system isalso considered to be important tool in any future activity

that may be considered.

AcknowledgementsThe authors would like to thank K. Stewart Petroleum

Corporation, the management of Smith International, Inc. andBasin Enterprises for their permission to publish this paper.

References1. Williamson, J.S. and Lubinski, A., Predicting Bottomhole

Assembly Performance, SPE Drilling Engineering (March1987).(*)

2. C. Brad Crouch, S.E. Dobler and James K. Carter, Drillingand Evaluating the Hunton at 26,000ft , SPE 9688, 1981

Deep Drilling and Production Symposium, Amarillo, April 5 7.3. R.L. Koenig, An Extraordinary Drilling Challenge in the

Anadarko Basin, SPE 22575, 1991 SPE 66 th AnnualTechnical Conference and Exhibition, Dallas, October 6 9.

4. API RP7G, Recommended Practice for Drill Stem Designand Operating Limits, sixteenth edition, August 1998.

5. D.W. Brinegar, What is the Condition of Your DownholeTools and How are They Being Repaired? , SPE/IADC

18702, 1989 SPE/IADC Drilling Conference, New Orleans,February 28 March 3.

6. G.K. McKown and J.S. Williamson, An EngineeringApproach to Stabilization Selection, IADC/SPE 14766,1986 IADC/SPE Drilling Conference, Dallas, February 10 12.

7. J.R.W. Crowe, W.G. Toohey and J.Holt, A New EffectiveMethod of Maintaining Hole Gauge using Synthetic

Diamond Enhanced Inserts on Downhole Drilling Tools,SPE 57556, 1999 SPE/IADC Middle East DrillingTechnology Conference, Abu Dhabi, U.A.E, November 8

10.

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