Fracking

1. Well interventions &
Production for
conventional &
unconventional reservoirs
Mba. Msc. B.D. Petroleum Engineer
Carlos Iver Saravia Vidal
Global specialist
September - 2020

2. Hello!
I am CARLOS SARAVIA
I am here because I love to give presentations.
Carlos_saravia_vidal@hotmail.com
2

3. Incremento de Producción de Hidrocarburos/Control
de Arena & Finos y Acidizing & Fracking
Mba. Msc. B.D. Petroleum Engineer
Carlos Iver Saravia Vidal
Especialista Global en Mejoramiento de Producción de Hidrocarburos
3
SEPTEMBER - 2020

4. Mba.B.D. Eng. CARLOS IVER SARAVIA VIDAL (Freelander Global Consultant)
 47 years old with 25 years O&G Global experience (HALL & WTF)
 ADNOC UAE Fracking & Completions 2020 Hiring process ongoing
 GLOBAL ONLINE Instructor 2020 (GET Middle East, SINPET, SEPERCAP Bolivia)
 Technical Leader NORTH AFRICA HALL 2019-2020
 HPS Senior Technical Advisor Pinpoint & Well interventions Halliburton UAE 2018-2019
 Mba Business Argentina 2009 & Msc University Education Bolivia 2017
 Brenntag O&G manager Bolivia 2017
 Completions foreman & Tool man WFT Bolivia 2016
 Global product champion for Halliburton sand Control & Conformance LATAM 2015
 Global Instruction SIGMA ATAC Engineering LATAM 2014
 Sales Manager Halliburton Venezuela 2011
 Account leader San Jorge Gulf Argentina & Punta Arenas Chile Halliburton 2006
 Field Engineer Halliburton Bolivia 1996

5. SAND CONTROL & FINES
MIGRATIONS
• A B C for Sand Control/Fines Migrations & Completions
• Best Practices, perforating, filtrations, fluid loss control.
• Sand Control/Fines Migrations Solutions
• Mechanical (Stand Alone, Gravel Pack, FracPack, High Rate Water Pack)
• Chemical (Resins & Z Potential criteria)
• Combination (Mechanical + Chemical Technologies)
• Sand Control Tools/Screens
• Water Control with Sand Control
• Scales, crude oils, gas & condensates reservoirs.

6. X Ray information
• Nothing of Calcite (matrix cement material) -Unconsolidated Sandstone. Be
careful with Clays for Acid Stimulation Design (Clay Control additives)
HC
Very clean sandstone /
Unconsolidated
LATAM case studies

7. Shear
stress
Effective
normal
stress
Stable Condition
Pore
Collapse
Failure
Shear Failure Region
Tensile Failure
Cohesive
Failure
Compression
Tension
Initial Conditions
Conditions under draw down
and production
Causes of Sand Production/Fines Migration? MOHR’s Failure Theory
Sand= Quartz
Fines/Cement Matrix= Feldspars K/Na, clays, Carbonates, etc
UCS (Unconfined
Compressive
Strength)
HC

8. 100
90
80
70
60
50
40
30
20
10
0
Very Coarse
Coarse Medium Fine
Very Fine Silt and Finer
U.S. Sieve No.
Sieve Opening, mm
325
200
140
100
80
60
50
40
30
20
10
.03
.04
.06
.08
0.1
0.2
0.4
0.6
0.8
1.0
2.0
Cumulative
Percentage
Sieve Analysis, Proppant &
Screen Design
• Various points are determined
 D50, D10, D40, D90
• These points can then be used to
determine the gravel sized needed to
retain a formation sand.
D90
D50
D40
D10

9. Análisis de la Formación
• Uniformity Coeficient (UC)
• d40/d90
9
UC < 3 Altamente Uniforme
3< UC < 5 Uniforme
5 < UC < 10 No-Uniforme
UC > 10 Altamente No-Uniforme
WELL COMPLETION TECHNOLOGIES
Saucier criteria
Type of reservoir

10. D50
SIEVE ANALYSIS Results
Dirty sandstone / ARCOSA
Unconsolidated. Mexico samples

11. Proppant and Screen selection
D50

12. Saucier + Tiffinh & King Criteria
Step #1, Uniformity Coeficient Cu(D40/D90) 9.37 & fines% (>325mesh) : 11.14%
Cu = D40/D90
Cu<3, very sorted
3>Cu<5, moderate sorted
Cu >5, poorly sorted
Step #2, Screen & Completion type:
Stand Alone Completion
(wrap)
Premium
screen/GP/HRWP
FracPack
D40/D90<3 & Fines <2%
3<D40/D90<5 & Fines <5%
D40/D90>5 & Fines >5%

13. Consecuencias de la producción de arenas y
migración de finos
WELL COMPLETION TECHNOLOGIES

14. Erosión de Equipo Causada por
Producción de Arena
Figure 2
Surface Choke Failure due to Erosion by Formation Sand
Falla de Choque de Superficie Debido a Erosión por Arena de Formación.
WELL COMPLETION TECHNOLOGIES

15. 15
Soluciones MECANICAS de Completamiento para Control de Arena & Migración
de Finos

16. Downhole Tools
Lower & Upper Completions

17. Tools Used to Execute
Gravel Placement
• Gravel Pack Packer
• Flow Subs / Closing Sleeves
• Fluid Loss Assembly
• Safety Joint
• Blank Pipe
• Screens
• Sump Packer
Multi-Position Service Tool
Versa-Trieve Packer
MFS Flow Sub
Production Screen
O-Ring Sub
Tell-Tale Screen
Perma-Series Sump Packer
Blank Pipe

18. Horizontal Gravel Packing
 Typically open hole
 Alpha Beta wave placement
technique
 Must maintain adequate filter
cake
 Must have ability to remove filter
cake after gravel placement

19. .
  2
2
2
189112
.
0
13
.
6
5
.
8
144
4
ft
Area 











sec
3
1
ft
Velocity 

sec
567337
.
0
sec
3
189112
.
0
3
2 ft
ft
ft
Velocity
Area
Rate 




min
06
.
6
42
1
1
4805
.
7
min
1
sec
60
sec
567337
.
0 3
3
bbl
gal
bbl
ft
gal
ft
Rate 




Area (ft^2) Velocity (ft/sec)
Rate
(ft^3/sec)
Rate
(bbl/min)
0.1891 3 0.5673 6.06
0.1891 2 0.3782 4.04
0.1891 1 0.1891 2.02
Calculations:
• Centralization
• Sand decantation
• Annular velocity

20. . 20
© 2011 HALLIBURTON. ALL RIGHTS RESERVED.
20
  2
2
2
3269
.
0
13
.
6
875
.
9
144
4
ft
Area 











sec
3
1
ft
Velocity 

sec
9807
.
0
sec
3
3269
.
0
3
2 ft
ft
ft
Velocity
Area
Rate 




min
48
.
10
42
1
1
4805
.
7
min
1
sec
60
sec
9807
.
0 3
3
bbl
gal
bbl
ft
gal
ft
Rate 




Area (ft^2) Velocity (ft/sec)
Rate
(ft^3/sec)
Rate
(bbl/min)
0.3269 3 0.9807 10.48
0.3269 2 0.6538 6.99
0.3269 1 0.3269 3.49

21. PetroGuard Advanced Mesh Screens
A completely new concept
• Uniform pore structure
within each layer
• Pore size control is
very precise
• No tortuous paths
• Easily cleaned
• (back-flush or acid)
• The performance of this
type of structure has been proven
in polymer filtration

22. Designed for specific size distributions (PSD’s)
Diffusion Bonding means a longer life and enhanced
precision in controlling sand flow in high viscosity
fluids
Base Pipe
Drainage layers
Filter layers
Shroud
PetroGuard Advanced Mesh Screens

24. Penetration?
Entry hole, Hole diameter, spf perfs
density, phase?
Main
explosive
load Case
Liner
“Primer” (or “Booster”) load
Case
Alta Penetración Gravel Pack
(Big Hole)
WELL COMPLETION TECHNOLOGIES
• 50% BH + DP
• Entry hole to connect reservoir
• 8-12 spf
• 90-120 degree phase (Vertical)
• 180degree (Horizontal wells)

25. 25
SAND CONTROL TOOLS / HYDRAULICS CALCULATIONS
P1 = Pbomba
P2 = Pbomba + Phidrostática
P3 = Pyacimiento
P4 = Phidrostática anular
ΔP X-Over Tool = P2 – P4
ΔP asiento de bola = P2 – P3

26. Squeeze (Screen-out)
P1
P2
P3
P4
P1 = Pbombeo
P2 = Pbombeo + Phidrostática – Pfricción tubing
P3 = Pyacimiento
P4 = Phidrostática anular + Paplicada anular

27. ACIDIZING
WATER SHUT OFF

28.  SPE paper CARLOS SARAVIA + SNOC ( UAE) on going

29. STIMULATION
PINPOINT
STIMULATION

30. Types of Acid Stimulations for Carbonates
 Perforations Wash Out ( cleanout)
 Minimum Reservoir penetration (1-10 Gal/Ft)
 No Formation Damage removal
 Near Well Bore Acidizing
 Medium Reservoir penetration ( 20 Gal/Ft)
 Limited Formation Damage Removal
 Foam Matrix Stimulation
 Deep Reservoir penetration (25 -75 gal/ft)
 Effective Formation Damage Removal, close to frac pressure

31. X Ray information
• Nothing of Calcite (matrix cement material) -Unconsolidated Sandstone. Be
careful with Clays for Acid Stimulation Design (Clay Control additives)

32. Mineralogy for a Carbonate reservoir
CARBONATES commonly are:
• Calcites (Calcium Carbonates)
• Dolomites (Magnesium Carbonates)
• Very low % of other minerals such as Sandstones
• Commonly High strengths % of Organic Acids HCl up to 28%
• High BHST>300F combined with organic acid
32

33. Near Wellbore Acidizing
 Foamed Acid
 Energizing and diversion technique due low reservoir pressure & permeability (improve fluids
placement and post-stimulation flow-back fluids)
 Selective Acid placement through CT. Use of High CO2 and H2S scavenger additive
 Micro Emulsion Surfactant, flow back enhancer
 Premium technology for Acid Stimulation in gas reservoirs (improve flow back fluids)
 Solvent pre-flush before main Acid Treatment
 Clean the rock reservoir from oil-wet in order to enhance Acid Penetration and Solubility
Additives for each type of rock reservoir

34. GAS & CONDENSATE CARBONATE HT ACID- Halliburton
System
 Designed for High BHST >290 F
 Recommended where traditional HCL systems spend quickly (minimum penetration/conductivity)
 Delayed reaction systems: Combination of HCl and non-corrosive organic acids
 Premium micro-emulsion surfactant: Premium micro-emulsion surfactant for Gas reservoirs to enhance
penetration and flow back fluids recovery
 Acid dispersant for homogeneous additives mixing
 Penetrating Agent for low permeability reservoir – to enhance wormholes generation
 Gelling Agents to Improve etching effect increasing penetration/conductivity
 Acid Corrosion Inhibitor + Inhibitor Intensifier for BHST >250F
 Non-ionic surfactant to break emulsions
 Soda Ash to neutralize Flow Back Contaminated/Spent Acids

35. CARBONATE 20/20
Laboratory Process in UAE
Lab Procedure
UAE case history (Mature field 350 psi BHSP!!!! High BHST GradTem
1.6 F/100ft) KAHAIF 03 WELL:
1. Acid Solubility Test @ BHST 305F
2. Separate samples after acid with Filter Press
3. Dry in microwave and get % Solvent Preflush and Acid
Solubility

36. SAJAA 8

37. N2
N2
315psi BHSP
Flow Back Contingency:
If well do not flow and still Liquid Acid in
Bottom Hole
BHSP = 315 psi
Hydrostatic Pressure
= 0.052 x Liq Dens (lb/gal) x Depth (ft)
Length (Fluid Level)
= 315 psi / (0.052 x 8.8 lb/gal)
Length level fluid = 686 ft
N2
N2+Liq
60 ft Btt Tub – Top Perfs
686 ft Level Fluid

38. KAHAIF 03 Vertical Well 4,4 deg Value
History Production & Stimulation
4 MM scf/d AOF 3,3 MM scf/d
(2007) 6500psi Ck 56
5,6% CO2 / 500 ppm H2S
Acid 5350bbls 28% Gelled HCl +
1000bbls Xlinked Gel
Perforations
& HUD
Well Completed 1993
11954-13492ft (1993)
11900-12950ft (2007)
LAST HUD 12,862 ft
898ft Net Perfs
Avg Porosity 2.55 % (Average)
Avg Perm 1.08 mD (Average)
Bottomhole temperature 298 F
Pore Pressure
Surface Pressure
350 psi
267 psi
SHUAIBA 11952 ft
KHARAIB 12195 ft
LEKWAIR 12580 ft
LEKWAIR 13360 ft

39. Average Treatment
Penetration: 75 in = 6 ft
Depth Limited to HUD
12,123ft
TAG 12432 ft
Bottom 12500 ft

40. AFTER EXTENDED MATRIX STIM
32,7 MMscf/day
Outflow InflowK = 1.080 InflowK = 1.320
FLOW RATE (MMscfd)
6
5
4
3
2
1
0
400
300
200
100
0
Inflow/Outflow Plot
 Prediction of Production
 K sensitivity
 Before  After

41. FRACKING

42. UNCONVENTIONAL
Reservoirs FRACKING
Conventional / Unconventional / BIOGENIC

43. Conventional Vs Unconventional reservoirs
Definition

44. BAJA PRODUCTIVIDAD Y
ALTO RIESGO DE
ARENAMIENTO
PREMATURO. FRACTURAS
PARALELAS AL POZO
ALTA PRODUCTIVIDAD Y
BAJO RIESGO DE
ARENAMIENTO
PREMATURO. FRACTURAS
PERPENDICULAR AL POZO

45. • XRD Analysis:
Carbonates reservoirs with fines migrations issues

46. • Porosity & Permeability:
• Rock Mechanics Testing:

47. • Rotating Discs:
• Acid Etching:

48. • Acid Etching:

49. 10 m
100 nK Shale
Unconventional Shale
300 years

50. Eagle Ford Woodford New Albany Barnett Johnson Bakken Barnett Wise
In Unconventionals – No Two Reservoirs Are
Equal
Bakken: 5% porosity, 0.02 mD
Eagle Ford: 8% porosity, 0.5 mD

51. Electron Microscopy Reveals
Kerogen Porosity
Low Maturity Samples
Vro ~0.5%
High Maturity Samples
Vro ~1.6%
Unconventional rocks (Images from Loucks, et al., 2009)
Conventional rock

52. FIB SEM Kerogen Porosity Measurement
(Focused Ion Beam Scan Electron Microscope)
Blue = Kerogen Porosity
Red = Kerogen (mix of organic materials in
the rock)
White = Pyrite

53. NORTH AFRICA- Unconventional- Petrophysics Evaluation Results for the Frac Job
 FRAC#1: PHIE=0.05, SW=0.47
 FRAC#2: PHIE=0.037, SW=0.70
 FRAC#3: PHIE=0.017, SW=1
 FRAC#4: PHIE=0.014, SW=1
The Best zone to Frac
Poor zone to Frac
Water wet/ non-reservoir
Washout
Best zone to Frac
Cut-off: PHIE: None, VCL<0.5

54. NF Natural Fracture evaluations and gas gradient shows potential zones to Frac
NF Dip Azimuth NF Dip
NO NF Natural Fissures

55. Summary for NORTH AFRICA Frac proposals
 Perf 2255 - 2260 m
 Top frac 2242 m
 Bottom frac 2276 m
 QH
 Perf 2028 - 2031 m
 Frac top 2003 m
 Frac Bottom 2054 m
 L-GEG
 Perf 1960-1963m
 Frac top 1930 m
 Frac Bottom 1986 m
 U-GEG
 Optional
 Optional
 Top frac 2242 m
 Bottom frac 2276 m
 Frac top 2003 m
 Frac Bottom 2054 m
 Frac top 1930 m
 Frac Bottom 1986 m

56. FRACKING TECHNOLOGIES
For all types of reservoirs

57. CARLOS SARAVIA GLOBAL SPE PAPERS
Available to download WWW.SINPET-
TRAINING.COM
• BOLIVIA
• USA
• PERU
• COLOMBIA
• ARGENTINA
• MEXICO
• UAE

58. Propped Fracture
production
casing
hydrocarbon
flow
jetted
perfs
Closest Current Solution: HydraJet Perforating or Radial Slotting
Flow Restriction is Reduced

59. What is Fracking?
What’s your imagination about an ideal frac?

60. X-linked Gel + Proppant
• A new, virtually residue-free fluid system

61. Mitigate Asphaltene, Paraffin, Scale, and Hydrate
Deposits for Shale oil production
• Accumulation of asphaltene, paraffin, scale,
and hydrate deposits can occlude pipelines and
tubulars, thus reducing or terminating flow,
and, in turn, creating production loss.
• Flow assurance challenges are managed
through system understanding, prediction
models, and product performance testing
conducted by our specialists in laboratories
simulating field conditions.
LABORATORY TESTING APPARATUS
Cold finger deposition testing Most efficient paraffin product and dosage evaluation using field crude
Hydrate rocking cells Methodology to reproduce field pressure temperature and gas conditions to select most
effective hydrate inhibitor
Tube blocking Methodology that uses candidate field brine to the point of scale precipitation that is used to
identify the most effective chemical, dosage and type for inhibition
Predictive water compatibility modeling Using water analysis from subject field, computer-based models predict type and quantity of
scale deposition

62. We’re IN ZONE!!!

63. The Reality:
Variation in Rock Properties
is non-negligible
Stage X
Engineered Completions allows
 Placement of stages in like rock.
 Placement of perforation clusters to
minimize stress contrast.
 Optimizes near wellbore reservoir AND
mechanical properties.

64. Engineered Completions Seek to:
 Improve perforation efficiency
 Reduce stimulation costs
 Optimize cost/boe

65. MULTISTAGES FRACKING = Sand Jet perforation +
Coiled Tubing Fracking
• Require Hydra-Jet perforation
• Diversion with Sand plug
• Require Insert trees saver or
sacrificial Christmas tree.
• Case hole

66. MULTISTAGE FRAC TYPE
• Require Hydra-Jet Sand
perforation
• Diversion with Dynamic effect
• Require Insert tree saver or
sacrificial Christmas tree.
• Open hole

67. Multi stage frac, completions slide side door
• Permanent completion
• Swelling packer may take 2-3
weeks.
• Open the sleeve either balls or
with well intervention with CT.
• Wellbore should be well
cleaned.

68. PILLAR TYPE FRACKING

69. PILLAR TYPE Frac Service
Advanced Pillar Frac – Infinite acting conductivity in void
spaces between proppant pillars

70. Infinite Conductivity concepts
26% Porosity 48% Porosity
65+% Porosity 85+% Porosity

71. Frac Service
Stable Pillars
• Chemical System Advancements
• Stabilized pillars using “on the fly” resin
coating.
• Expedite
• SandWedge
• Proppant bonding agent, provides channel
stability at reservoir pressure and
temperature.
• Helps retain fracture channel conductivity
over well lifetime.

72. PILLAR TYPE Frac Service
• Chemical System Advancements
• Stabilized pillars using “on the fly” resin
coating.
• RESINS
• Z POTENTIAL
• Proppant bonding agent, provides
channel stability at reservoir pressure
and temperature.
• Helps retain fracture channel
conductivity over well lifetime.

73. PILLAR Fracturing Service – Design
Workflow
• Candidate Selection
• Optimize fracture geometry
• Stress environment
• Physical properties
• Well production
• Proppant selection
• Fracture simulation
• Pillar design
• Pillar distance
• Spacer volumes
• No. of proppant pulses
• Proppant volumes

74. PILLAR Fracturing Service -
Operational

75. NEW FRAC FLUIDS ERA Service – What is it?
• A high regained permeability
system that has provided a
better return on investment
compared to guar-based fluid
systems.
• It centers around a residue
free natural polymer

76. FRAC FLUIDS Service – Advantages
 Clean
• <<1% insoluble residue
• High regained conductivity
• High regain core conductivity
 Efficient
• Enhanced formation mobility modifier
• Excellent proppant transport and suspension
 Versatile
• Wide temperature range 100-275 °F
• Salt tolerant (2-7% NaCl or KCl)
• Instant and delayed crosslinking
• Can be foamed with N2 or CO2
 Available
• Dry powder or LGC
• Stable supply from renewable natural polymers
LipTest for X Linked Gel

77. NEWS FRAC FLUIDS Service Can Benefit
Your Well –
Clean: minimal residue
NEWS Fluid << 1 %
Guar 8 – 15 %
HPG 5 – 9 %
CMHPG 2 – 5 %

78. Radioactive proppants
Why to use?

79. NRT Proppant helps determine if fractures are growing
past packers NORTH AFRICA Case
Results
 Stages 1, 3, 5, 7 used NRT and stages 2, 4 and 6 using CARBOLITE
without NRT. This allowed to indicate if propped frac were
growing vertically out of the pay zone. Excessive growth down
past the packer did occur in stage 5, resulting in 8 ft of propped
fracture growth into the stage 4 area. Stage 3 had minor growth
downward past the packer into the stage 2 area. Stage7 was fully
contained, no growth past the packer.
Challenge
 Establish measured in post cases of Frac Height of rock
properties from gas and or oil reservoir
Solution
 Alternated between NRT and CARBOLITE to create
contrast between stages. If NRT was detected in the non-
NRT stages, it was determined that the NRT fractures had
grown past the packers

80. Micro proppants
Why to use?

81. RPM’s coated proppants

82. Why Should I use ? RPM’s fluids systems
 Limits risk and reduces permeability to water
 Requires no special placement techniques
 A simple liquid additive that can be included in the pad of your frac schedule
 Extends the economic producing life of the well by controlling the influx of water in the formation
 Results can reduce of water flow from the treated area of a water-producing zone (or layers), with little or no damage to
the flow of hydrocarbon

83. Why Should I use it?
 Not recommended to formation with high permeability as 2 Darcy's
 Carbonate formations with high fracture conductive as 2 Darcy’s
 Sandstones with high density of Naturally Fracture that present small fluid efficiency as 25%
Possible Fracture orientations in Conventional Perforated guns
Short area treated and less are
with chemical to water control
Filtrated area and water permeability change and high
hydrocarbon conductivity.
Untreated area
New preferred orientations of hydrocarbon due to water
perm reduced in entered frac

84. Petrophysics remarks
 In case of DFIT/Minifrac predict the confirmation of
frac height risk of contact the lower zone, it is
recommended to evaluate the chance to use CWFrac
(RPM’s)
 Note that DFIT/Minifrac will support to correlated
the permeability around 0.09 till 0.13 mD
 In case of small permeability as 0.09 mD good
chance to contact the lower zone
 3903m Top of Propped
Frac
 3936m Top of Propped
Frac

85. Reduction of scale generations

86. Salt production control

87. 87
Thanks!