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G11 > Technical > Flashcards

Technical Flashcards

1
Q

Design process

A
  1. Well data
  2. Model selection
  3. Fluid selection
  4. Proppant selection
  5. Fracture geometry
  6. Fracture parameter optimization
  7. Pumping schedule
  8. Placement optimization
  9. Finalize design
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2
Q

Fluid selection

A
  • must consider bottom hole static temperature and formation properties
  • some conditions to consider:
    • water sensitivity
    • low Pres
    • extra visc req
    • high pack conductivity
    • short length ~300 ft
    • low conductivity

Choose fluid which will give: large conductivity & lowest polymer damage

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3
Q

Optimize fluid selection according to

A
  1. Leak off coefficient
  2. Retained factor
  3. Flowback in design ?
  4. Good clean up
  5. BHST
  6. BHP
  7. Formation sensitivity
  8. Friction data
  9. Formation perm.
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4
Q

Prop selection

A
  1. Closure pressure
  2. Mesh size
  3. Mean diameter
  4. Preferences
  5. Cost
  6. Availability
  7. Compatibility
  8. Pack porosity
  9. Perm
    * *optimizing Fcd is a must**
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5
Q

Prop production control products

A
  1. PropNET
  2. PropGUAR
  3. RC sand
  4. CRC curable resin coated
  5. Forced closure technique
  6. Unconv shapes proppants
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6
Q

Constants & variables for NPV

Optimize design vs cost

A

Constants:

  1. 1/2 length
  2. Geometry model

Variables:

  1. Formation permeability
  2. Maximum prop conc
  3. Fluid type
  4. Prop type
  5. Frac height
  6. Leakoff coefficient
  7. Max pump rate
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7
Q

Variables for FGS

A
  1. Fluid pumped
  2. Height growth
  3. Leakoff
  4. Modulus
  5. Pump rate
  6. Spurt loss
  7. Formation toughness
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8
Q

% PAD

A

=(1-n)/(1+n)

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9
Q

N= fluid efficiency

A

=formation vol/total fluid pumped

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10
Q

Finalize design

A
  1. Customer desires
  2. Ops restrictions
  3. Cost
  4. Material availability
  5. Res restrictions
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11
Q

Design parameters

A
  1. Wellbore configuration
  2. Formation properties
    3 fluid properties
  3. Proppants
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12
Q

Wellbore config

A
  1. Tubular config
  2. Perforations
  3. Hole survey
  4. Cmt bond log
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13
Q

Tubular config

A

Is the job pumped through cst or tubing.
Tubular size, wt, grade
Packer depth

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14
Q

Perforations

A

Info generally available with well file.

The more information known about how well was perforated. sPAN can be used to determine geometry configuration of perfs.

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15
Q

Hole survey

A

Only used for proper frictional and hydrostatic calculations in fraccade

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16
Q

CBL cmt bond log

A

Can be used to verify zonal isolation.

Weak bond could allow unrestrained height growth behind csg

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17
Q

Formation properties

A
  • perm
  • porosity
  • formation stress
  • FG (psi/ft)
  • Pres
  • BHST
  • skin
  • Sw
  • So
  • Sg
  • GOR
  • lithology
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18
Q

How to obtain Perm

A
  1. Empirically derived from porosity and Siw( both obtained from logs)
  2. Well testing (P build ups/drawdowns) can you give permeability estimates Through Type curve matching
    - short flow test/ drill stem test (involve flowing well)
    - RFT/MDT (logging tools) pack-off in the csg & flow formation fluid into test chamber.
  3. procade/perform: obtain well test match form pressure build-up/drawdown.
  4. Core testing: extremely dep on sampling and testing method
19
Q

How to obtain Porosity

A
  1. Logs: sonic/Density/Neutron
      • all can be used provided formation lithology is known**
  2. Core testing (dep on sampling method)
  3. Resistivity logs
20
Q

How to obtain Formation stress:

A
  1. Dynamic measurements can be obtained from Shear velocities on sonic log. This data in conjunction w/ bulk density can be used to calculate in situ stress
  2. Datafrac gives closure stress through the analysis of pressure data.
  3. Static measurements can be obtained from core in lab
  4. Mini-frac: small isolated breakdowns done over large section of well can provide stress profile for entire well. Can be used to correlate info on nearby wells.
  5. Small acid breakdown. May only provide info on pay section
  6. Drilling report w/mud info can give bounds for both closure stress and Ppore
  7. Quick estimate can be calculated using Pc equation.
21
Q

How to obtain FG

A

= closure stress/tvd

  • can be estimated w/ in-situ correlation in fraccade
  • factor used to set formation frac P as function of well depth.*
22
Q

How to obtain Pres

A

Here

23
Q

How to obtain formation stress

A
  1. Dynamic measurements can be obtained from Shear velocities on sonic log. This data in conjunction w/ bulk density can be used to calculate in situ stress
  2. Datafrac gives closure stress through the analysis of pressure data.
  3. Static measurements can be obtained from core in lab
  4. Mini-frac
24
Q

Variables for FGS

A 
Fluid pumped
Height growth
Leakoff
Modulus
Pump rate
Spurt loss
Formation toughness

if good data available for parameters: do not sensitize on them

25
Q

To obtain P res

A
  1. Horner plot of a P fall-off will give estimate of Pore P
  2. SRT(step rate test) can also give an approximation
  3. A RFT/MDT tool can be used to obtain physical measurement of actual pressure
  4. Mud reports from drilling phase can give indication of pore P w/kicks or losses
  5. DST(drill stem test) can be used
26
Q

To obtain BHST

A
  • most logging runs will measure T.

- couples w/recent mud circulation history a close estimate can be made

27
Q

To obtain Skin

A

Well testing including DST

28
Q

To obtain Sw

A
  • generally pore vol not filled w/water assumed to be HC*
  • can be obtained from rock resistivity Ro along w/ porosity and connate water resistivity are.
  • restistivities are obtained from:
    1. Water catalogs
    2. Produced water samples
    3. Water saturation equation
    4. Induction logs give resistivities at varying depths from wellbore
29
Q

To obtain So

A

Same logs used for det Sw used in conjunction to set So also

30
Q

To obtain Sg

A

Density logs can detect gas and quantify HC density

31
Q

How to obtain GOR

A

Area production data is the most reliable source for GOR

32
Q

To obtain lighogy

A
  1. GR & SP: used to indicate boundaries, correlate zones & give indication of lithiligy
    - GR: define shale beds when SP is distorted/featureless.
  2. Neutron & Density: used in combination to identify lithology utilizing crossplots. X ray diffraction on core is a physical measurement.
  3. Induction (resistivity) logs used to indicate lithology diff & correct for pseudogeometrical factors.
  4. Mud reports from drilling phase can be a good lithology data source
  5. Company geologist should have good idea of what area zones will be
  6. Photoelectric logs (PE) used in combo with others.
33
Q

Fluid properties

A
  1. Rheology
  2. Wall building leakoff coeff
  3. Total leakoff coeff
  4. Spurt
  5. TSO (tip screen out)
  6. Fluid friction
  7. N2/CO2 quality
  8. Retained factor
  9. additives
34
Q

Rehology

A

(n’,k’)
For CADE software is important to consider rheology as a function of time and temp.
*actual n’ &n’ #s can be obtained from published info/ lab testing of individual fluid.

35
Q

Cw

A

Wall building leakoff coeff
- is selected for wall building fluids/ fluids with FLA which makes them wall building fluids
- is a function for polymer and FLA concentration as well as formation perm.
1/(Ct)=[1/Cw]+[1/Cv]+[1/Cc]

If non wall building fluids Cw should be set to large number NOT zero

36
Q

Spurt

A

For wall building fluids, spirt is the leakoff that occurs before the deposition of footer cake.
- occurs at faster rate that after filter cake is in place

37
Q

TSO

A
  • Tip screenout design
  • to have complete packing of prop from tip of fracture back to wellbore & around gravel pack screen if present
  • as screenout progresses width inc proportionally with net P.
  • in high perm formation this is requ for adequate Fdc
  • other adv:
    • to prevent flow in fracture after shutdown. If large pad vol remains in front of sand laden fluid, fracture will continue to propagate and can significantly reduce prop conc near wellbore
38
Q

Fluid friction

A
  • easily obtained from published info

- most reliable results can be obtained from short field tests (isip in PAD)

39
Q

N2/CO2 Quality

A
  • % by vol of gas, excluding proppant

- decision needs to be made prior to job whether constant downhole/ surface rate is going to be used

40
Q

Retained factor

A
  • fraction of proppant pack perm that remains after fluid damage has occurred
  • only place to obtain this is from published breaker curves
  • number of great importance when calc fracture conductivity
  • if no breaker used in polymer based wall building fluid which leaves great deal of residual mass im fracture, value can easily approach 0.15 making default value of 1 inaccurate

Value ranges from .15-.75

41
Q

Proppants

A 
Inc alumina content: 
Sand (closure stress:6k , SG:2.65) 
RCS: (8k, 2.55)
Ceramic:
-Light weight proppant(8k, 2.7)
- intermediate strength (10k, 3.2)
-HSP high strength (15k, 3.55)
42
Q

Additives

A
  1. Control viscosity:
    - inc visc: XL
    - adj time to dev vice: delayer
    - red Cisco: breaker
    - control pH to maintain visc: pH buffer
    - prevent premature loss of visc: biocide/bactericide
    - maintain visc at elevated temp: HT stabilizer
  2. Formation compatibility
    - prevent permeability loss: clay stabilizer
    - leave formation water wet: surfactant
    - prevent fluid incompatibility: non- emulsifier
  3. Surface req:
    - hhp req: FR
    - fluid req: FLA
43
Q

Design for proper evaluation

A
  • breakdown/ballout
  • dataFRAC
    1. Step rate test
    2. Shut in decline test
    3. Flow back test
    4. Calibration test
    5. Step down test
44
Q

Breakdown/ballout

A
  • after perf & before frac, operators perform acid/water breakdown to ensure injection is established & perfs are open.
  • standard practices usually involve establishing inj rate before any acid or balls are pumped. Perfect opportunity to perform quick isip.
  • calc formation FG & rough estimate of closure
  • ideal to perform flowback test.

G11 (3 decks)

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