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DRILLING FINAL YEAR 2 > MODULE 16-horizontal drilling v1 > Flashcards

MODULE 16-horizontal drilling v1 Flashcards

1
Q

what percentage of wells drilled are horizontal?

A

80%

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2
Q

what’s a main reason for horizontal well failure?

A

poor reasoning and planning

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3
Q

what tool has increased in drilling horizontal wells since the 70’s?

A

MWD

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4
Q

List the improvements that have made horizontonal drilling feasible?

A
  1. Mud motors
  2. MWD tools
  3. LWD tools
  4. Geosteering system
  5. Downhole Data transmission systems
  6. top drive drilling rig systems
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5
Q

How has technology improved horizontonal well drilling?

A
  1. reducing rig time
  2. improving directional control
  3. reducing risk of stuck pipe
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6
Q

Horizontal well applications- list 6

A
  1. Thin pay zones
  2. Naturally fractured reservoirs
  3. Heavy oil
  4. Gas reservoirs with low perm(enhance draining), high perm (reduce turbulence)
  5. gas storage schemes to enhance productivity
  6. EOR schemes including “water floods, miscible floods and oil sandwiches”
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7
Q

Benefits attributable to horizontal wells?

A
  1. Productivity (increased direct contact, linear drainage, reduced pressure gradient at the well bore)
  2. Development (reduced number of wells/max drainage, penetration of natural fractions, specialized product shemes)
  3. Heterogeneous reservoirs (can affect flow patterns)
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8
Q

types of heterogeneous reservoirs?

A
  1. channel point bars (alternating permeable and non permeable sands)
  2. braided stream deposits (areas of high perm conglomerates or sands with areas of low perm ss)
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9
Q

What’s preferable for horizontal drilling, thin or thick pay zones and why?

A

think because when fracturing, it will only target a certain depth

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10
Q

when is the productivity of a horizontal well significantly reduced?

A

when the vertical perm is less than the horizontal perm

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11
Q

what are some typical ranges of lateral lengths in the WCSB? (most common)

A

800m, 1000m-1300m, 2500m

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12
Q

What are 5 steps to do prior to planning a horizontal well?

A
  1. HC thickness
  2. IOIP
  3. Production mechanism(res drive pressure)
  4. Fracture intensity and directions
  5. surrounding well history
  6. Geological characteristics
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13
Q

what is the most immediate concern in hz well planning?

A

directional control

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14
Q

what is the expected cost ratio if hz wells to vert wells?

A

2.5 times. This will reduce rapidly and by the 3 or 4th well, you can see costs less than twice.

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15
Q

what percentage of production needs to be achieved to make it economical?

A

50 %more than a vertical well

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16
Q

what are the 4 well profiles?

A

long
medium
short
ultra-short

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17
Q

What are 6 ways to determine a well profile choice?

A
  1. casing program
  2. target entry point
  3. ability to move to surface location
  4. min build up rate restrictions\
  5. KOP restriction
  6. Pay zone thickness
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18
Q

what are the preferable well profiles?

A

long or medium

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19
Q

Ultra short BUR

A

45-90/.3m

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20
Q

Short BUR

A

5-10/m

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21
Q

Medium BUR

A

8-30/30m

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22
Q

Long BUR

A

1-6/30m

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23
Q

what determined the build angle in a hz well?

A
  1. Torque
  2. Drag
  3. Ability to transfer weight on bit
  4. Hole size
  5. Hole cleaning ability
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24
Q

how far apart should multilateral KOP’s be?

A

20-30m

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25
Q

BUR equation

A

180/(pi*r) *30

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26
Q

RADIUS equation

A

(30*180/pi)/BUR

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27
Q

steps required for well profile design?

A

KOP
BUR
Tangent section
TVD uncertainty

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28
Q

what is the greatest single cause of casing wear?

A

drill string rotation

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29
Q

applications for a long radius profile?

A
  1. Intersecting a reservoir displaced from the surface location
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30
Q

Advantages of a long radius profile?

A
  1. uses conv drilling equip
  2. Gives the op ability to rotate BHA
  3. Develops less torque and dra
  4. drills longer HZ section
  5. allows for conventional cores/logging
  6. Can be cased and completed.
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31
Q

Disadvantages of a long radius profile?

A
  1. Greater wall contact, higher true and drag and increased risk of differential sticking
  2. require top drive use
  3. needs bigger mud pumps
32
Q

Medium radius well applications

A

intersects reservoir where long displacement from surface is not required

33
Q

Advantages medium well profile

A
  1. conventional drilling equipment
  2. reduced wall contact and decreases torque and drag
  3. decreases well costs
  4. Increases hydraulic efficiency
34
Q

Disadvantages medium well profile

A

Inability to rotate BHA during build
disallows some completion and logging techniques
Increases bit and motor stress
Restricts some bit type

35
Q

advantages of short profile

A
  1. more precise placement of the HZ section
  2. Less expensive and drilled from existing well
  3. Less risk because KOP is below the fluid contacts
36
Q

Disadvantages of short profile

A
  1. needs customized drilling equipment
  2. no MWD logging, no control over azimuth
  3. short hz section
  4. open hole completion only
  5. no logging or coring services
37
Q

Benefits of multilateral drilling?

A 
reduced well costs
improve economics
higher production
increased recoverable reserves
additional fracture development
heavy oil development
reduced environment impact
38
Q

TAML?

A

technical advancement of multi-laterals

39
Q

Muti-lateral well classification- Level 1?

A

Open/Unsupported Junction
Mother bore lateral or slotted liner hung off in either bore
most common
used in medium to short build

40
Q

Multi-lateral classification- Level 2?

A

Mother bore cased and cemented: Lateral open hole
pack off slotted liner inside the formation
mother bore cased to below lateral kick off point

41
Q

Multi-lateral classification- Level 3?

A

mother well bore is cased and cemented and the lateral drilled as per a level 2 multilateral- is also cased and the casing ties back to the mother well bore with some form of liner hanger.

42
Q

Multi-lateral classification- Level 4?

A

Mother-bore & Lateral Cased and Cemented

Both bore cemented at the junction

43
Q

Multi-Lateral classification- Level 5?

A

Pressure integrity at the junction

cement not acceptable, packer and tubing used

44
Q

Multi-lateral classification-Level 6?

A

Pressure integrity at the Junction

cement not acceptable, achieved with casing

45
Q

Multi-lateral classification- Level 6s?

A

Downhole splitter

Large main well bore with 2 smaller lateral bores of equal size

46
Q

what 2 multi-lateral classification are the preferred systems?

A

level 3 and level 6

47
Q

considerations for drilling multi lateral?

A
  1. connecting to discrete reservoirs
  2. to encounter maximum number of natural fractures
  3. restricting drainage to a particular horizon
  4. alleviate coning
  5. reducing problems caused by sands
48
Q

List the application of multi laterals?

A 
Multiple targets
Limited size targets
Drainage pattern improvement
Heavy Oil production
Completion by layer
Handle Reservoir Geology
Limit water or gas production
Injectivity
49
Q

how much NPT does stuck pipe account for?

A

50%

50
Q

What are the most common problems to occur downhole?

A

fluid related

formation related

51
Q

key activities associated with stuck pipe prevention

A

selecting BHA
Drilling
Tripping

52
Q

when to change your BHA in regards to stuck pipe

A

Optimize jar placement

Accurately gauge worn bits and stabilizers

53
Q

Efficient Hole cleaning is impacted by a combination of

A

mud type
flow rate
solids control

54
Q

Differential Sticking causes, required action to minimize it happening

A

High potential to occur
High Risks if happened
Recovery Possible

55
Q

Geo-pressured formation

A

Exploration wells
Predominately shale / clay formations
Recognition is essential
Difficult to tell if it is happening when there is high pressure and low volume of gas

56
Q

Unconsolidated zones

A 
Low potential when:
In drilling program 
fully prepared
adherence to procedures
Recovery is possible
57
Q

Key seat sticking

A

High potential
Requires alertness and skillful drillers
Ream out when detected

58
Q

Reactive formation

A

Shallow depths
alleviated by inhibition
recovery cumbersome and costs potential high

59
Q

Drill string vibration

A

not a mechanism but a catalyst

makes fragile but stable formations become unstable

60
Q

fractured / faulted formations

A

formation is brittle
aggravation by: losses and dril string vibration
early recognition allows recovery potential to be high

61
Q

mobile formation

A

usually salt, sometimes shales
tectonically stressed
recognition and preventive measures essential

62
Q

hole cleaning

A

in conduction with thole instability, is the main cause of stuck pipe around the world

63
Q

borehole geometry

A

difficult to recognize
deep wells, high risks
difficult to recover
often in combination with other mechanisms

64
Q

cement related

A

poor cementations
long ratholes
does NOT normally result in permanently stuck pipe

65
Q

under gauged hole / junk in hole

A 
unnecessary: 
negligence
mis-preparation
pushing luck
recovery can be difficult and costly
requires alertness and skillful drillers
66
Q

factors contributing to differential sticking

A

excessive hydrostatic pressure opposite a permeable zone
high filtration rate
high mud solid content
large drill collars in relation to hole size
length of a shut down time opposite a permeable formation

67
Q

early warning signs of differential sticking

A

increased torque and increased drag

68
Q

causes of differential sticking

A

drilling through depleted reservoirs
formation pressure increases with depth more than the mud hydrostatic pressure and the mud weight is increased too dramatically - exceeding formation pressure

69
Q

fluid related problems

A

differential sticking - caused by pressure differential from the well bore to a permeable formation. minimize risk by reducing mud density and monitoring filter cake. Pulling free is unlikely. Reducing mud density and friction is a solution.

70
Q

Formations problems

A

include salt sections, lost circulation and sloughing shales which can be handled with the use of good mud additives

71
Q

describe differential sticking

A

differential pressures of hydrostatic vs. formation is great and causes the pipe to embed into the filter cake and adds to the problems of release

72
Q

minimum annular velocity is determined by?

A

the cuttings slip velocity

73
Q

when velocity of the fluid(vf) = slip fluid

A

minimum annular velocity

74
Q

is Slip velocity independent of fluid velocity?

A

YES!!

75
Q

stoke’s law assumptions

A

assumes perfect sphere

no turbulence

76
Q

Major effects affecting hole cleaning

A

annular fluid velocity
inclination
drilling fluid density
drill string rotation

77
Q

minimum rate in most problematic inclination to continue carrying of the cuttings and reduce bed setting

A

150 fpm

DRILLING FINAL YEAR 2 (1 decks)

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