PET 514 - Drilling Engrg II_1

8/10/2019 PET 514 - Drilling Engrg II_1

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COURSE CODE: PET 514

COURSE TITLE: DRILLING ENGINEERING II (4 UNITS)

LECTURER: JAMES A. CRAIG, B.Sc. (I badan), M .Sc. (Norway)

COURSE OUTLINE:

1. Advanced Well Control

2. Drilling Hydraulics (Pressure Drop & Optimization)

3. Casing Design

4. Drilling Economics

5. Introduction to Underbalanced Drilling (UBD)

6. Introduction to Coiled Tubing (CT) Operations

7. Offshore Operations


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CHAPTER ONE

ADVANCED WELL CONTROL

Review of basic well control in PET 314

Rig kick removal equipment

Kick control methods

Drillers method

Engineers method (wait and weight)

Kick tolerance

1.1 Review of Basic Well Control in PET 314

1.1.1 Concept of Pressure

Figure 1: Concept of pressure.

1.1.2 Basic Well ControlConsider the well schematic below: A kick of length kL entered the well. The well was shut in. SIDPP

and SICPrepresent shut-in drillpipe pressure and shut-in casing pressure respectively.

0.052i i iP h

0.052n n

i i i

i i

P h

n

BOTTOM TOP i

i

P P P

1 2 3 4BOTTOMP P P P P

1

2

3

4

TOPP

BOTTOMP

1h

2h

3h

4h


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Figure 2: A well schematic showing kick.

,H annP

, ,H dpP

, ,H mP

, and ,H kP

are the hydrostatic pressure in the annulus, hydrostatic pressure inthe drillpipe, hydrostatic pressure of mud in the annulus, and hydrostatic pressure of kick in the

annulus.

,H dpSIDPP P BHP

,H annSICP P BHP

, , ,H ann H m H kP P P

Mud weight increase,0.052

SIDPPMWI

TVD

New mud weight, new old MWI

Kick density,0.052

k old

k

SICP SIDPP

L

SIDPP

SICP

FP

BHPTVD


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1.2 Rig Kick Removal Equipment

Figure 3: Rig kick removal equipment.

Number Equipment

1standpipe pressure gauge 2hole fill tank3casing pressure gauge 4blowout preventer rams (or bag)

5mud pump 6mud pump stroke sensor

7kill line 8choke in choke line9flow line mud flow sensor 10gas flare and flare line

11mud flow line 12gas mud separator

13mud pit level sensor 14active mud pit

15separator mud flow line 16choke line17accumulator 18bope lines19cement for last casing 20vent line21fracture in formation and loss of mud 22shoe of last casing23kill mud and inside drillpipe 24drilling mud and drillpipe annulus25drill collars 26kick fluid and drill collar annulus27drill bit 28kicking formation

29jets in the drill bit 30drillpipe


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1.3 Kick Control Methods

The objective of the various kick methods is to circulate out any invading fluid and circulate a

satisfactory weight of kill mud into the well without allowing further fluid into the hole. This should be

done with minimal damage to the well. After the kill mud has been fully circulated, the well can then

be opened and normal operation commences.

Different methods of circulating out kicks are listed below. Of all these, the drillers and engineersremoval methods are the most reliable.

1.3.1 Drillers

kill mud is pumped after the kick is removed from the hole

two circulations of the hole are required

annular and surface pressures will be higher while removing the kick than those of the

engineer's method

1.3.2 Engineers

the drilling mud is weighted to kill mud weight prior to pumping

kill mud is pumped while removing the kick

one circulation is required to kill the hole

1.3.3 Concurrent

drilling mud is weighted as it is pumped into the hole but not necessarily to the weight

of kill mud

the hole will contain a variable weight mud

annular and surface pressures will be higher than the engineer's and less than the driller's

1.3.4 Gas Migration

the gas bubble is allowed to rise in the annulus without circulating

the casing pressure is allowed to rise to a selected value without bleeding mud

mud is bled from the annulus while keeping the pressure at the selected value

after the kick rises to the surface, heavy mud is lubricated into the annulus to kill the

annulus and well

1.3.5 Dynamic

kill weight mud is pumped at a rate sufficient to raise the pressure at the bottom of thehole above or equal to that of the kicking formation. The increase in bottom hole

pressure occurs because mud is occupying more and more of the volume of the annulus,

and friction pressure losses in the annulus. (pump mud faster than gas entry rate)

a choke pressure may or may not be applied


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1.3.6 Low Choke Pressure

a pressure is held at the choke which will prevent the fracturing of a formation in the

hole

additional gas will enter the hole during the removal of the kick

similar to the dynamic method

1.3.7 Partition

the kick is pumped out of the hole in partitions

pressures will be the lowest of the methods

mud may or may not be weighted prior to the circulation of a partition

The drillers method, the engineers method, and the concurrent method are all similar in principle

because they are carried out under constant bottomhole pressure. They only differ in respect of when

kill mud is pumped down.

1.4 Drillers Method

Two complete circulations. Advantage: there is no waiting time; well control process starts

immediately after well is shut in and stabilized shut-in pressures are read.

Circulate kick out of hole using old mud

Circulate old mud out of hole using kill weight mud

Figure 4: Circulate kick out of hole using old mud.


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Figure 6: First circulation profile of circulating and annular pressure (Drillers method).


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Figure 7: Second circulation profile of circulating and annular pressure (Drillers method).


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1.5 Engineers Method (Wait and Weight)

One circulation is required. The influx is circulated out by pumping kill mud down the drillstring

displacing the influx up the annulus. The kill mud is pumped into the drillstring at a constant pump rate

and the pressure on the annulus is controlled on the choke so that the bottomhole pressure does not fall,

allowing a further influx to occur.

The advantages of this method are: Since heavy mud will usually enter the annulus before the influx reaches surface the annulus

pressure will be kept low. Thus there is less risk of fracturing the formation at the casing shoe.

The maximum annulus pressure will only be exerted on the wellhead for a short time.

It is easier to maintain a constant bottomhole pressure by adjusting the choke.

The engineers method is generally considered better than the drillers method since it is safer, simpler

and quicker. Its main disadvantage is the time taken to mix the heavier mud, which may allow a gas

bubble to migrate.

Figure 8: One circulation method.

1.5.1 One Circulation

Prepare the kill mud:0.052

SIDPPKMW MW

TVD

Start circulation with the kill mud: SCRICP P SIDPP

Pump up to kill rate while keeping the casing pressure at or near SICP.

As the kill mud proceeds down the drillpipe, the drillpipe pressure steadily drops from ICPto

FCP.


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After the kill mud has reached the bit, the drillpipe pressure is maintained at FCP, until the kill

mud returns to surface.

Figure 9: Circulation profile of circulating and annular pressure (Engineers method).


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1.6 Kick Tolerance

The kick tolerance, KTOL , determines the ability to control a kick at the current situation without

fracturing and causing lost circulation. To establish safe drilling condition, it should be ensured that

1KTOL ppg .

Maximum allowable shut-in casing pressure, psi: 0.052 frac csMASICP F MW D where fracF = formation strength, ppg

MW = mud weight in use, ppg

csD = casing shoe depth (vertical), ft

The kick tolerance, ppg: 0.052

csfrac

DMASICPKTOL F MW

TVD TVD

Maximum surface pressure, psi: max 0.052SP KTOL TVD

Maximum formation pressure, psi: max 0.052FP KTOL MW TVD

Maximum influx height, ft: ,max 0.052k k

MASICPL

MW

where k = kick density, ppg

Maximum influx volume, barrels is:

,max ,max,max

,max ,max

, if

, if

oh dc dc oh dp k dc k dc

k

oh dc k k dc

C L C L L L LV

C L L L


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CHAPTER TWO

DRILLING HYDRAULICS

Flow regimes

Rheological models

Frictional pressure loss

Nozzle sizing and optimisation

2.1 Flow Regimes

2.1.1 Laminar Flow

Fluid is said to move in layers or laminae. The direction of fluid particle movement is parallel to each

other and along the direction of flow at all times. No mixture or interchange of fluid particles from one

layer to another takes place. There is a linear relation between shear stress and shear rate at relativelylow rates of shear.

2.1.2 Turbulent Flow

The fluid particles move downstream in a tumbling chaotic motion so that vortices and eddies are

formed in the fluid at high rates of shear or high average flow velocities.

Figure 10: Flow patterns in pipes.


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The Reynolds number,ReN , defines the boundary between the laminar flow and the turbulent flow.

Laminar flow: Re 2,000N

Transition flow: Re2,000 4,000N

Turbulent flow: Re 4,000N

Flow through pipes: Re928

ivd

N

where

22.448

i

qv

d

Flow through annuli: Re928

evdN

where

2 22 12.448q

vd d

and 2 10.816ed d d

where = fluid density, ppg

v = mean fluid velocity, ft/sec

= fluid viscosity, cp

q = flow rate, gal/min

id = pipe ID, in.

2d = outer pipe ID or borehole diameter, in.

1d = inner pipe OD, in.

ed = annulus equivalent diameter, in.

2.2 Rheological Models

2.2.1 Newtonian Model

Newtonian fluids show a direct relationship between the shear stress and the shear rate , assuming

pressure and temperature are kept constant. Shear stress is directly proportional to shear rate, and

proportionality constant is called coefficient of viscosity, or simply viscosity, .

Examples of Newtonian model are water, gases and thin oils (high API gravity).


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Figure 11: Newtonian flow model.

2.2.2 Non-Newtonian Model

The shear stress to shear rate relationship is not linear and cannot be characterised by a single value,

such as the coefficient of viscosity. It is possible however, to define an apparent viscositywhich is the

shear stress to shear rate relationship measured at a given shear rate. Drilling fluids and cement slurries

are examples of a non-Newtonian model.

Figure 12: Non-Newtonian flow model.

Non-Newtonian fluids that are shear-time dependent are thixotropicif the apparent viscosity decreases

with time after the shear rate is increased to a new constant value and are rheopectic if the apparent

viscosity increaseswith time after the shear rate is increased to a new constant value.

Shear rate

Shearstress

Apparent viscosity

Shearstress

Shear rate

1

2

3

Increasing temperature


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Bingham plastic and power-law fluid models are used to describe non-Newtonian fluids.

Apparent viscosity:300 N

aN

where N = viscometer dial reading at N rpm, cp.

2.2.2.1 Bingham Plastic Fluid Model

y p

where y = yield point (YP), dynes/cm2

p = plastic viscosity (PV), cp

600 300p

300y p

600 = viscometer dial reading at 600 rpm, cp

300

= viscometer dial reading at 300 rpm, cp

Figure 13: Bingham plastic fluid model.

2.2.2.2 Power-Law Fluid Modeln

K

where K= consistency index of the fluid, dyne-s

n/cm

2. Units depend on the value of n .

n = flow index behaviour (power-law exponent)

600

300

3.32logn

300510

511nK

Plastic viscosity

Shear rate

Shearstress

Yield point


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Figure 14a: Power-law fluid model (cartesian axes).

Figure 14b: Power-law fluid model (log-log axes).

Kindicates the thickness (viscosity) of the fluid, the larger the value of K, the thicker (more viscous)the fluid is. n has a value range of 0 1.0n .

1.0n : Pseudoplastic fluid.

1.0n : Newtonian fluid

1.0n : Dilatant fluid

Lo Shear rate

Log

(Shearstress)

K

n

Shear rate

Shearstress


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Figure 15: Shear stress vs. shear rate relationship for pseudoplastic and dilatant fluids.

2.3 Frictional Pressure Loss

2.3.1 Pressure Drop in Pipes and Annuli

2.3.1.1 Laminar Flow

Newtonian Model

Flow Through Pipe:2

1500 i

LP

d

Flow Through Annulus:

2

2 11000

LPd d

Bingham Model

Flow Through Pipe:2

1500 225

p y

i i

L LP

d d

Flow Through Annulus:

2

2 12 1 2001000

p yL LP

d dd d

Power-Law Model

Flow Through Pipe:1

13

144000 0.0416

n

n

n

i

K L nPd

Shear rate

Shearstress

Pseudoplastic fluid

Dilatant fluid


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2.3.2 Pressure Drop in Bits

The pressure across a nozzle is given by: 4 21 28.074 10 nP v P

Pressure drop is therefore: 4 21 2 8.074 10b nP P P v

Figure 16: Discharge through a nozzle.

Nozzle velocity (ft/s) is:4

1238

8.074 10

b bn

P Pv

To compensate for the frictional loss in the nozzle:

1238 bn d

Pv C

dC = discharge coefficient, depending on the nozzle type and size (commonly 0.95dC )

Total nozzle area (in.2) is: 2

30.32

4T n

n

qA d

v

nd = jet nozzle diameter, 1/32 in.

Bit nozzle diameters are expressed in 32nds of an inch. For example, bit nozzles described as 12-13-

13 denotes that it contains one nozzle a diameter of 12/32 in. and two nozzles having a diameter of

13/32 in. each.

For a bit with more than one nozzle, that is, a bit with m numbers of nozzles, the total (resultant) jet

nozzle diameter is given as:22 2

1 2 ...32 32 32

mn

dd dd

2

32

mm

n

i

dd


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The total nozzle area (sometimes called total flow area, TFA) is given as:

2 2 2 21 2

...

1303.8 1303.8

m

m

i mT

dd d d

A

Then:

2

2 212032b d T

q

P C A

Hydraulic horsepower due to bit is:1714

bP qHHP

2.4 Nozzle Sizing and Optimisation

Proper selection of jet bit nozzle size will have the following effects:

Increase penetration rate

Proper hole cleaning efficiency

Reduce bit wear

Minimise hole problems Reduce operational costs

Hydraulic Design Parameters

Bit nozzle velocity

Bit hydraulic horsepower

Jet impact force

There is no general agreement on which of these parameters should be maximised. Current field

practise involves the selection of bit nozzles that will cause one of these parameters to be a maximum.

Total pump pressure is expended by frictional pressure losses in the surface equipment,se

P , frictional

pressure losses in the drillpipe, dpP , and drill collars, dcP , pressure losses caused by accelerating the

drilling fluid through the nozzle, bP , and frictional pressure losses in the drill collar annulus, dcaP ,

and drillpipe annulus,dpa

P .

p se dp dc b dca dpaP P P P P P P

Let the system pressure loss (total parasitic pressure loss) bes

P :

s se dp dc dca dpaP P P P P P

Then: p s bP P P

2.4.1 Bit Nozzle Velocity

From1238

bn d

Pv C

, then: n bv P

The annular velocity needs to be high enough to lift the cuttings out of the hole


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nv is maximised when bP is maximised

b

P is maximised when pP is maximised (within allowable pump rating) and frictional losses

are minimised

Frictional losses are minimum when the flow rate is a minimum

Annular velocity,

bbls/minft/min

Annular capacity bbls/ft

qAV

2.4.2 Bit Hydraulic Horsepowerm m

s sP q P kq

m = a constant (usually 1.75). In general, 0 2m . Also, m is the slope of the system pressure loss

curve, i.e.

,1

,2

1

2

log

log

s

s

P

Pm

q

q

k= proportionality constant that depends on the mud properties and wellbore geometry.

From above: p s bP P P then:m

b p s pP P P P kq

1714

bP qHHP

then: 1

1714 1714

m mp p

P kq q P q kqHHP

11714 1714

m

pPd HHP m kq

dq

To maximise:

0

d HHP

dq then: 1 1m

p sP m kq m P

1p

s

PP

m

In turbulent flow: 1.75m

100%

1.75 1

p

s

PP

36%sP of pumpP

64%bP of pumpP

In laminar flow, for Newtonian fluids: 1.00m

100%

1 1

p

s

PP

50%sP of pumpP

50%bP of pumpP


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In general, the hydraulic horsepower is not optimised at all times. It is usually convenient to select a

pump liner size that will be suitable for the entire well. The flow rate should neverbe allowed to drop

below the minimum required for proper cuttings removal.

2.4.3 Jet Impact Force

Jet impact force is given as: 0.01823 d bJIF C q P

Remember: mb p s pP P P P kq

Therefore: 0.5 0.5

2 20.01823 0.01823m md p d pJIF C q P kq C q P q kq

0.5

2 20.01823 md pJIF C q P kq

To maximise:

0d JIF

dq then:

1

0.52 2

0.009115 2 20

m

d p

m

p

C qP m kq

q P kq

Given: 1

2 2 0m

pqP m kq

then: 2 2 0m

pP m kq 2 2 0p sP m P

2

2

p

s

PP

m

In turbulent flow: 1.75m 53%sP of pumpP

47%bP of pumpP

In laminar flow, for Newtonian fluids: 1.00m 67%sP of pumpP

33%bP of pumpP

Summary

Hydraulic HorsepowerGives a flowrate that is usually adequate for hole cleaning under conditions of

moderate to low ROP. Gives very high nozzle velocity and excellent bit hydraulic for both ROP and bit

life in hard rock drilling.

Impact Force Higher flowrate, higher annular velocity, generally better hole cleaning, reduced

cuttings concentrations both at the bit and in the annulus and, therefore, less tendency for bit and

stabilizer balling. A higher flowrate, however, also results in increased fuel consumption, more wear on

pump parts and, possibly, increased hole enlargement in some formations.

Although there is no clearly defined separation between the two, the general rule is to design for impactforce in softer rock and faster drilling and to design for hydraulic horsepower n conditions of slower

drilling, small hole diameter, and low ROP.


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CHAPTER THREE

CASING DESIGN

PET 514 - Drilling Engrg II_1

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