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8 Horizontal Drilling

Apr 06, 2018

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    8. 1 Directional Drilling' - Horizontal Drilling

    8.1

    8.2

    8.3

    8.48.5

    ,,

    INTRODUCTION AND HISTORY

    RESERVOIR CONSI CERATrONS

    DRILLING PROPOSAL GENERATION

    MONITORING AND PARAMETERSDATA COLLECTION AND POST WELL ANALYSIS

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    8. 2 Directional Drilling - Horizontal Drilling, ..

    8.1 INTRODUCTION AND HISTORYSTANDARD TERMSThe term "horizontal" identifies a well that stays within the reservoir for some durationto maximize the productive interval. The interval within the reservoir, referred to as the"lateral" section, will have an inclination of approximately 90 deg., plus/minus 20 deg.The total displacement of the horizontal well, from kick off point (KOP) to TO, will notbe significantly greater than the length of the lateral. for example, a short radius welldrilled by the Montedison Group (SELM) off-shore Italy has a total displacement fromKOP of 1191 ft (363 rn), versus a lateral of 1053 ft (321 rn),The term "extended reach" refers to a well drilled to maximize the displacement from_KOP. The extended reach well may have a lateral section; if so, the extended reachwell tends to have a total displacement significantly greater than the length of thelateral. For example, a long radius well drilled by Unocal off Platform Gilda, ott-shoreCalifornia. has a horizontal displacement of 12.740 ft (3883 rn), with a lateral sectionof 5743 ft (1750 m) in the reservoir. Horizontal and extended reach wells are classifiedbased on length of radii as described below and in Fig. 8.1.

    SHORT RADIUSBUILD RATE 20 40 ft (6 - 12 m)1.5 3 deg./ft (5 - 10 deg./m)Short radius technology was developed in the 1930's. and was the earliest type ofcurvature generation technique used to drill laterals. At this time, it became evidentthat increasing exposure to the productive reservoir should have a positive effect onproductivity. Specialised equipment was developed to drill this type of rapid build-up tohorizontal.

    LONG RADIUS 1000 - 3000 ft (300 - 1000 m)BUILD RATE 2 - 6 deg./100 ft (2 - 6 deg.J30 m)Long radius technology also has an established heritage. Used by the Chinese andeSoviets in the 1950's, long radius drilling was revitalized by Esso Canada. Elf and 8PAlaska in the late 1970's and early 1980's. An adaptation to extended reachtechniques used to drill wells to 84 deg. +, long radius drilling employs standard rotaryassemblies and steerable systems to generate the curve and drill the lateral section.Long radius techniques generally are used because of the lateral displacement that canbe achieved away from the rig before the reservoir is penetrated. Usually this techniqueis chosen where expensive surface facilities such as platforms. man-made islands orpads would otherwise be required. Lateral displacement and the length of the lateralusually are limited only by the resultant torque and drag related to the drillstringcomponents and rig capacity.

    MEDIUM RADIUS 300 - 700 ft (90 - 215 rn)BUILD RATE 8 - 20 deg.J100 ft (8 - 20 deg./30 m)Medium radius techniques were developed in the late 1970's. In addition to the desireto re-drill horizontal intervals from existing well bores. a driving force behinddevelopment of medium radius technology were lease line and reservoir constraintsewhich made it necessar to build to 90 dec more raoidlv than could be achieved usina

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    8. 3 Directional Drilling' ..Horizontal DrillingFig. 8.1

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    ,8. 4 Directional Drilling - Horizontal Drilling, ..Short radius techniques were not suitable because of the limited hole sizes andcompletion options available.

    Although curvature rates are established to determine the boundaries of the differentcategories of horizontal wells. the equipment used to generate the curve must beevaluated to distinguish between long and mediumradius techniques.NOTESHorizontal drilling has become a focal point of many. as the number of horizontal wellsdrilled has increased dramatically since the late 1970's. A review of the historicalreferences reveals how the early techniques were developed, and points out theobstacles these early inventors had to overcome._Those who were once concerned over the degree of dog leg severity generated byhorizontal drilling equipment, now are using it regularly to achieve curvature oncethought beyond the limitations of safe drilling practices and the completion equipmentthat would follow. In general, horizontal drilling created greater variances in philosophyand comfort level than technological improvements..There has been a great deal of discussion as to why horizontal wells are increasinglycommon. It has been suggested that the volatility of oil prices since late 1985 has putsignificant pressure on Operators to utilize more cost-effective means to increaseproductivity at lower total field development costs. Increased us of 3D seismic alsomay be a factor. and is credited with giving the explorationist a better idea of the aerialextent of productive intervals. Finally, widespread use of measurement-while-drillingsystems. coupled with steerable drilling systems, have allowed the driller to placehorizontal wellbores with much greater confidence.

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    8. 5 Directional Drilling ..Horizontal DrillingCOMPARISON OF RADIUS METHODS

    SHQBI RADIUS MEDIUM RADIUS !"QNg RADIUSlimited completion All completion techniques All completionoptions techniques

    lateral length limitations No lateral length limitation No lateral lengthlimitation

    lack of azimuth control Good directional control - large amount ofwith mechanical system azimuth directional holeneeded

    Excellent vertical control Good vertical control of largest lateralof reservoir entrance reservoir entrance extension beforereservoir entrance

    Multiple laterals from Multiple laterals fromsingle well single well

    5pecialised equipment 5erni-conventlo nat Conventionalequipment equipment

    Hale diameter limitations More torque anddrag

    BHA requires multiple trips Highest costs

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    8. 6 Directional Drilling ..Horizontal Drilling, ,8.2 RESERVOIR CONSIDERATIONS

    CHOOSING A HORIZONTAL CANDIDATE WELLThe decision to drill a horizontal well should be driven by reservoir considerations. Nomatter why the well is drilled horizontally, analysis of all available reservoir data mustindicate the results are, in fact, obtainable. The number of horizontal wells that weretechnical successes and economic failures provides ample evidence of the truth of thisstatement.Horizontal test wells drilled in the late 1970's proved the viability of the technique.Although further research and development may be needed to drill horizontal wells incertain areas under certain conditions. most proposed wells can be drilled succe~sfully_today. ...ADVANTAGES OF HQRIZONTAl OVER CONVENTIONAL WELLSProductivity from a horizontal wellbore can be from several times to as much as 20times greater than from a comparable conventional vertical or deviated well withdeviation angle up to approximately 45 deg. Generally. an improvement of only about 2.to 2~ times the productivity is sufficient economic justification for drilling a horizontalwell.The major reason for such improvement is that a horizontal wellbore affords muchgreater exposure to the producing zone(s); such exposure is limited only by the lengthof the horizontal portion of the wellbore. (Fig. 8.2)A horizontal well may also offer other advantages:

    Pressuredrops and fluid velocities are less around the well boreWater and/or gas coning is minimizedProduction usually can beacceleratedUltimate recovery often is higherIncreasedproduction can minimize the number of wells required for infill, and thenumber and size of platforms and other infrastructure required.

    Fluid flow and drainage patterns. different in a horizontal well than in a conventionalweU, result in less pressure drop around the wellbore. Lower pressure drops result inlower fluid velocities, so there will be less migration of solids and fines. The lowerpressure drops and fluid velocities alsominimize water and gas coning problems.

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    8. 7 Directional Drilling"- Horizontal DrillingFig. 8.2

    CONVENTIONAL WELL

    VERTICAL HOLE SLANT HOLEDEVIATION

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    FACTORS THAT INFLUENCEHORIZQNTAl WELL PRODUCTIVITYPrincipal factors affecting horizontal well productivity include:

    Reservoir thicknessLateral lengthReservoir heterogeneities such as faults. shale layers. permeability variations etc.Ratio of vertical to horizontal permeabilityLateral location within the reservoir

    Fig. 8.3 plots relative production for equal pressuredrawdown (the ratio of horizontal tovertical productivity indices), versus horizontal well length (portion exposed to thereservoir) for reservoir thickness from 400 - 25 ft where vertical and horizontalpermeabilities are equal (Kv = Kh). A 1,'00 ft lateral in a reservoir 25 ft thick has thepotential to produce about eight times more than a conventional well; i f reservoirthickness is 400 ft, productivity is only accutz.s times greater.Fig. 8.4 plots similar productivity index ratios versus lateral length for various ratios ofvertical to horizontal permeabilities. For a vertical well, radial flow is primarilyhorizontal; a reduction in vertical permeability makes little difference to the productivityindex. With flow coming into a horizontal well from the sides as well as the top andbottom, productivity depends on permeabilities in both planes. The graph substantiatesthe intuitive judgement that productivity for a horizontal well decreasesas the vertical tohorizontal permeability ratio decreases. For example. for the conditions assumed in thisgraph. the horizontal well changes from being four times more productive than aconventional well to only twice as productive when the permeability ratio changes frome1.0 to 0.25 for an 800 ft lateral.

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    Directional Drilling' - Horizontal DrillingNatural fractures. which represent a primary application of horizontal wells. tend toparallel regional trends. Therefore. it is very important that the path of a horizontal wellbe located at approximate right angles to the trend so as to intersect as many fracturesas possible. If directed along the trend, the well could miss the fractures entirelyl SeeFig. S.5Vertical placement also is critical for reservoirswith oil/water or gas/oil interfaces. (Fig.S.6) The phenomenon of water coning experienced with vertical wells is modified witha horizontal well since the water tends to "crest" along the length of the wellboreexposed to the formation. (Figs S.7 and 8.8) the water cresting effect in a horizontalwell generally will be less than water coning in a vertical well becauseof the lower fluidvelocities entering the well. Vertical positioning should be optimized to stay away fromthe water/oil contact (or gas/oil contact)' but located to maximize recovery.

    Fig.8.5

    Fig. 8.6

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    8.10 Directional Drilling - Horizontal Drilling, ,

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    HORIZONTAL

    In summary, horizontal wells are best suited for:Thin formationsRelatively isotropic reservoirs (high ratio of vertical to horizontal permeability)Naturally fractured reservoirsFormations where water and/or gas coning is likely.

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    8. 11 Directional Drilling -_Horizontal DrillingHORIZONTAL WEllS COMPARED TO HYDRAULICAllY FRACTURED CONVENTIONALWELLSFrom a reservoir engineering stand-paint, horizontal wells and hydraulically fracturedwells have many similarities, but one obvious difference is that a hydraulic fractureextends across the entire reservoir thickness, whereas the horizontal well extends over avery small vertical distance (Fig. 8.9)However, as long as it doesn't collapse, the horizontal well has infinite conductivity,whereas fracture conductivity is limited by proppant permeability and fracture width.Also, as reservoir pressure declines, proppant in the fracture undergoes increasinglyhigher closure stress, which can crush the proppant and therefore, greatly reducefracture conductivity.Based on theoretical equations, a horizontal well cannot compete with a hydraulicallyfractured conventional well until permeability is about 1.0 md or more. As reservoirpermeability increases, the advantages of a horizontal well become more pronounced.These are theoretical conditions; what about the "real world"? Actual fracturing ofteninvolves the danger of the fracture leaving the zone and communication with a water.sand. (Fig. 8.10) Also, even though fracture treatment may be designed for a specifiedfracture length and conductivity, target values may be missed during actual pumping. Ahorizontal well, on the other hand, allows greater control over length and location in thereservoir. In other words, horizontal wells may offer greater advantages over fracturedconventional wells than theory predicts.Furthermore, hydraulic fracturing in naturally fractured reservoirs may not work.Hydraulic fractures tend to parallel natural fractures, and the poor results sometimesobtained in formations such as the Austin Chalk testify to what happens in suchsituations. A properly planned horizontal well would, on the other hand, intersect theoptimum number of natural fractures and result in greatly enhanced productivity.In summary, horizontal wells have infinite conductivity and a controllable path. Costand risk factors may offset these advantages, however. Each potential well should becarefully evaluated to determine the best type of well to drill.OTHER HORIZQNTAL APPLICATIONSIn addition to the four situations outlined above, horizontal wells may be superior tovertical or conventional deviated well in other applications. Significant uses include:Accessing several layers of producing sands with extremely high dip angles (e.g. aroundsalt domes). (Fig. 8.11)Accessing several layers of producing sands that may be difficult to locate with verticalwells (e.g. channel sands, reefs). (Fig. 8.12)Circumventing topographical restrictions, such as drilling in urban areas, shipping lanesand deep off-shore waters. (Fig. 8.13)Producing gas from coal seams. (Fig. 8.14)Providing increased sweep efficiency. (Fig. 8.15)

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    8.12 .! .i.

    The Drilling and Production Training CentreDirectional Drilling ..Horizontal Drilling

    .. .Fig. 8.9

    CONVENTIONAL WELLWITH HYDRAUUCFRACTURE

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    8.13 Directional Drilling ...Horizontal Drilling

    Other applications also are being evaluated and developed, including ways to usehorizontal wells for better reservoir management via tighter spacing, and for bettercontrol of injected fluids for EORprojects. It is likely that this emerging technology mayalso unlock doors to lower-cost hydrocarbon recovery in ways not yet recognized by theenergy industry. Most observers believe at least 30% of world-wide drilling will involvehorizontal drilling by the mid-'990's, while the more optimistic experts predict thatpercentage could climb eventually to as high as 70%.TYPEAND SIZEOFHORIZQNTALTARGETMany factors will influence determination of the horizontal target: depth of well;accuracies of marker horizons; survey sensor accuracy; type of curvature chosen;target boundary conditions (lithology); ability to use, and placement of formationevaluation MWD sensors; and productive formation characteristics all will influence tosome degree the ability to hit a predetermined target, and stay within the requirementsof the proposal.Operators drilling in the Bakken formation in North Dakota have been able tosuccessfully place a lateral in a 5 to 6 ft thick target at 10,000 ft + true vertical depth.Boundary formations with higher compressive strengths have positively influenced the.ability to do this successfully. Minimal degree of formation dip also is a factor.Operators drilling a six-inch hole in sandstone reservoirs have much more difficultystaying with a '2 ft "sweet spot" at 4,000 ft TVD. The inability to use resistivitysensors in conjunction with MWD tools, as well as an irregular dip angle in theproductive zone, and long cuttings lag time all combine to make it more difficult to staywithin this larger target.Generalities could bemade, but all of these factors must be evaluated on a case-by-casebasis to determine if the target is viable and economically feasible. Alternativemethods, such as altering the inclination through the lateral to guarantee contact (aswas done in the sandstone example), may be required.

    Fig. 8.12

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    8.14 Directional Drilling - Horizontal Drilling, ,

    Fig. 8.13

    Fig. 8.14

    Fig. 8.15

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    8.15 Directional Drilling - Horizontal DrillingRESERVQIR CONSIDERATIONS: NON-CANDIDATESThere has been considerable publicity recently regarding the "success" of horizontalwells, and very little said about the down side. It should be clearly understood that notevery field will provide an ideal application; often a well will be planned and drilled witha great deal of enthusiasm, becoming a technical success from the drilling stand-point,but an economic failure nonetheless. It is incumbent upon the management of theoperating company to evaluate why the well is being drilled, and to analyze theeconomics in advance. Horizontal wells must be jointly planned by the reservoirengineer, the geologist. petrophysicist, drilling engineer and production engineer. If anyof these disciplines is absent in the planning process, the well is less likely to be aneconomic success.Thus, it is obvious that more than wishful thinking is required to drill a profitablehorizontal well. It takes team-work, with each member of the team exercisingmaximum diligence in his endeavour. While there are many reasons to drill a horizontalwell, rarely has improved well productivity alone been economically successful.Incomplete reservoir information, leading to erroneous assumptions about the rock andfluid properties, also will contribute to the chances of failure. Formation damagemechanisms must be well known in the candidate field; the nature of horizontal.completions, and the sheer length of the exposed reservoir face. make remedialtreatments extremely difficult and costly.WHERE HORIZONTAL WEllS MAY NOT SUCCEEDA well recently drilled in the Philippines illustrates the point made above. The well wasdrilled horizontally in an attempt to make a deep water, marginal oil field economical todevelop. The only reason for drilling horizontally was to improve productivity in thesandstone reservoir. There were no other reasons, such as elimination of water coningor interception of natural fractures. Incomplete understanding of the reservoirproperties, together with extensive and irreparable damage to the formation by thedrilling fluid, made the well a technical success. but an economic failure. With 2100 ftof horizontal well bore in the producing sand, the well made approximately the samerates as a vertical well with only 160 ft of reservoir exposed.In each and every case, it is the responsibility of the engineering team and theirmanagement to be realistic and pragmatic about the reasons for drilling. Frequently, alittle more information or thought could have prevented failure, either by not drilling thewell, or by using different drilling or completion practices.BASIC PROJECT ECONOMICS: HORIZONTAL VS VERTICAL WEllSThe same basic considerations used to prepare project economics for vertical wells areemployed to evaluate horizontal drilling projects. The followinq variables are the basisfor the sound economic evaluation of potential drilling ventures:

    Costs to lease. drill, complete and equipAnticipated EOR and production scheduleProduct prices

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    8.16 Directional Drilling - Horizontal Drilling. ; Risks and contingencies

    Deal and tax structures.What follows is a brief discussion of how each factor should be determined for ahorizontal well:COSTSPrior to drilling a horizontal well, it should first be determined whether the project focusis research and development, or the basis for immediate economic gain. Many times,the initial wells are drilled to test and modify current horizontal drilling and completiontechniques. Accordingly, there has been little attention paid to these "expensed" costs._When this approach is taken, the value of information is the primary reward, and therSWis no need to performanything more than cursory economics.But assume we are expected to show immediate returns on our horizontal wells. Afterdetermining the most efficient means of drilling and completing the subject horizontalwell (using techniques described elsewhere in this manual), it is necessary to estimatethe corresponding cost.This cost estimate should be performed by time andmaterial analysisjust as it would ona vertical well, with two exceptions. First, the effect of a significant "learning curve"should be applied to the predicted costs of the first and subsequent wells. Althoughcosts may vary over a wide range of horizontal applications, a general model forcalculating relative well costs ($/ft of relative measured depth) based on this "learningcurve" is shown in Fig. 8.16. The curve is indicative of a company drilling its firsthorizontal wells in a particular area, and reflects the value of experience from well towell.The second consideration in producing a horizontal well cost estimate involves thepotential for cost over-runs associated with changes in the scope of the project inprogress. These additional costs are difficult to quantify, but emphasize the importanc_of thorough pre-project planning and coordination. These incremental costs areaddressed in the discussion on "Risks and Contingencies".EaR AND PRQDUCTION SCHEDULEEOR and production scheduling should be performed using a combination of thefollowing three resources:

    local horizontal well production databaseHorizontal well reservoir modelslocal vertical well production database.

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    8.17 Directional Drilling' - Horizontal Drilling

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    8.18 Directional Drilling - Horizontal DrillingOf 'greatest importance is a production database of local horizontal wells in the subjectreservoir. As horizontal drilling becomes more prevalent, an increasing volume ofproduction history is made available to guide investment decisions. If productioninformation from nearby horizontal wells of similar scope is available, its value should beweighted more heavily than information from models or vertical wells.Horizontal well databases can provide other valuable information. including well costs,problems while drilling. completion techniques, well directions. lateral extensions andgeological abnormalities such as fracture occurrence. water level etc.Horizontal well productivity models are another means of predicting flow rates andultimate recoveries. While there is significant subjectivity associated with these models.'they do provide another data point for predicting production profiles. Currently. modelsaexist for use with at least three horizontal drilling applications: ' FRACTURED RESERVOIRSUsing models to predict performance in fractured reservoirs is extremely difficult. Thesemodels require extensive knowledge of fracturing patterns, frequency and significance.Because this information is both difficult to accumulate and statistically unpredictable, a.high correlation between predicted and actual well performance is unlikely, especially insingIe-well applica tions.WATER OR GAS CONING RESERVOIRSDrawdown is the significant input variable in these models, and can be estimated withreasonable accuracy for horizontal versus vertical wells. For this reason, models are ofgreat use in predicting the incremental production performance associated withhorizontal wells of this type.THIN, HOMOGENEOUS RESERVOIRSHorizontal wells are drilled in these applications to replace or supplement hydrauli~fractures. These models are based on the comparison of (infinite) conductivity andextension of horizontal wellbores. to the conductivity and extension of hydraulicfractures. They also can predict the incremental production of horizontal wells fairlyaccurately.The last input information in predicting horizontal well performance regards theproduction history of local vertical wells. Clearly, there is a local relationship betweenthe performance of vertical and horizontal wells. Monitoring this relationship can yieldbetter production schedules over time. Also. in areas where there has been little or noprevious horizontal activity, an increment over average vertical well performance is usedto generate horizontal production schedules. An often-used generalization (with largerisk of error) is that a horizontal well will double the production of a vertical well. Thismay be used as a starting point for production data where no other techniques exist.

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    8.19 Directional Drilling ..Horizontal Drilling8.3 DRILLING PROPOSAL GENERATION

    The most important elements of a successful horizontal well project are a detailed andeffective plan. coordination of all aspects of the plan and team work. The planningshould begin with reservoir considerations and logging requirements, followed bycompletion needs. before drilling details are finalized. The most successful horizontalwell is attributed to internal coordination of production, completion. reservoir and drillingpersonnel, to maximize interaction between the entities to create the desired results.(Fig. 8.17)

    Fig. 8.17

    COMPLETION NEEDS DETERMINATIONAfter the horizontal well candidate has been selected based on reservoir considerations.it is necessary to determine the type of completion technique needed to optimizeproductivity results or isolation needs. To do so, the planned well history must beevaluated to determine if remedial work or stimulation techniques will be conductedduring the well life-cycle, as this will also influence the complexity of the completiondesign. All subsequent decisions will be based on the economics and technologicalcompetency of, and value added by the techniques under consideration.

    While service companies are actively testingcompletion techniques for shortradius laterals, open hole, slotted liner and pre-packed gravel packed screencompletions have been most successful to date.

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    8.20, Directional Drilling ..Horizontal DrillingDetermining the optimum build-up rate is based on many relational factors. Thecurvature may be dictated by the decision to redrill an existing well, as opposed todrilling a new well. Further, after choosing a completion technique, limits to dog legseverity and hole sizealready may be set.Curvature selection can be determined only after properly evaluating the productionformation and lithology above the reservoir. where the kick off will be conducted.Vertical depth uncertainty of the reservoir, and availabllitv or absence of geologicalmarkers as reference points. will strongly influence choice of curvature and maydetermine the need to contact the reservoir and then plug back. The need for verticaldepth accuracy will increase as the size of the target decreases. The shorter the radiusof curvature, the better control of entrance into the reservoir. Dog leg severity may beincreased due to troublesome formations at initial kick off; therefore, a vertical hole ..could be extended so the kick off would occur deeper. ...The anticipated length of lateral, as discussed below. also will influence the curvatureused to reach horizontal. Lease line constraints, in conjunction with an expected longlateral would dictate that the target entry be as close as possible to the vertical line(from rig). Conversely, long radius curvatures are selected to extend the target entry asfar as possible from the vertical line in order to increase lateral displacement from.expensive structures such as islands. platforms or pads.Curvature selection will present a series of "trade-offs" affecting each of theconsiderations mentioned above. For example. although it is not possible at present.drilling 2,000 ft of lateral hole using a short radius curvature would minimize thedirectional hole and make the contact point with the reservoir much more accurate.Although there are few selective completion techniques available for short radius wells,the advantages from being able to place a pump much closer to the reservoir mayoutweigh the disadvantages. This type of "flow-chart determination" also influenceslong andmediumradius techniques.LENGTH OF LATERALIn very few instances is the length of the lateral hole selected for valid engineeringreasons. Often. an "achievable" length is selected with no more justification than thatanother company was able to drill that far. Other times, the horizontal length is dictatedby the desire to set a record. While record-setting is admirable, there must be moresound reasoning behind the "decision" to drill horizontally for 4000 ft or mars.HOLE SIZEHole size will be determined after evaluation the completion needed, and decidingbetween a new well and re-drill. Hole sizesin re-drill programmeswill be predeterminedbefore almost anything else is evaluated. Economics playa large role in this decision.but can't always be the determining factor.When determining the casing programme, decisions should be influenced by previousdirectional or straight hole well programmes, but may merit change based on otherconsiderations. For example, there may be limits imposed by the directional equipmentthat must be run in the hole to drill the curve and lateral. Or advantagesmay be gainedby casing off the exposed hole above the reservoir to ensure drilling parameters aremaximised for the production interval onlv. An extra casinn ~trinn m::lv ha ran, ,iraA t o . .. .

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    Savings of as much as 50% can be realized by drilling from larger casing sizes. Smallercasing sidetracks can be extremely expensive because of the limitations of small drillingtools.PLANNED WELL L1FE-CYCLECompletion selection will be determined, based on the estimated life of the well, andwhat remedial work, if any, may be needed in the future to ensure good productionresults for a long time. Since the industry lacks significant long term production resultsfrom horizontal wells, these decisions still involve a lot of uncertainty. Little has beendone to date, to determine if horizontal wells can be sidetracked in the horizontalinterval at a later date to prolong well life. Some remedial work has been successfullyconducted, but the ample work that remains to be done in this area will influenceconstruction of horizontal wells in the future.DEPTHITUBULARS - TYPE AND SIZEPlanning a horizontal well often involves a decision about the hole size to be drilled.There are no clear "rules" to follow in selection of the hole size. Instead, the well mustbe considered as a total system.The desired completion, and anticipated production and workover profile of the well is agood place to start the hole size selection process. Formation evaluation needs (l.e.MWD versus full, drill pipe conveyed log suits, versus simple mud logs) can influencethe decision. In addition, the lithology and pressure profile will dictate the need forprotective casing strings which, together with economic analysis of the cost to drill onehole size as opposed to another, can further narrow the choices.Finally, field drilling practices can be a major factor; in some areas there is littleexperience in drilling unusual hole sizes, and this can have significant impact on thedrilling cost. Although tool availability can dictate casing sizes, probably the poorestreason to drill a particular hole size, and to use a particular size of tubulars, is that thetubulars are already in inventory. Adopting this approach to well design will invariablyresult in additional costs.KICK OFF POINTWhen the radius of curvature has been selected based on previous considerations, theKG? must be determined. Many factors influence this decision including, but not limitedto lithology considerations, economics, reservoir entrance constraints and previousdirectional experience in the field.LITHOLOGY CONSI DERATIONSBeginning the kick off in troublesome formations should be avoided i f possible.Selection of directional apparatus to start the curve in most cases, is influenced by theformation. If the equipment does not build at the required rate, or builds too much, itmay be necessary to "play catch up" during the remainder of the drilling, or to trip anew assembly shortly after starting.

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    The Drilling and Production Training Centre8.22 Directional Drilling ..Horizontal Drilling

    DIRECTIONAL LENGTH CONSIDERATIONSThe shorter the curve. the better the accuracy of entry into the reservoir and usually,the cheaper the curve. Another consideration is that the shorter the curve, the closerthe entry point to the surface location. Operators like BP and Elf Acquitaine want longlateral extension before penetrating the reservoir because of the high cost of surfacefacilities and lack of lease constraints. Others, like Unocal, the Netherlands, want toreach the reservoir quickly because of the limited extent of reservoir delineation.Operators drilling in the chalk in the US want as much lateral contact with the reservoiras possible before running out of lease area, so they choose faster curve-generationtechniques.The length of the directional interval depends on a number of factors which areeessentially outside the control of the drilling engineer. These include formationproperties discussed above, governmental regulations, surface location restrictions,target considerations and anti-collision considerations.However, some limits on directional work are imposed by the drilling engineer. Often atarget tolerance has been given in advance of the directional profile desiqn. The drillingengineer can use these tolerances as a "budget", allowing each portion of the well to. use a percentage. In close tolerance wells, the drilling engineer must use tightertolerance drilling techniques to improve his accuracy. This is most economicallyachieved by selecting a portion of the hole which can be drilled to a tight tolerance for areasonable cost. In horizontal drilling, tighter tolerances usually are achieved by higherbuild rates. Fortunately, the shorter drilled hole length offsets the higher equipmentcosts. Therefore. a medium radius kick at the end of a conventional long radius buildcan economically contribute to the overall accuracy of the horizontal well.On-shore US work generally will continue to be largely medium and short radiushorizontal work. due to spacing limitations. Small proration units do not leave adequateroom for a long slow build, followed by a properly designed horizontal section. Shortradius wells are expected to be the norm for spacings less than 40 acres. although __recent decisions by stata oil and gas regulatory commissions may change this. Some ....commissions may begin to allow dedication of several proration units for each horizontalwell. An example is the Texas Railroad Commission's decision to change fieldproduction rules based upon the horizontal length in the reservoir. However. otherstates are still trying to decide just what to do with horizontal wells.RESERVOIR ENTRANCE PREDICTABILITY AND CONSTRAINTSThe single most critical aspect of horizontal drilling is choosing the appropriate build rate(radius) to facilitate reservoir entry at the target point. The following table summarizesthe relative advantages and disadvantages of the three main horizontal drillingtechniques with respect to reservoir/target entry:SHORT RADIUS:

    Target height:Build rate:KOP above TO:

    5 - 20 ft1 - 3 deg'/foot 25 ft

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    8.23 Directional Drilling' - Horizontal DrillingShort radius techniques yield high build-rate predictability and good reservoir entrycontrol for very thin reservoirs. Drawbacks of the short radius system include poordirectional control (azimuth), poor correctability and limited lateral extension.MEDIUM RADIUS;

    Target height:Build rate:KOPabove TO:15 - 100 ft6 - 20 deg.l100 ft 300 ft

    Medium radius techniques yield high build-rate predictability and fair reservoir entrycontrol for moderately thin reservoirs. However, medium radius drilling provides forgood directional control (azimuth), goad correctability and good lateral extension. Thetechnique is applicable over the widest range of conditions.LONGRADIUSi

    Target height:Build rate:KOPaboveTO:> 15 ft1 - 6 deg.J100 ft1,000 - 2,000 ft

    Long radius drilling offers fair build-rate predictability and poor reservoir entranceaccuracy. Advantages include good directional control (azimuth), good correctabllityand exceptional lateral extension. The major drawback is the increased cast associatedwith additional target control and measured footage.In summary, thin reservoirs requiring little extension should be drilled using short radiustechniques. Conversely, thick reservoirs requiring large lateral extensions should utilizelong radius techniques. Medium radius drilling can be applied over a wide range ofapplications. For this reason, most wells currently employmediumradius build rates.MECHANICS OF TORQUE AND DRAGModelling and estimating torque and drag in directional wells is a relatively newtechnique. In a publication by Johancsik, et.al,' of ExxonProduction Research.a torqueand drag calculation technique is outlined, and Exxon Corporation's use of this newtechnology is discussed. At about the same time, Mobil Research and Developmentalso developed 8 drag/torque model as a key element of their joint industry ExtendedReach Drilling Project. As a result of these two concurrent efforts, the technique wasrapidly disseminated into the drilling industry at large.Calculation of torque and drag in a directional or horizontal well involves application ofsimple principles of physics. Classic sliding friction theory is used.

    F=pNwhere:

    F = = Friction force (lbs)J 1 = Friction coefficient (dimensionlesslN = = Normal contact force nbs)

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    8.24 Directional Drilling ..Horizontal DrillingThis concept requires calculation of the gross normal contact force within an interval ofpipe, and an estimation of the sliding coefficient of friction. With these two knownfactors, the drag, torque and tension can be obtained at the top and bottom of the pipeinterval. The normal contact force is usually calculated by conSidering only twecontributing factors: the effect of gravity on the pipe and the effect of tension acting incurvature.Other factors which contribute to the normal contact force include buckling, bending,and internal-te-external differential pressure. For a horizontal well, where use of acompressive drillstring is mandatory, buckling contact forces should be included. Theother effects are generally considered to be small contributors, and are usually ignored.Widespread use of drag/torque models has led to the conclusion that the slidingcoefficient of friction appears to be the major source of torque and drag in directional.wells. . ..FRICTIONCOEFFICIENTThe so-called sliding coefficient of friction used in drag and torque models actually is anaggregate of many different, but related parameters, and is difficult to quantify withdirect, laboratory measurements. In reality, it depends on the contacting surfaces and.degree of lubrication, both of which assume many different values in typical wellbore.Therefore, in practice, it is obtained by taking the ratio of the friction force to the normalcontact force.If, for example, there is 10,000 Ibs of drag, and the total normal force is 40,000 Ibs,then by use of the friction equation, the coefficient of friction is 0.25. This is the fieldtechnique for arriving at a coefficient of friction for a particular well bore. The frictionfactor is estimated, the computer model is run and the friction coefficient is adjusteduntil the observed torque and drag valuesmatch the calculated results.Obtaining a realistic value for the friction coefficient requires the following information.An accurate description of the wellbore geometry, a description of the driJlstring and..field measurement of pick-up weight, slack-off weight and rotating torque. The first..,two can be easily and accurately obtained; the field measurements require much morecare. It is important when taking the field measurements, to ensure that sensors areaccurately calibrated and the observation conditions are steady state when readingsaretaken. Any acceleration terms will cause an erroneous increase in the apparent frictioncoefficient. Each of the three separate field measurementscan lead to an independentfriction coefficient; the confidence with which the computer simulation can be usedincreases as these three values converge.It should be remembered that the friction coefficient is affected by many otherparameters, and will frequently change as a function of time or hole condition. Build-upof cuttings on the low side of the hole, for example, often will cause dramatic increasesin the friction coefficient, and can make the friction coefficient for pick-up appear to bedifferent than for slack-off or rotation. Wall-force related hole problems, such as keyseats, also will cause abnormalities in the friction coefficient. Once the mechanismscausing torque and drag are clearly understood, these changes in the apparent frictioncoefficient become valuablediagnostic aids, allowing the drilling engineerat the well siteto correctly identify the nature of downhole occurrences.

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    8.25 Directional Drilling - Horizontal DrillingOther variations in friction coefficient may be localized in nature, due to variations in thesurfaces which are in sliding contact. For example, cased hole exhibits differentcharacteristics than open hole; an abrasive sandstone behaves differently than a cleanshale. The ability of a torque and drag model to allow input of multiple frictioncoefficients can greatly improve its utility. although more user experience will berequired to obtain the benefit.COMPOUND FRICTIQN THEORYConventional friction theory states that the friction force acts in the opposite sense tothe motion. This means that if the pipe is pulled out of the hole, the friction opposesthe motion and the resultant drag causes an increase in string tension. As long as thepipe is not simultaneously rotated. all the friction is seen as drag. Similarly, when thepipe is rotated without any axial motion. all of the friction is seen as torque.If, however, the pipe is rotated and moved axially at the same time, the friction acts inthe opposite sense to the resultant motion. This is a very important concept, sincerotating the pipe as it is moved into or out of the well will alleviate the axial friction.While this reduction in axial drag is usually not needed in medium radius horizontal wells.due to the normally low levels of drag, it providesthe principlemechanism by which it ispossible to apply weight on bit when the pipe is being rotated from the surface.Because the pipe is being rotated, and becausethe tangential velocity due to rotation islarge compared to the velocity with which the pipe is being advanced down the hole,almost all the friction is seen as torque; there is very little axial drag. The Mobil-sponsored ERD project previously mentioned successfully confirmed the applicability ofthis concept in the field. Despite this, there appears to be very little understanding ofthe concept among field personnel.To determine the individual coefficients of friction in the axial and rotated (tangential)directions, a resultant velocity must be calculated. Then, by simple vector analysis, theaxial and tangential friction coefficients can beobtained. (Fig. 8.18)

    = BQf60

    = " (RPMlDt j12

    jJVox(V ox2 + Vton2) l' zPtan jJ V tan

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    8.26 Directional Drilling Horizontal DrillingWhete:

    Vex = Axial velocity (ft/min)Vtan = Tangential velocity (ft/min)Rap = Penetration rateRPM = Rotary speedDti = Diameter of tool joint (in.)P = Gross friction factorPax = Axial friction factorPlan = Tangential friction factor

    Calculation of torque and drag in real wellbores requires use of the individual friction.factors in the axial and tangential directions.GRAVITY; NORMAL AND TENSIQN FORCESA length of pipe lying on a ramp of constant inclination from vertical has a normalcontact force and incremental tension due to gravity, given by the following equationsand Fig.8.19.

    Fnorm =Fex =

    Where:Fnorm =Fax =w =L =e =

    wLsin9wLcos9

    Normal force of pipe on hole wall (lbs)Axial weight of pipe (lbs)Buoyedweight of pipe Ub/ft)Length of pipe interval (ftlInclination < (degrees)

    For a curved section of well bore, the gravity-induced normal force and incrementaltension can be obtained reasonably accurately by ignoring the curvature and using theaverage inclination angle, as long as the interval length is not too long. It is aninteresting observation that the effective weight of a string of pipe in a directional wellcan always be obtained by the product of the true vertical length and unit buoyedweight of each component. This is the most accurate method, and should be used if theinterval length is long, or the curvature very high. It

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    The-,Drilling' and Production Training CentreDirectional Drilling' - Horizontal Drilling

    Fig. 8.18

    Vu

    Fig. 8.19

    Fnorm

    wL

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    8.28 Directional Drilling - Horizontal Drilling,.. Fig. 8.20

    Fcur ;; nfaL18000

    Fcur ;; Curvature normal force of pipe on hole waUlbsF ;; Effective tension lbsa "" Curvature of we!lbore deg.l100 ftL ;; Length of pipe interval ft

    t;IC\. O[lOIttts

    The normal force due to gravity is the major contributor to drag and torque in any longsection of wellbore which has high inclination and low curvature. such as the horizontalinterval. At the upper limit. all of the buoyed pipe weight becomes normal force at ,90deg. inclination, but at the same time, it then contributes nothing to the tension.Minimisation of drag in intervals of this type usually involves running the lightest weightpipe possible. provided that no other adverse effects. such as buckling, result.CURVATURE NORMAL FORCEWhen an element of pipe is curved, it exerts a normal force on the wall of the hole,equal to the product of the average effective tension and the total curvature in radians.In field units, this relationship is shown in the following equation. A good analogy isthat a cable being pulled over a curved surface; the contact force depends on the cabletension and the radius of the curved surface. This assumes that the stiffness of thecable is insignificant relative to the radius of curvature. Most drag/torque modelsimplicitly make the same assumption, and have consequently been referred to as "soft-string" models. In most field applications, this has proven to be a good approximation. e

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    8.29 Directional Drilling' ~Horizontal DrillingFeur =Feur =F =a =L =

    m : m . .18000Curvature normal force of pipe on hole (Waillbs)Effective tension (lbs)Curvature of wellbore (deg.l1 00 ft)Length of pipe interval (ftl

    The curvature normal force acts in the direction concave to the curvature for positivevalues of tension, and convex to the curvature for negative tension (compression), In anormal directional well, with the drillstring in tension in the angle build interval, thecurvature normal force is directed up, and the gravity normal force, down. There is alsosome alleviation of the curvature normal force provided by the pipe weight. (Fig. 8.20)The situation is reversed with a compressive loading in the angle build interval; both thecurvature and gravity normal forces are directed down. It is very simple to determine ina given situation where in the hole the pipe is lying top or bottom by calculating the.magnitudes and directions of the two respective normal forces.One implication of this is that in a normal directional well, the pipe rides the high side inthe build; in a medium radius horizontal well, the pipe is almost always on the low side.This may partially explain observed differences in hole cleaning behaviour.Depending on the specific conditions of tension and local curvature, this curvaturenormal force can be very large or quite small. High curvature normal forces are usuallyproduced in conventional long reach directional wells, where high build rates are oftenseen together with high drillstring tensions.ln medium radius horizontal wells, despite the high curvatures, the curvature normalforces remain at reasonable levels due to the relativelv [ow compressive loadings whichexist in the angle build.The magnitude of the normal force of the drillstring on the wall of the hole is importantfor more than just drag and torque. If the loading of each tool joint and/or pipe body onthe wall of the hole becomes too high, well bore or drillstring problems will result. Pipefatigue can occur, or it may be possible for the wall of the hole to fail mechanically.which may be seen initially at the surface as sloughing, and eventually as key seating orhole collapse if the problemis allowed to continue unchecked.Earlywork by Lubinski indicated that contact loads of more than 2,000 Ibs/tool joint, incased hole. accelerated pipe fatigue. Fie[d use of a drag/torque model by AmocoProduction Company has been able to consistently relate key seat formation in soft rockto contact forces exceeding 1,500 lbs/tool joint. The magnitude of the maximumcontact force which is safe for a particular circumstance is dependent upon the grade ofsteel in the drillstring, the size and contact area of the tool joint, the hardness of therock if in open hole, and whether or not the pipe body also is contacting the hole wall.In a normal directional well with a tension drillstring desiqn, there is usually a high stringtension in the angle build portion of the well. This results in very high normal contactforces if the curvature is high, and in most wells of this design, most of the drag andtoraue orininata in thA ::.nnlA hllilrl intMV::l1

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    8.30 Directional Drilling -Horizontal Drilling,,

    Common techniques for drag and torque reduction in these wells consist of minimizingthe buildrata, or using less bottomhole assembly, or lighter drillstring below the anglebuild. These techniques work by reducing either the tension or the curvature, both ofwhich are directly proportional to the normal forces.Inmedium radius horizontal wells, the situation is much different. Becausecompressiveloading through the angle build is needed to transfer weight to the bit. the tensioncondition in the curved interval is relatively low when compared to a normal directionalwell. This allows usa of much higher curvatures without adverse effects on torque anddrag. In both types of wells, it is prudent to forecast the drag, torque and normal forcemagnitudes during drillstring design.BUCKLING NORMAL FORCEIn wells drilled with tension drillstring designs. buckling of the tubulars is rare, sinceconvention dictated placement of the effective neutral point within the thick-walledBHA. In recent years, this has been a marked shift in operating practices, caused by theneed to drill some very long departure directional wells in which it became impossible toapply reasonablebit weights if the older. conservative philosophywas applied.This prompted some re-examination of Dellinger, of early Lubinski work on thecontribution of hole angle to drill pipe stability, based on elastic stability theory byTimoshenko. Finally, Dawson, et.al., provided a sound analytic basis for theexperimental data.Dawson's paper states: "In high angle wells. the force of gravity pulls the drillstringagainst the low side of the hole. This stabilizes the string and allows drill pipe to carryaxial compressive loads without buckling. For this reason. it is practical to run drill pipein compression in hjgh~angledrilling where the drill collar weights, which are needed toavoid compression, would cause excessive torque and drag."While this concept is very useful in reducing drag and torque in high-angle, extended ...reach directional wells, it becomes essential in the drilling of horizontal wells. At..,inclinations of 90 deg. or more, it is not possible to obtain bit weight using a tensiontype drillstring design. Instead, the drilling weight is obtained by placing the drillstring incompression through the curve and lateral intervals. This necessitates use of drill pipein compression. As long as the pipe remains in the elastically stable region, no damageoccurs to the pipe. However. once buckling begins, wall contact forces increase rapidlyin an almost-geometric progression. .The onset of buckling. with the additional wall contact force, increases the frictionalloading, which then requires the application of more axial load to maintain the same bitweight. This in turn, causesmore severebuckling, and the cycle repeats.A parametric study of the effect of buckling on drillstring design and operatingparameters indicated that the best string design was one in which buckling was avofdedaltogether. However. when attempting to drill oriented in lateral wells. it often is almostimpossible to avoid buckling if any weight transfer is to be made to the bit. In thesecases, drillstring design demands very careful thought.

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    Directional Drilling' - Horizontal Drilling

    Fe titCRITICAL BUCKLING OF PIPE IN INCLINED WELL

    Where:Fcrjt

    E

    we

    D p

    = 2(2Elwsin0) V a(1 2(Dh - Dtj)]= "(Dp4 - Dj4)64

    = Critical buckling force (1bs)= Young's Modulus (Ibs/inch2)= Moment of inertia (inch+)= Buoyed weight of pipe (lb/ft)= Inclination (degrees)= Diameter at hole (inch)= Diameter of tool joint (inch)= Diameter of pipe body (inch)= Inside diameter of pipe (inch)

    Examination of the critical buckling equation above shows that the allowablecompressive load increases as hole inclination and pipe stiffness increases, and as theclearance between pipe and hole wall decreases. The most sensitive terms are theoutside diameter of the pipe body and the difference between the tool joint diameter andhole diameter.The best way to increase the critical buckling load is to increase the size of the pipe,with oversized tool joints a fair second best choice. Use of lightweight aluminum pipein the compressive interval is not recommended because. while it promises reducedtorque and drag by virtue of its low weight, it suffers from reduced critical bucklingloads due to its low modulus of elasticity (approximately 10.6 million psi, as opposedto29 million psi for steel). Tables at the end of this section show critical buckling loadsfor various sizesand weights of pipe in commonly used hole sizes.When pipe buckles, it assumes a helical shape in the borehole, and creates additionalloading between the pipe and hole. The calculation of the length of the helix is difficult;the commonly used equation by Lubinski differs from that derived by Cheatham andPattillo; both consider the pipe to be weightless. More work in this area is necessary.The equations that follow provide approximations only for torque and drag calculation.

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    8.32 Directional Drllllnqs.Horlzontal DrillingPITCHOFHELIX IF BUCKLED

    P2 = 8TTEI12Fp2 = 4nOEI12F

    Where:

    p = Pitch of helix (ft)F = Axial load on pipe (lbs) " eE = Young's Modulus (lbs/in2)

    = Moment of inertia On4)

    .CONTACT FORCEOFBUCKLEDPIPEONHOLEEbuk = 3 (04 - OljlF2L2EI

    Where:Ebuk = Lateral buckling force (lbslDh = Diameter of hole (in.)Dti = Diameter of tool joint (ln.)F = Axial load in string (lbs)L = Length of buckled pipe 1ft)E = Young's Modulus (lbs/in.2)

    = Moment of inertia On.4)The equations above show clearly that use of tool joints or couplings which are largerthan the outside diameter of the pipe will increase resistance to buckling. However,Lubinski's work on drill pipe in tension in dog legs also shows that the tool jointssignificantly increase the bending stresses over that which would have occurred simplyfrom the hole curvature.When the drill pipe is in contact with the hole wall only at the tool joints, the radius ofcurvature of the pipe is not constant. in this case, the maximum bending stress willoccur at the centre of the joint, and can be considerably higher than for uniformlycurved pipe. The maximum bending stress in tool-jointed pipe can be estimated usingthe following equation:

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    Directional Drilling - Horizontal Drilling

    =Where:

    K =

    218aDtj(6Ky)tanh(6Kljl

    lElli_[EI1~And where:

    Sb = Maximum bending stress (lb/inch2)a = Hole curvature (deg.ll00 ftl011 = Diameter of tool joint (in.)lj = Length of pipe joint (ft)F = Axial load on pipe (lbs)E = Young's Modulus (lbslin.2)

    = Moment of inertia (in.4)DRAG AND TORQUE FROM NORMAL FORCESOnce the individual components of the normal force have been calculated, all thatremains is to sum them vectoriaJly into the total normal force acting on the interval, andthen to calculate the resulting drag and torque by applying the sliding friction equationusing the appropriate friction coefficients.

    T =

    Where:

    F, Fi+l =T =Flat =

    Fbuk =Otj =

    Fnorm + Fcur

    = Drag force on interval (lbs)Axial tension at top of l, i+ 1 element of string (lbs)Torque in interval (ft-lbs)Lateral force of pipe on hole wall (lbs)Lateral buckling force (lbs)Diameter of tool joint (in.)

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    8.34 Directional Drilling - Horizontal Drilling, , Axial friction factor

    Prad Tangential friction factorADDITIONAL ITEMSOther factors can influence the magnitude of the normal contact force. The "soft-string" model described ignores the stiffness of the individual element lengths used inthe calculations. For relatively limber drill pipe in normal curvatures, this is a reasonablesimpli ficati on, but for driII colla rs, 8HA 's and Iarge 0 D drills trings j n tight cIearanc esituations, some corrections are required.Internal-to-external differential pressure, acting in thin-walled tubulars, can produce a ...straightening effect on the pipe, contributing additional normal contact force. In most .,cases, this contribution is small. However, it can be significant with large diameter,thin-walled tubulars in strong curvature with high pressure differentials, such as in drillpipe in the lower part of the angle build interval. Most torque and drag models simplyignore these additional factors.CALCULATION OF TORQUE AND DRAGCQMPUTER ALGORITHMThe usual algorithm for computer computation of drag and torque is as follows: thedrillstring is described as a number of sections with uniform properties, for example, drillcollars, drill pipe and heavyweight pipe. For each section, the length, tool joint diameter,pipe diameter, pipe 10, pipe weight, moment of inertia and elastic modulus are specified.The well bore trajectory is described by means of a survey file. A table of depths versushole diameters and friction coefficients is provided, and operating parameters are thenspecified tl.e, depth of interest, weight on bit, torque at bit, rotary speed and axialvelocity).With this basic data, the next step is to determine a computation interval. This is often etaken as the basic survey interval, but could be any interval length desired ifinterpolation is done on the survey data. Often, 100 ft is used as a convenient length;the length of a [oint of pipe can also be used, which will then roughly equate the normalforces to tool joint loadings. Starting at the bottom of the hole (or the depth ofinterest), the end conditions of torque and axial load are applied, and the normal forcesare calculated and vectorially summed for the calculation interval up the hole. Thisprocess is repeated until a surface load and torque are obtained.Total axial drag for pick-up and slack-off are obtained by running the model three times.Drag is the difference between the free rotating string tension and the tension obtainedwith axial motion. If the compound friction model is included, variations are possiblewith various combinations of rotary speeds, bit weights and penetration rates. Usefuloutputs display pick-up, slack-off, free rotating weight and drilling torques versus depthof complete hole intervals; or profiles of normal contact forces, string tension, stringtorsion and critical buckling load versus depth for a particular depth and operatingcondition. Graphical output is particularly useful for assimilating the large amount ofdata which is typically generated during the analysis.

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    .8.35 Directional Drilling - Horizontal DrillingSIMPLIFYING ASSUMPTIONSDepending on the fidelity of the particular model, many or few simplifying assumptionsmay have been made. It is important to the end user to be aware of these. The usualsimplifications are listed below. in the order they most frequently occur:

    No allowance for stiffness of string componentsNo allowance for BHA components (stabilizers etc.)No allowance for effects of differential pressureNo buckling force modelNo provision for multiple friction coefficientsNo provision for multiple hole sizesNo compound friction model

    LIM!TATIONSThe overall utility of the model is affected by the fidelity of the model, the accuracy ofthe input data, and the amount of experience the user has with the model. Using adrag/torque model in the well planning phase requires a high level of knowledgeregarding suitable friction coefficients for the particular area and drilling fluid.combination. Likewise, local variations in curvature, which are usual as a well is beingdrilled. should be considered during the planning phase, particularly if the well isapproaching the limits of the available equipment.Accurate modelling of field drag and torque measurements, and subsequent problemdiagnosis. requires both a high-fidelity model and a highly experienced user who is ableto interpret changes in apparent friction coefficient in terms of downhole phenomena.For conventional directional wells, where no buckling takes place, almost all currentlyavailable models should be suitable. For medium radius horizontal wells, a bucklingmodel should be included. Alternately, the user can manually verify that no bucklingtakes place by comparing the string tensionswith the critical buckling tables provided.USES FOR TORQUE AND DRAG SOFTWAREThe capability to predict frictional loads on drill pipe has a number of benefits. Wellboretrajectories can be planned to minimize drag and torque, knowledge of the drillstringloadings will allow use of improved drillstring design techniques. Rig selection for highangle directional and horizontal wells can be made rationally, with a high degree ofassurance that the selected rig is neither too big nor too small for the task. Duringdrilling, problems can be diagnosedand corrected before they become severe and causeloss of time or loss of the hole. After the well is drilled, post-appraisal is enhanced bymatching predictions with field observations. Many of these uses are discussed byBrett et.al., in their paper, listed in the references.DESIGN OF WELlBORE TRAJECTORYWhen designing extended reach directional wells. or conventional long radius horizontalwells, the limiting factor in the design generally is the ability to rotate the pipe atsurface when approaching total depth. In the two-build, long radius horizontal wellprofile, the interaction between build curvatures. inclination of the ramp angle betweenthe two build intervals. and the selected kick off points, is very complex and requirescareful study uslnn ~ trirru IA ::.nrl rlr::.n .,..,,,,-1,,,1 t...rI",.,; ......th ........ t:~ " : I - .

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    8.36 Directional Drilling ..Horizontal DrillingA parametric study should always be undertaken for wells of this type, since such astudy can easily determine the feasibility of the well, and will allow estimation of themaximumvariation permissible between the plan and the well as drilled. Knowing howfar it is possible to stray from the plan while still being able to drill the well withouttrouble makes good economic sense and adequately repays the planning time spent.Sometimes it is better to plug back and re-drill a well early in the process, rather thandrilling ahead with wellbore problems becoming steadily worse. Proper planning usingthe torque/drag model can provide sound workable guide-lines for supervision of thewell as it is drilled.DESIGN OFTHE DRILlSTRINGDesign of drillstrings for horizontal drilling is an evolving science. Without any ...convenient way to analyze loadings at each point in the string, much design work was .based on trial and error in the field, with frequent drillstring f~ilures and fishing jobsproviding the best-learned lessons. It is much better (and cheaper) to be able to basethe drillstring design on sound engineering principles, tempered by field experience. Theapplication of the torque/drag model allows this.Drillstrings for horizontal wells involve usa of a compressively loaded lower interval in.order to transmit weight to the bit through the horizontal section. This involves use ofheavy pipe higher in the well to produce the required axial compressive load. A mediumradius well has six distinct segments in the drillstring, as shown in Fig. 8.21.

    Fig. 8.21

    -SGJUf n

    SlC JIO T ,

    SUIOT ItsmuT UJI J.tQIO'T II

    SEGMENT1:BHA, comprised of bit, motor, NMDC's, MWD. This segment is used for control of thewell trajectory.

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    8.37 Directional Drilling' - Horizontal DrillingSEGMENT 2:Horizontal load transmission segment. This segment transmits the axial and torsionalloads during drilling and tripping. The pipe must be capable of transmitting these loadswithout failing, but also provide minimum drag and torque. Buckling can be a seriousconcern in this interval, and should beavoided in most circumstances.Some resistance to buckling is provided by the high inclination. This pipe usually is thelargest 00 conventional drill pipe that can be conveniently handled by the rig.SEGMENT 3:Lower portion of build, from 60-90 deg. The pipe here must also be able to transmitthe same axial and torsional loads as the pipe in Segment 2, but also must be able tohandle the bending stresses caused by the build curvature. Because of the highinclination angle, the weight of the pipe in this interval will move from the lower part ofthe build into the horizontal section. This segment is usually heavyweight drill pipe.SEGMENT 4:.Upper portion of the build, from a - 60 deg. This pipe must be able to withstand thebending stresses imposed by the curvature, and also resist buckling without the stabilitybenefit imparted by high inclination angles. The weight of pipe used here cansignificantly contribute to the available bit weight. This segment also usually isheavyweight drill pipe.SEGMENT 5:Weight stack interval, required to produce the required bit weights after the pipe inSegment 4 has beenconsidered. This is usually an interval if drill collars or heavyweightpipe in the vertical interval of the well, above the kick off point. If collars are used, it isnot usual practice to allow them to enter the angle build interval of the well during thecourse of a bit run. This interval can contribute significantly to parasitic pressurelosses. In a mediumradius well, very little torque or drag results fram this interval.SEGMENT 6:Vertical portion af the well. The pipe used here is run in tension, and must be capableof withstanding the tension and torsional loads of drilling and tripping, with an allowableoverpull margin. Except for hydraulics and convenience of rig operations, this pipe isusually not critical.It can be seen from the description above that design of the drillstring for horizontaldrilling usually involves a number of compromises and, in most cases, is an alternativeprocess. The string should be designed to provide the required bit weights, withminimum torque and drag, and should fit within the hydraulic's capability of the rig.The string should also be designed to be capable of reasonableweight transmission tothe bit in oriented (non-rotated)modewithout buckling taking place in the well.

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    8.38 Directional Drilling ,-Horizontal Drilling. ,Due consideration must be given to the length of the bit runs, since pipe will move fromone hole interval to the next during the course of a bit run. This is unlike conventionaltension drillstring design, where pipe is simply added at surface to advance the bit, andbit runs are limited only by bit life. In a horizontal well, the maximum length of the bitrun is pre-determined by the make-up of the driJIstringas it is run in the hole.

    The need to adjust lengths of some of the string segments (usually Segment 2) duringtripping, places some operational constraints on the drillstring design as a function ofthe particular rig design. While it might be best theoretically to use 5" pipe in Segment2 or 4!-1:" pipe in Segment 6, on most rigs this would not be practical due to excessivehandling time or limited set-back areas.The process of selecting an appropriate drillstring design beginswith deciding on a base__drill pipe size for the planned hole size. This is often decided in advance by the pipe ..which comes with the rig. A good starting point for design of the driJlstring for amedium radius well is to use heavyweight pipe in Segments 3 and 4, add enough drillcollars above in Segment 5, then quickly check the hydraulic pressure losses. Ifhydraulics are OK at the planned circulation rates. a torque and drag analysis isperformed next for the driHstring design in both oriented and rotated modes. It isgenerally necessary to operate in orientedmode at reduced bit weights.If all checks out satisfactorily, the string design is next checked at the beginning of thelongest planned bit run. If any intermediate casing is to be run between the beginningof the build and total depth, the entire process must be followed for both hole sizes.Finally, the string designs for each planned bit run should be evaluated at the beginningand end of each bit run.During the design process, if any phase proves unsatisfactory, one of the relevantoperating parameters or string segments is changed and the process is repeated.Sometimes, before a viable plan emerges, it is necessary to reconsider the hole size,base drill pipe size, or the drilling technique (i.e. motor versus conventional rotary; poeversus roller cone bit).RIG SELECTIONFrequently, a rig is selected for a project without any idea of what is really needed interms of mast rating, hoist capacity, rotary size and torque capacity, pump horsepowerand pressure rating. set-back area and control systems. Often, this results in an overlyconservative rig selection; much to big a rig is used, with poor economics resulting.Other times, too small a rig is chosen. and the project ends in disaster. Use of a dragand torque model, together with calculation of hydraulics requirements, can quickly andefficiently lead to a minimumspecification for the rig.This process is similar to that of drillstring design, and is often performed in conjunctionwith the string design. Once a hole size has been decided upon for the horizontalportion of the well (usually driven by completion or workover requirements), the wellprofile and casing programmefollow.A preliminary drillstring design is then made for the end of each hole size interval, andhydraulics are calculated for the desired range of circulation rates. Drag and torqueanalysis follows. Fromthese calculations comes the pump pressure and horsepower, _maximum hookload, the maximum surface torque and the amount of set-back space ..needed. This ouicklv nrovidas ;J ...n .~ifirMinn fl'lr thR rin

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    8.39 Directional Drilling ..Horizontal DrillingEXAMPLE OF ORILLSTRING DESIGN AND RIG SELECTION PROBLEM. ,It is desired to drill a horizontal well with 3,000ft of horizontal hole at a TVD of 6.900ft. Completion requirements dictate the lateral hole should be S Y 2 " with maximumbuildrate of 10 deg.l100 tt, with an intermediate casing string set at about 60 deg.inclination to case off an unstable shale overlying the producing formation. Wells in thearea are drilled with a fresh water PFPA mud system at 9.5 Ib/ga!. It is planned to drillthe curve and lateral intervals using roller cone bits. steerable motors and MWD fordirectional control.Previous experience in the area indicates that good hole cleaning is obtained withannular velocities of 120 - 150 ftlmin up to 60 deg. of inclination. and around 180ft/min over 60 deg. inclination. Usual steerable motor drilling practices in the area is torun 45.000 lbs on a 1214" insert bit. and 35,000 Ibs on an 8 %" insert bit.Provide a minimum rig specification. and perform preliminary drillstring design for the8 Y 2 " hole interval.SOLUTION'With a build rate of 10 deg'/1 00 ft. the KOP is approximately 6.325 ft. Two pipe sizeswill be considered, as both are common on rigs in the area, 5" and 4 Y z " , To obtain therequired annutar velocities:Flow Rate Range, GPM

    Pipe Size 12 Y 4 " Hole 8}7" Hole5"4}s' "

    600-800625-825300-400320-425

    To check hydraulics, the following preliminary string designs were chosen. toapproximately satisfy the bit weight requirements (from top. down):12 Y4" Hole to 6.925 ft MD

    5995' 5" drill pipe270' 8"x3" collars540' 5" HWDP120' 8" BHA5995' 4}S." drill pipe270' 8"x3" collars540' 4%" HWDP120' 8" BHA

    all" Hole to 10.225 ft MD5935' 5" drill pipe270' 6 3/4" collars1500' 5" HWDP2400' 5" drill pipe120' 6 3/4" BHA

    5935' 4%" drill pipe270' 6 3/4" collars1500' 4%" HWDP2400' 5" drill pipe120' 6 3/4" BHA

    With mud weight of 9.5 Ib/gal and typical mud properties of PV 10 and YP 15, thefollowing table shows the hydraulics requirements:

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    Directional Drilling - Horizontal Drilling. ,

    600700800

    118137157

    12%" Hole - 5" Drill pipeSystem PO7709601180

    BHA P O Total PO1000 17701000 19601000 2280

    12% .. Hole - 416" Drill pipe

    6208001065

    Engine HP7309401250

    System PO aHA PO Total PD Engine HP625 118 1140 1000 2140

    1000 2430780 920

    725 137 1430 1030 1210.825 156 1740 1000 2740

    816" Hole - 5" Drill pioe1320 1550

    System PD aHA PO Total PO Engine HP300 156 620 1000 1620 285 335350 181 730 1000 1730 355 415400 208 840 1000 1840 430 505

    ~ % " Hole - 4%" Prill pipeSystem PO aHA PO Total PO Engine HP

    325 153 870 1000 1870 355 420375 177 1020 1000 2020 440 520425 200 1170 1000 2170 540 635From the hydraulics stand-point, both 4 }) .. and 5" drillstrings are suitable, although the4%" string requires about 30% more pump horsepower. The next step is to do a dragand torque analysis, to evaluate the strings for pick-up and slack-off loads, maximumsurface torque and to check that no buckling takes place at the required operating loads.A friction coefficient of 0.35 was used as a first guess, and overpull margin of 70,000Ibs and a block weight of 30,000lbs was assumed. Bit torque was assumed to be1000 ft-Ibs. Hoist horsepower was calculated using a hoist velocity of 90 ftlmin, _lines strung, and a power efficiency of 0.841.

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    12Y." Hole at 6925 ft MDEiM Pi!;;k-yg ~1~&:k-Qff R01~!ing Drilling Mast Hoist~ Weight Weight Weight Torque Rating HP5" 179 165 172 6500 280 9104 Y . r : " 160 146 152 6300 260 845

    8~ ..Hole a110.225 ft MD~ Pi~k-!.!g Slack-Qff Rotating Drilling Mast J : ! . 9 l s . t~ Weight Weight Weight TQrgu~ Rating HP5" 174 77 131 15000 274 8904~" 152 65 113 13800 252 820

    Fromthe above information, it can be seen that the required rig should have a minimummast rating of 'around 280,000 lbs approximately 900 hp 'available for the draw-works,1200 hp and 3,000 Ibslin2 for the pumps, and capability to provide at least 15,000 ft-Ibs of torque at the rotary. At this point, detailed analysis should be conducted todetermine the loadings in the drillstring, to ensure that no buckling will take place, andthat point loadings on the tool joints lie within acceptable levels.FEASIBILITYSTUDIESThe use of the drag and torque model, together with other drilling engineeringsoftware,allows the feasibility of projects to be examined. It is often possible to be able topredict the limits for a particular well design before the well is actually drilled. bysimulating the drilling beforehand. In particular. the attainable length of horizontalwell bore can be predicted, as can the possibility of running the desired casing andcompletion strings. As the experience of the drilling engineer increases. so do thepossibilities for flexibility in well design.PROBLEM DIAGNOSIS AND REMEDIESMany downhole occurrences can be readily explained if drag and torque analysis isperformed on a real time basis during the drilling of the well. Comparison of thecoefficient of friction necessary to match the field data can shed light on whether theobserved torque and drag behaviour is a result of hole geometry or some other factor,such as problems with hydraulics or the mud system. Early detection of problemsindicated by increases in the coefficient of friction can help reduce the occurrence ofserious problems with hole cleaning, wellbore instability or differential sticking.

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    FILE:SECTION8.DOC 27 JuIV. 1992 'ehe Drilling and Production Training Centre8.42 Directional Drilling - Horizontal Drilling

    In addition to the benefits of monitoring the variation of the apparent friction coefficientas the well is drilled. real time drag and torque analysis can quantify the impact ofdeviations of the directional trajectory from the initial plan. Tendencies for key seating.casing wear and pipe fatigue can be evaluated by monitoring the magnitude of thecontact forces in cased and open hole. Sometimes, seemingly small variations from theplan early in the well can significantly affect the ability to achieve target objectives. If awell is not proceeding according to play, the ability to project ahead from thecurrent position, and quickly perform drag, torque and contact force analyses, allowsrational decisions whether to proceed or plug back.Once clue to diagnosis is a change in the gross friction coefficient when nothing elsehas apparently changed. For example, while drilling horizontal hole in the pay interval,the coefficient of friction may begin to increase from 0.30 to 0.33 over 60 ft or.so of -'.hole. but ROP is constant, and none of the operating parameters have been changed....An increase in friction coefficient always signals a change in something downhole; inthis case, hole cleaning is probably the culprit, with the increase in friction coefficientsignalling the growth of the downhole cuttings bed.Another clue is provided by divergent friction coefficients in the pick-up, slack-off androtating directions. For example, an increase in slack-off and rotating friction, with no.change in pick-up friction, could indicate the onset of buckling, or weight stacking on astabilizer. Additional clues can be provided by friction behaviour with the pump ratevaried. If friction increases as the pumps are slowed down. hole cleaning is almostcertainly the problem.Real time calculation and observation of the drag and torque parameters will generallyindicate the very early stages of a developing problem, allowing remedial action to betaken early. Wiper trips, circulation of hole cleaning pills, additional rotation and pipereciprocation can be initiated to eliminate the problembefore it becomessevere.POST-WELL APPRAISALAppropriate planning, and the use of torque and drag software during drilling will often eeliminate the problems that give rise to the need for detailed post-analysis. Torque anddrag data gathered during drilling can be compared with model results and used todetermine why the well did not achieve its predetermined objectives.Routine post-well appraisal of all wells drilled in a given area will almost certainly lead tooperational improvements in the form of better trajectories, changes to the mud system,different casing points or longer bit runs. Area knowledge obtained from post-wellappraisal allows the selection of good friction coefficients for preplanning purposes.Using offset well data can improve the accuracy of friction coefficients by providinglocal information such as formation lithology and permeability, mud type. filter cakethickness and hole washouts.POINT LOADINGIn the previous section, an element length of 30 to 100 ft was used to derive the forcesused in calculating torque and drag. Point loading is established in those conditions ofsevere dog legs or when the arc of the directional wellbore 'is changed so that astabilizer or part of the collar or tool joint "loads", or is forced against the side of thewellbore on a formation ledge. This causes an unanticipated increase in the torque anddrag.

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    8.43 Directional Drilling' ..Horizontal DrillingALUMINIUM ELEMENTSAluminium has been used in drillstrings for many years, principally due to its reducedweight which can extend the drilling depth capabilities of many smaller rigs. Morerecently, use of aluminiumdrill pipe was expandedto drilling long reach directional wellsto reduce torque and drag. as is the case in conventional, tension drHfstringdesigns.Aluminium drill pipe is available commercially in 3Yl", 4" and 5" sizes, with steel APIinternal flush joints. The pipe has an average specific gravity about half that of steel,and this weight advantage is increased as the mud density increases. Three principledifferences between aluminium pipe and steel are alunimiums lower weight, lowermodulus of elasticity, smaller internal diameter and larger outer diameter for the samanominal pipe size. (Figs8.22 - 8.25)In medium radius horizontal drilling, drill pipe typically is used in two positions in thestring: in compression in the horizontal interval, and in tension in the vertical part of thehole. The reduction in the stiffness value (EI) generally makes aluminium pipeunacceptable for use in compression as the allowable values of compressive load aremuch less than for comparable steel pipe. However, it may be possible to runaluminium pipe in the vertical tension interval if the need arises for reduced surface'tension due to low rating of the rig's mast.In long radius horizontal wells, considerabledrag and torque reduction may result fromthe judicious placement of aluminiumdrill pipe in the string. Potential for drag reductionshould be thoroughly investigated using torque/drag software.TRANSMISSION OF WEIGHTSCOMPRESSIQN ASSEMBLIES {MEDIUM RADIUS) VS TENSION ASSEMBLIES (LONGRADIUS)Medium radius horizontal wells use inverted type bottomhole assemblies in which thedrill pipe is run in the lateral. heavyweight or compressive strength pipe is run, in acurve, and the collars - normally run above the bit - are run in the vertical section. Thisprovides sufficient weight for the elements to go through the curve and supply the farcethat applies weight on the bit. However, there must not be too much weighttransferred to the bit, as this could cause the drill pipe elements to buckle helically in thelateral section. as discussed in previous sections. Use of drill pipe in the lateral sectionpowers frictional forces due to the reducedweight and surface area,of the element.REDUCING PREMATURE FAILUREIt is critical that the operator have very thorough inspection reports on all drillstringelements to be used on the horizontal well. Attempting to reduce costs by reducing thenumber of inspections is risky, at best. Only after sufficient case history data iscompiled can the number of hours between inspections be extended.

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    8.44 Directional Drilling - Horizontal Drilling,,:

    Inspection reports must be accurate, and must relate to preplanning in terms of torqueand drag calculations. If there is any concern over the calculated torque and drag limits,different types or larger size BHA elements should be considered. This may involvesimply using 5 1 0 drill pipe rather than 4Y2",or may require investigation of other types oftool joints that may add torsional strength or tensile capacity to withstand anticipatedtorque and drag. The torsional capacity of tool joints can be increased by decreasingthe 10 and there by "thickening" the tool joint wall; however, this may also cause areduction in hydraulic capacity.DRILLING FLUID PROPERTIES ANO SELECTIONIt is common knowledge among drilling personnel that borehole problems can beconsiderably more severe in a directional well than in a vertical well. The problems are _magnified as hole angle and horizontal displacement increases. ..Although most of these reactions are mechanical in nature, much can be done toalleviate them by proper selection andmaintenanceof the drilling fluids. Forexample, ifa water base mud is being