drillstring & bha design

9. Drillstring & BHA Design

Habiburrohman abdullah 1

Drill String Design

• Drill Pipe• Pressure Control Equipment• Drill String Loads• Monitoring Equipment

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Bottom-Hole Assembly (BHA) Design

• Purpose• Components• Assemblies:

- Slick, Packed, Pendulum, Directional• Properties:

- Weight, Stiffness

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Introduction

• The drillstring design is the mechanical linkage connecting the drillbit at the bottom of the hole to the rotary drive system on the surface.

• The drillstring has several functions:

- transmit rotation to the drillbit.- exerts weight on bits (WOB)- guides & controls trajectory of the bit- allows fluid circulation

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Drillstring Components

• The components of drillsting:1. Drill Pipe2. Drill Collar3. Accessories including:- HWDP- Stabilizers- Reamer- Directional control equipment

Figure 1: Drillstring Components5

Drill Pipe Selection

• Only grade E, G and S are actually used in oilwell drilling. • API RP7G established guidelines for Drill Pipe as follows:

- New = no wear, never been used - Premium = uniform wear, 80% wall thickness of new pipe- Class 2 = 65% wall thickness of new pipe- Class 3 = 55% wall thickness of new pipe

Grade Minimum Yield Strength, psi

Letter Designation Alternate Designation

D D-55 55,000

E E-75 75,000

X X-95 95,000

G G-105 105,000

S S-135 135,000

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Table 1: DP grade and yield strength

Tool Joints

• Tool joints are screw-type connectors that join the individual joints of drillpipe.

• All API tool joints have minimum a yield strength of 120,000 psi.

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Washout in Drillstrings

• Tool joint failure is one of the main causes of fishing jobs in drilling industry. This failure is due entirely to the joint threads not holding or not being made properly.

8Figure 2: Make Up Torque

Washout in Drillstrings

• Washout can also develop due to cracks develop within drill pipe due to severe drilling vibrations.

• Washout are usually detected by a decrease in the standpipe pressure, between 100 – 300 psi over 5 – 15 minutes.

• The life of tool joints can be tripled if the joints if hardfaced with composites of steel and tungsteen carbide.

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Approximate Weight of DP and Tool Joint

• Nominal weight of DP is always less than the actual weight of DP and tool joint because of the extra weight added by tool joint and due to extra metal added at the pipe ends to increase the pipe thickness.

10Figure 3: Tool joint dimension

Approximate Weight of DP and Tool Joint

• Calculations of approximate weight of tool joint and DP:

a)

b)

Where : L = combined length of pin and box (in)D = outside diameter of pin (in)d = inside diameter of pin (in)DTE = diameter of box at elevator upset (in)

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4.29weightupsetweightendPlainDPofweightadjustedeApproximat

TETE DDxdxDDx

dDLxjotoolofweightadjustedeApproximat

233

22

501.0167.0

222.0int

Approximate Weight of DP and Tool Joint

c)

where,

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lengthadjustedjotooljotoolwtapproxxDPwtadjustedapprox

assemblyDPofweightadjustedeApproximat

int4.29int..4.29..

ftDDxLlengthadjustedjotool TE

12253.2int

Tool Joint Dimension

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Table 2: Tool joint dimension table

Approximate Weight of DP and Tool Joint

• Examplecalculate the approximate weight of tool joint and DP assembly for 5 in OD, 19.5 lb/ft Grade E DP having a 6.375 in OD, 3.5 in ID. With NC50 tool joint. Assume the pipe to be internally-externally upset (IEU) and the weight increased due to upsetting to be 8.6 lb.

• SolutionReferring to Table 2, NC50, 6.375 in OD, 3.5 in ID tool joint for 19.5 lb/ft nominal weight DP is available in grade X95

Thus L = 17 in ; DTE = 5.125 in

D = 6.375 in ; and d = 3.5 in

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Approximate Weight of DP and Tool Joint

a) Approximate adjusted weight of Tool Joint

b). Approximate adjusted weight of Drill Pipe

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TETE DDxdxDDxdDLx 23322 501.0167.0222.0

lb

xxxx27.120

125.5375.65.3501.0125.5375.6167.05.3375.617222.0 23322

4.29weightupsetweightendplain

4.296.85.489

1441276.45

422 xx

ftlb /22.18293.093.17

Approximate Weight of DP and Tool Joint

Adjusted length of tool joint:

c) Hence, approximate weight of tool joint and DP assembly :

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651.112

125.5375.6253.21712

253.2

xDDxL TE

ftlbx /2.214.29651.127.12022.18

Drill Collar (DC) Selection

• There are two types of DC : - Slick DC- Spiral DC

• In areas where differential sticking is a possibility spiral DC should be used in order to minimize contact area with formation.

17Figure 4:Type of Drill Collars

Drill Collar (DC) Selection

Table 2: Drill Collar & Hole Size

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Procedure for Selecting DC

1) Determine the Buoyancy Factor (BF) of the mud weight: MW = mud weight, ppg 65.5 = weight of a gallon of steel, ppg

2) Calculate the required collar length to achieve desired WOB:WOB = weight on bit, lbf (x1000)Wdc = DC weight in air, lb/ft

0.85 = safety factorBF = buoyancy factor, dimensionless

3) For directional well:I = well inclination

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5.651 MWBF

dcLength WxBFx

WOBDC85.0

IverticalLengthDCDCLength cos

Bending Strength Ratio (BSR)

• Bending strength ratio defined as the ratio of relative stiffness of the box to the pin for a given connection.

• Large OD drill collars provide greater stiffness and reduce hole deviation problem.

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Stiffness Ratio (SR)

• Stiffness ratio define as follows: SR = Section modulus of lower section tube/section modulus of upper section tube

• From field experience, a balance BHA should have:- SR = 5.5 for routine drilling- SR = 3.5 for severe drilling or significant failure rate experience

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222

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21

212

IDODODIDODODSR

Heavy Weight Drill Pipe (HWDP)

• HWDP has the same OD of a standard DP but with much reduce inside diameter (usually 3”)

22Figure 5:Type of HWDP

Stabilizer• Stabilizer tools are places

above the drill bit and along the BHA to control hole deviation, dogleg severity and prevent differential sticking.

• There are two types of stabilizer:– rotating stabilizer– non rotating stabilizer

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Figure 6:Type of Stabilizer

Standard BHA Configuration

• There are five types of BHA configuration:1. Pendulum assembly2. Packed bottom hole assembly3. Rotary build assembly4. Steerable assembly5. Mud motor and bent sub assembly

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Drillstring Design Criteria

• The criteria used in drillstring design are :- Collapse- Tension- Dogleg Severity Analysis

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Collapse Design

• The criteria to be used as worst case for the collapse design of DP is typically a DST. The maximum collapse pressure should be determined for an evacuated string, with mud hydrostatic pressure acting on the outside of the DP.

• A design factor is used in constructing the collapse design line. The design factor to be used for this full evacuation scenario is 1.0.

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Collapse Calculation

1. DST (Drill Stem Test)

• Where:- Pc = collapse pressure (psia)

- Y = depth to fluid inside DP (f)- L = total depth of well (ft)- 1 = fluid density outside DP (ppg)

- 1 = fluid density inside DP (ppg)

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251.19251.19

21 xYLxLPc

Collapse Calculation

2. Design Factor in Collapse

a DF of 1.125 is normally used

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)(tan

cPpressurecollapseDrillpipeofceresiscollapseDF

Tension Design

• The tension load is evaluated using the maximum load concept. Buoyancy is included in the design to represent realistic drilling condition.

• The tension design is established by consideration of the following :- tensile force- design factor- slip crushing design

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Tension Design (Tensile Force)

Weight Carried• The greatest tension (P) on drillstring occurs at top joint at

the maximum drilled depth.

Where : Ldp = length of DP per footWdp = weight of DP per unit lengthLdc = length of DC per footWdc = weight of DC per unit length BF = Buoyancy Factor

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BFxWxLWxLP dcdcdpdp

Tension Design (Tensile Force)

• The drillstring should not be designed to its maximum yield strength to prevent the DP from yielding and deforming. At yield, the DP will have: – Deformation made up of elastic and plastic (permanent)

deformation.– Permanent elongation.– Permanent bend & it may be difficult to keep it straight.

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Tension Design (Tensile Force)

• To prevent this, API recommends that the use of maximum allowable design load (Pa), given by :

Where : - Pa = max. allowable design load in tension, lb

- Pt = theoretical yield strength from API tables, lb

- 0.9 = a constant relating proportional limit to yield strength

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ta PxP 9.0

Tension Design (Tensile Force)

• From above (tensile force) equation, we obtain: MOP = Pa – P

DF = Pa / P

where : MOP = margin of overpull, lbsDF = design factor, dimensionless

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Dogleg Severity Analysis

• The most common DP failure is fatigue wear. Fatigue is tendency of material to fracture under repeated cyclic stress and chemical attack.

• A DP fatigue wear generally occurs because the outer wall of the pipe in a dogleg is stretched resulting in additional tension loads.

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Dogleg Severity Analysis

• The maximum possible dogleg severity for fatigue damage considerations can be calculated using the following formula:

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KLKLx

EDxDMax b

stanh000,432

END

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