1) The document discusses numerical modeling approaches for hydraulic fracturing design within full field models. 2) It outlines the limitations of traditional analytical fracture modeling and highlights advantages of numerical modeling, such as accounting for geological heterogeneity, reservoir architecture, depletion and injection effects on fracture behavior over time. 3) The document presents a case study where various fracture scenarios for a well candidate are modeled using a new approach of unstructured local grid refinement within the existing full field model, allowing spherical flow modeling at fracture tips and integrated workflow to rank fracture candidates.

1. Turning Sense into Dollar$:
Advances in Hydraulic Fracture
Design within Full Field Models
Arif Khan
Reservoir Technologist
recently in Statoil
(Formerly worked as Sr. PetroTechnical Expert -Reservoir/Production in Schlumberger)
Working in Oil industry since 1999

2.  Motivation
 Case background information
 Stress Profile Preparation
 Analytical Analysis
 Numerical Model Preparation
 Old Approach
 New Approach
 Numerical Analysis
 Well Candidacy
 Conclusion
Agenda

3. According to Terry Palisch:

4. Motivation
Why to go for 3D numerical modeling with New approach
Analytical Model versus Numerical Model

5. Analytical Fracture Modeling
Fractures are modelled (PI calculation of well) using
equivalent wellbore radius with no geometrical
representation of the reservoir.
Hegre and Larsen 1994
Fracture is represented as modification to productivity
of the well without any representaion of the physical
matrix-fracture interaction
• No quantification of geological heterogeneity, reservoir
architecture on performance of fracture.
• No injection or depletion effects (frac~ closing/widening).
• Simple negative skin approach may suite for vertical single
frac in homogeneous reservoir but very conservative for
horizontal well in hetrogeneous medium where multilayer
communication is enhanced by fractures.

6. Numerical Fracture Modeling
Multiphase Flow
Depletion or phase segrgation or water BT is defined via Relative perm. Curves
(very important factor in gas condensate reservior for condensate bank bypassing.)
Water or Gas Coning
Fracture sustainability and long term profitability by predicting coning/cusping effects on production
profiles (this evaluation is absent from analytical techniques).
Non Darcy Flow
Generally, the lower the permeability is, the higher the Beta factor and, consequently the higher the
non-Darcy effects are. Despite fracture’s high conductivity, the pressure losses due to non-darcy effects
can be significant, and ignoring those could lead to over-estimating production. Simulators have
options to take Beta factor for each layer or to calculate it using porosity and grid permeability.
Reservoir Geometry and Well location
Hydraulic fracturing (HF) might initially seem profitable, but after one-year of
depletion it looses its efficiency. Well location relative to the reservoir boundaries,
Barriers, and other wells is very important. As shown, only one side of the fracture
contribute to production and if poorly analyzed then production forecast
post frac. will be erronoues.

7. Numerical Fracture Modeling
Vertical communication
Numerical modeling can achieve objective of connecting horizontal well
through many reservoir layers (volumes), detailed layer properties are
defined (Kv, Phi).
According to the rock strength and stresses, the fracture propogation
direction (vertically and horizontally) is determined and is an input to
simulator to give us an idea on loss of connectivity with time.
A fracture connects the wellbore to the
reservoir layers isolated by shale barriers
Flow Convergence/Divergence at Fracture Tips
Flow convergene and divergence at fracture tips is crucial to model as it
significantly improves or impairs fracture conductance. Modeling of this
is absent in analytical methods while it requires special consideration in
numerical modeling also.
Flow Convergence due Partial Penetration
This can result in a high skin factor especially when non-darcy flow is
present

8. Fig A. Shows prod. rate without, 2 and
3 fractures
Fig B. Shows sensitivity of the prod.
rate to the number of fractures.
Fig C. Shows Results comparison
between Analytical and Numerical
models
Nodal Plot Sensitivity Plot
Analytical sensitivity Fig. B deviates from numerical results (decreasing slope with number of fractures).
PSS solution achieved by analytical model (Fig. C) is greater than even the transient period of numerical
simulation.
Note that Numerical simulation allows a quantification of the magnitude and duration of this transient
period.
Numerical versus Analytical Model Results

9. Case in Hand
Analyse and Rank Candidates for Frac. Job
Prior to Vessel arrival on Short Notice
Basic Field Info and List of Candidates

10. Reservoir Synopsis:
 Initial reservoir pressure: 589 bar @ 4166 m TVDSS
 Oil density= 805.0 kg/m3
 Water density= 1065.9 kg/m3
Candidates for Frac job
 An oil field located in the southern part of the North Sea.
 Permeability varying from 0.025 to 4010.41 md with a mean of 43.5 md for PERMX, PERMY
 Permeability varying from 0 to 56.25 md with a mean of 0.785 md for PERMZ
Porosity Permeability

11. Preparation
Stress Profile Prediction,
Frac. Pumping Diagnostics,
Frac. Properties

12. Mechanical Earth Model (MEM)
1-D MEM - Hydraulic fracture design
• Stress and stiffness profile modeling
• Zonation
• Pumping schedule
• Initial output
Fracture initiation and intersection with
Wellbore; depend on Azimuth
3D MEM
(Prepare 3D MEM model
if many wells with mechnical data,
populate geostatistically biased to
seismic etc)

13. Stress Orientation
• In Current evaluation, no direct information to confirm
frac. propagation, orientation.
• World stress Map suggests compression regime WSW-
ENE from reported breakout, which was inline with
observed behaviours in nearby fields.
• Such orientation would result in collinear fracture
along direction of planned horizontal wells.

14. Well:A, Stress Profile
• Stress profile developed from
sonic data
• Compressional sonic
measured, shear sonic
synthesised from offset data
• Stress profile showed good
stress barrier to prevent
excess upward vertical
fracture propagation

15. Fracture Parameters - post pumping simulations via FracCADE
0 20 40 60 80
Fracture Half-Length - m
< 0.0 md.ft
0.0 - 273.3 md.ft
273.3 - 546.6 md.ft
546.6 - 819.9 md.ft
819.9 - 1093.2 md.ft
1093.2 - 1366.5 md.ft
1366.5 - 1639.7 md.ft
1639.7 - 1913.0 md.ft
1913.0 - 2186.3 md.ft
> 2186.3 md.ft
FracCADE*
k of Schlumberger
ACL Fracture Profile and Conductivity
Draft Design ver 1
05-10-2011
0 20 40 60 80
Fracture Half-Length - m
-1.0 -0.5 0 0.5 1.0
ACL Width at Wellbore - in
Fracture Initiation MD = 4774.69 m
8000 10000 12000
Stress - psi
3825
3840
3855
3870
3885
3900
3915
WellDepth(TVD)-m
• Effective Fracture Height = 40 m vertical,
• Fracture
• Top = 3,847 m TVDRKB,
• Bottom = 3,887 m TVDRKB
• Effective Fracture Half
Length = 40 m
• Fracture Conductivity =
900 mdft
0
< 0.0 md.ft
0.0 - 273.3 md.ft
273.3 - 546.6 md.ft
546.6 - 819.9 md.ft
819.9 - 1093.2 md.ft
1093.2 - 1366.5 md.ft
1366.5 - 1639.7 md.ft
1639.7 - 1913.0 md.ft
1913.0 - 2186.3 md.ft
> 2186.3 md.ft
Draft Design ver 1
05-10-2011
Fracture Specs. Input to Simulation Recapitulation

16. Initial Analysis
Perform Quick Analytical Analysis
(while running batch of 3D numerical simulation cases)

17. Equivalent Reservoir Radius
Rectangular surface shape converted to an equivalent surface radius
Surface
403937m2
Surface
πr2
Equivalent radius = 358m
A
A
Static Pressure 400 bar
Reservoir Temperature 158 C
Reservoir permeability: 2md
Reservoir thickness 68m
Reservoir Radius 358m
Fracture Half Length 40m
Fracture Height: 40m
Fracture permeability 900 md.ft
Compositional model used - PVT available
Mechanical skin and rate dependent skin adjusted
to match the initial rate ~25m3/d.
Watercut 50%
Segregation of the results by reservoir interval
– Production from full reservoir height
– Production from only the hydraulic fracturing interval
Input
Analytical Fracture Modeling
PIPESIM model

18. Reservoir Permeability
Frac Interval
Contribution
Reservoir Radius
Frac Interval
Contribution
450
m
300
m
110
m
50m
80
md
2
md
0.5
md
Analytical Fracture Analysis
Both reservoir permeability and radius show large variation on results thus numerical modeling will
eliminate this uncertainity.
Fracture through-put is very dependent on matrix permeability as with 80 md; much higher PI.
Smaller radius reservoir shows higher deliverability thus fracture’s overall area is dominant «as expected
for this approach» for small drainage radius around it compared to higher Rd = 450m.

19. Frac Interval Contribution
Fracture PermeabilityFracture Half Length
Frac Interval Contribution
10 m
20 m
40 m
50 m 300 md
600 md
900 md
1200
md
Analytical Fracture Analysis
Fracture Half Length shows more sensitivity compared to Frac. Permeability for the same reason as shown
in previous slide where reservior drainage radius was sensitive. Thus larger Frac. Half length will be
dominant in analytical aproach.
Both Parameters max out at 400 sm3/d at maximum input variables values, while Fracture permeability
shows less variation compared to Fracture half length.

20. Preparation
3D Fracture Modeling for Numerical Analysis
Overview of Old Approach

21. 3D Hydraulic fracture design and Simulation Workflow
(now its Old)
This workflow was started few years ago as innovative solution for modeling Fractures in 3D Full Field
models, to avoid LGR’s and model 1ft to 3 ft wide fractures in simulation model without any through-put
convergence issues.
OR follow
Petrel* workflow:
• Imported FFM grid &
properties from the client
History Matched Eclipse
Model
• Created horizons from FFM
• Imported HFTM grid with
correct map coordinates
• Recreated layer structure
• Sampled properties from FFM
onto HFTM grid
• Exported integrated grid
• Exported FFM well trajectory
from Petrel to Eclipse

22. 3D Hydraulic fracture design and Simulation Workflow
(now its Old)
Method offers «advantages» of modeling fractures in modified but existing simulation model at field level
and «drawback» in terms of partial remodeling like transformation of properties between grids, distorted
grid, grid realigment to fracture in contrast to field wide drainage flow-pattern dictated by channels or
faults or dominant direction of flow, loosing details, effect on other wells, combursome workflow, trial-
error approach, use of many tools and menus, loss of history matching per well (field wide), have to be
done separately for each candidate Well thus many grids and many iterations, leading to delays, erronoues
results.

23. Preparation
3D Fracture Modeling for Numerical Analysis
Overview of New Approach

24. • Fracture is located traverse to the well path as per FracCADE design
• Still Orientation is a bit uncertain, keeping in view regional stress profile assumption
Fracture Location and Design
OWC is below this
bottom horizon

25. TOP=3847m
TVDRKB
BTTM=3887m
TVDRKB
TVD
Phi
Log
GR
Log
TOP=3847m
TVDRKB
BTTM=3887m
TVDRKB
Fracture
Traverse to
Well Path
Fracture Location and Design
Fracture specs (center, Top, bottom, orientation) as below
OWC is below this
bottom horizon

26. MD
GR log
TVD
Frac
orthgonal
to well
path
Zones or
Sands
GR log
Fracture Location and Design
Fracture covers almost all zones vertically as shown with respect to MD and TVD

27. Hydraulic Fracture Modelling
Model Dimensions
 Unstructured Local Grid Refinement
for Fracture gridding is applied where
well A is located
 The min. size of the grid cell around
Frac is approx. 0.9 m or 3 ft.
 Frac conductivity upscaled /adjusted
to 3 ft
 Unstructured LGR for Fracture
Modelling generates polyhedral grid
cells. Special simulator INTERSECT® is
used to solve these type of cells.
Merits of UnStr LGR + INTERSECT:
 Spherical flow is robustly modelled at
fracture tips
 Upscaling is avoided
 Grid distortion is avoided
 No imports and horizon rebuiling required
 Integrated workflow within Petrel
 Time saving, error mitigation and accurate
frac. flow modelling at field level.
Unstructured LGR in Global Sim. Grid
INTERSECT® is Schlumberger’s Next Generation Simulator
Well : A

28. Generation of Local Grid for HF
Using Existing FFM
FFM
Petrel* workflow 1:
• Use Existing Simulation model
• Spot grid cells around Target
Well A
• Gather information from
FracCADE
• Judge frac. orientation per
30deg Global Stress direction
• Design location, top and
bottom and orientation of
fracture using HF module of
Petrel
• Draw (link) HF to well
• Trace cells intersecting well and
HF
FracCADE informationExisting Sim. model

29. Generation of Local Grid for HF
Using Existing FFM
FFM
Petrel* workflow 2:
• Define Unstructured Local Grid
Refinement traverse to Well A
path (i.e. Parallel to desgined
HF) using Petrel’s built-in
unstructured LGR option.
• Adjust grid for fracture tips i.e.
spherical flow profile
• Define cells parrallel to HF
increasing logrithmically
• Create fracture conductivity (for
3 ft) using property calculator.
• Export new completions per
polyhedral cells to INTERSECT®
sim. deck
• Create another unstr. LGR for
other scenarios

30. Generation of Local Grid for HF
Using Existing FFM
FFM
This highly optimistic (and unlikely) ”60m”
scenario was not simulated.
Fracture Half Length = 40m
Fracture Half Length = 20m Fracture Half Length = 10m
Fracture Half Length = 60m

31. Generation of Local Grid for HF
Using Existing FFM
FFM
• Fracture Location and Height are shown above
• 2 scenarios are simulated with 20m fracture height as
worst case for fracture conductivity of 300md as
shown at lower right.
Fracture Height=
20m
Fracture Height=
40m

32. Results Analysis
Numerical Analysis
Overview of Results for One Well

33. Assumption: Constant Flux Boundary: No Frac vs. Frac case
FPR: around 600 bars in all cases
Frac_600/300/150md_L40/20/10m_H40/20m
HF_No Frac_ BC
Note:
4 cases’s pressure
varies ± 8 bars
which requires
further aquifer
attenuation but it
has no major
effect on
production and
frac. collapse
*L=Frac half Length, H=Frac Height, ??md = Frac conductance

34. Assumption: Production Control under THP = 15 bars
FFM unstructured LGR – A

35. Liquid Production Rate for All Sensitivities
WLPR : A, FFM unstructured LGR
No Frac_ BC
Frac – All Sensitivities
@THP =15 bars
log

36. Sensitivity Cases Performed
HF – A
0
20
40
60
80
100
120
140
160
180
BC
L10_H40_300md
L10_H20_300md
L20_H40_150md
L20_H20_150md
L40_H40_150md
L40_H20_150md
L20_H40_300md
L20_H20_300md
L20_H40_600md
L20_H20_600md
L40_H40_300md
L40_H20_300md
L40_H20_600md
L40_H40_600md
LiquidProductionRate,sm3/d
Liquid Production Rate, Ranked

37. Table 1: Sensitivity Cases Performed
HF – A,
* Highlighted is special scenario i.e. Most pessimistic case
Sr. No. Cases Fracture
Half Length
(m)
Height of
Frac (m)
Liquid Production
Rate after 5 Years
Ranking
(sm3/d)
BC - - 26.7396
1 600 md 40 40 161.910 1
2 600 md 40 20 161.909 2
3 600 md 20 40 149.065 5
4 600 md 20 20 149.065 5
5 300 md 40 40 152.167 4
6 300 md 40 20 152.168 3
7 300 md 20 40 142.196 6
8 300 md 20 20 142.196 6
9* 300 md 10 40 75.606 10
10* 300 md 10 20 101.490 9
11 150 md 40 40 135.765 7
12 150 md 40 20 135.765 7
13 150 md 20 40 129.427 8
14 150 md 20 20 129.427 8

38. Effect of Conductivity
L40_H40_600md
WLPT – A (Frac_600mD_vs. Frac_300mD vs. Frac_150mD)
@ Frac_half_L40m, Frac_Height_40m
L40_H40_300md
L40_H40_150md
• At constant fracture
height of 40m, 600md
and 300md
conductivities has ’no’
dependence on frac half
length, they are
insensitive above half
length 20m i.e. at 40m
• 150md is sensitive to
40m half length i.e.
L40_H40_300md=
L20_H40_600md
BC
*L=Frac half Length, H=Frac Height, ??md = Frac conductance
Case MSm3
L40_H40_600md 0.3062
L40_H40_300md 0.2849
L40_H40_150md 0.2501

39. Effect of Conductivity (continued…)
• All three frac.
conductivities are sensitive
to 40m half length with
20m fracture height
*L=Frac half Length, H=Frac Height, ??md = Frac conductance
L40_H20_600md
L40_H20_300md
L40_H20_150md
BC
Case MSm3
L40_H20_600md 0.3062
L40_H20_300md 0.2849
L40_H20_150md 0.2501
@ Frac_half_L40m, Frac_Height_20m

40. Effect of Conductivity (continued…)
• All three frac.
conductivities are sensitive
to 20m half length with
20m fracture height
• While 20m half length is
not sensitive to 20m frac
height as results are
similar to 40m frac height
*L=Frac Half Length, H=Frac Height, ??md = Frac conductance
L20_H20_600md
L20_H40_300md
L20_H40_150md
BC
L20_H40_600md
L20_H20_300md
L20_H20_150md
Case MSm3
L20_H40_600md 0.2779
L20_H40_300md 0.2633
L20_H40_150md 0.2370
@ Frac_half_L20m, Frac_Height_20 & 40m

41. Effect of Fracture Half Length
Case MSm3
L40_H40_300md 0.2849
L20_H40_300md 0.2633
L10_H40_300md 0.1919
Case MSm3
L40_H40_600md 0.3062
L20_H40_600md 0.2779
• Frac. Half Length for same value of conductivity is less sensitive, least
significant change is seen in 600md where if there is 600md conductivity
available then it doesn’t matter if frac half length is 40m or 20m.
Case MSm3
L40_H40_150md 0.2501
L20_H40_150md 0.2370
@300md, Height=40m @600md, Height=40m @150md, Height=40m
L 40m
*L=Frac Half Length, H=Frac Height, ??md = Frac conductance
L 20m
L 10m
BC
L 40m L 20m L 40m
L 20m
BC BC

42. Effect of Fracture Height
@300md, Length=10m
Height = 40m and 20m (very sensitive)
L40_H40_300md
Case MSm3
L40_H40_300
md 0.2849
L40_H20_300
md 0.2849
L20_H40_300
md 0.2633
L20_H20_300
md 0.2633
L10_H40_300
md 0.1919
L10_H20_300
md 0.1395
L40_H20_300md
L20_H40_300md
L20_H20_300md
*L=Frac Length, H=Frac Height, ??md = Frac conductance
(no sensitivity)
(no sensitivity)
L10_H40_300md
L10_H20_300md
BC
• @ 600md with frac. length
20m, there is no frac. height
sensitivity seen, even L40 is
very similar. (not shown in this plot)
• @ 300md, no sensitivity seen
for frac height (40 to 20m)
both for 40m and 20m length
• @ 300md, significant sensitivity is seen for frac height (40 to 20m) for
frac. Half length of 10m

43. Table 1: Sensitivity Cases Performed
HF – A,
Most Optimistic case:
L40_H20_600md, 0.3062 MSm3
*L=Frac Length(m), H=Frac Height(m), ??md = Frac conductance
Most Pessimistic case:
L10_H20_300md, 0.1395 MSm3
BC, 0.0487 MSm3

44. Sensitivity Cases Performed
HF – A,
0,000
0,050
0,100
0,150
0,200
0,250
0,300
0,350
BC
L10_H20_300md
L10_H40_300md
L20_H40_150md
L20_H20_150md
L40_H40_150md
L40_H20_150md
L20_H40_300md
L20_H20_300md
L20_H40_600md
L20_H20_600md
L40_H40_300md
L40_H20_300md
L40_H40_600md
L40_H20_600md
TotalLiquidProduction,Msm3
Total Liquid Production Increment after 5 Years,
Ranked

45. Table 2: Sensitivity Cases Performed
HF– A,
* Highlighted is special scenario i.e. Most pessimistic case
Sr. No. Cases Fracture Half
Length (m)
Height of Frac (m) Total Liquid Production
Increment after 5 Years
Ranking
(Msm3)
BC - - 0.04870
1 600 md 40 40 0.28496 1
2 600 md 40 20 0.30633 2
3 600 md 20 40 0.27793 3
4 600 md 20 20 0.27793 3
5 300 md 40 40 0.28488 4
6 300 md 40 20 0.28489 4
7 300 md 20 40 0.26325 5
8 300 md 20 20 0.26325 5
9* 300 md 10 40 0.19187 8
10* 300 md 10 20 0.13951 9
11 150 md 40 40 0.25013 6
12 150 md 40 20 0.25013 6
13 150 md 20 40 0.23695 7
14 150 md 20 20 0.23695 7

46. Wells Ranked as «go/no go» Candidates prior
Frac. Vessel arrival
Here shown in separate colors, all possible frac scenarios simulated on an individual well to
qualify for ranking (volume wise for next 5 years), also shown is comparison with base case i.e.
no frac.
If one well has issues (WH fatigue, downhole problems etc) then next inline is known to switch
to.
Candidates for Frac job

47. Conclusion
 Perform in advance initial MEM for all available wells and establish 1D and 3D MEM’s, use those as input for
rapid numerical analysis
 Update MEM with new frac data.
 Perform brief analytical + analogue analysis before jumping in numerical modeling so to have better control
over numerical results.
 Polyhedral Grid cells show rapid numerical analysis with outmost accuracy.
 On downside; simulating and preparing polyhedral cells requires special features, both in pre-post
visualization and enhance simulator.
 Case study results showed Rate (PI) increase of 5 times.
 Analytical solution is over-estimating PI (Rates).
 Fracture conductivity showed an impact to overall liquid productivity in the fracture cases, contrary to
analytical analysis, although one to one comparison (analytic vs. numerical) is bias.
 Fracture Height variation showed significant impact on lower (10m) compared to higher (20m, 40m) values of
Fracture half length.
 Fracture Half Length showed a limited effect on the overall liquid productivity of the well except for worst case
of 20m frac. Height, compared to analytical analysis.
 Wells were rapidly ranked for immediate selection as candidate for intervention.

48. Thank you!
Arif Khan
arkha@statoil.com
Mob: (0047) 45 22 1367