Embed Size (px)
Citation preview
Anderson Thompson – who are we?• We provide direct support for oil and gas operators and
investors
• Characterize the reservoir, completion effectiveness and predict future performance
• Design and optimize completion and field development strategies• Provide resource assessment and auditing services on producing and
undeveloped acreage
• 22 studies completed, 200+ wells analyzed across all major Canadian and US basins
• Integrated team consisting of reservoir engineers, geoscientists and hydraulic fracture specialists
• Experts in Rate Transient Analysis
Anderson Thompson Integrated Workflow
Core and Openhole Logs
Hydraulic Fracture Modeling
Rate Transient Analysis (RTA)
Formation PropertiesPorosity, Permeability,Saturations, Net pay, Young’s modulus, Poisson’s ratio
Frac PropertiesFrac length,Frac height,Frac conductivity,Perf cluster effectiveness
Placed Effective
ProductionRelates completion, fracture, PVT and formation properties to well performance
Play by Play Review of Lessons Learned
• Assessing the impact of completion type on well performance (Permian)
• Optimizing stage spacing and treatment size (Permian and Montney)
• Attaining predictable and scalable results (Montney)
• Maximizing completion effectiveness for infills (Eagle Ford)
Production Rate
time
Operations- Open versus choked flow- Shut-ins- Flowing pressure profile- Artificial lift- Separator pressure/temp
Reservoir/Fluid- Reservoir pressure- Net pay- Porosity- Sw- Young’s modulus- Poisson’s ratio- Natural fractures- Stress profile- Permeability- Fluid compressibility- Pore compressibility- Fluid viscosity- Gas solubility- Gas gravity- Oil API gravity- Capillary pressure
Completion/Wellbore- Lateral length- Landing depth- Tubing/casing size/depth- Number of entry points- Missed entry points- Completion type- Proppant volume- Proppant type- Fluid volume- Fluid type- Treatment schedule- Well spacing
Just one of many variables that influence well performance
Assessing the Impact of Completion Type:what causes one well to perform better than another?
Modified from Reynolds et al. (CSUR 2015)
Range of 12-month oil is ~ 170 MBOE (P10 – P90)
Completion technology impacts 12-month oil by only 20 MBOE
Impact of Completion Parameters:Difficult to Measure at the Play Level
Operations- Open versus choked flow- Shut-ins- Flowing pressure profile- Artificial lift- Separator pressure/temp
Reservoir/Fluid- Reservoir pressure- Net pay- Porosity- Sw- Young’s modulus- Poisson’s ratio- Natural fractures- Stress profile- Permeability- Fluid compressibility- Pore compressibility- Fluid viscosity- Gas solubility- Gas gravity- Oil API gravity
Completion/Wellbore- Lateral length- Landing depth- Tubing/casing size/depth- Number of entry points- Missed entry points- Proppant volume- Completion type- Proppant type- Fluid volume- Fluid type- Treatment schedule- Well spacing- Azimuth- Toe up/down
Measured and modeled
Measured and controlled
Controlled due to proximity
Measured but not modeled
Benchmarking Procedure Using RTA
Objective: Determine whether new pinpoint completions are performing better or worse than incumbent P&P technology
- Choose small area (2-5 wells)- Control important variables
- Azimuth- Landing Depth
- 1 P&P well (2010)- 2 pinpoint wells (2014-15)- Well spacing ~ 1320 ft
Permian (Bone Spring) Example 1
Rate-time
Compound Linear Typecurv e Analysis
Jitterbug 161 #H101BE
10-2
10-1
1.0
101
102
5 . 10-3
2
46
23
5
23
5
2
46
Norm
aliz
ed R
ate
10-3 10-2 10-1 1.0 101 102 8 . 1022 3 4 5 6 2 3 4 5 6 7 2 3 4 5 6 2 3 4 5 6 2 3 4 5 6 7 2 3 4
Material Balance Time
k = 6 microdarciesxf = 132 ft
xs/xf = 1
Early linear flow followed by transitional flow
P&P – Type Curve Analysis
k = 20 μdxf = 135 ftDrainage = 160 acFCD = 5
Final Np matches simulated
P&P – Benchmark Model
mprop
FCD
xf
𝐹𝐶𝐷=𝑥 𝑓 ( h𝑏𝑒𝑛𝑐 𝑚𝑎𝑟𝑘)𝐹 𝐶𝐷( h𝑏𝑒𝑛𝑐 𝑚𝑎𝑟𝑘)
𝑥 𝑓
xf
P&P (calibration well)
2.4 Mlbs
NCS #2NCS #1
1.72 Mlbs1.7 Mlbs
119 ft120 ft
135 ft
P&P (calibration well)NCS #2
NCS #1
5
5.65.7
Adjusting for Different Treatment Size Between Benchmark and Comparison Wells
k = 20 μdxf = 119 ftDrainage = 160 acFCD = 5.7
Pinpoint #1 outperforms P&P by 22 Mstb over 8 months
1320 ft
Pinpoint #1 – Comparison Model
k = 20 μdxf = 120 ftDrainage = 160 acFCD = 5.7
Pinpoint #2 same as P&P over 5 months
Pinpoint #2 – Comparison Model
• Oil wells with solution gas(700-1000 scf/stb)
• Initial Pressure = 4592 psia
• TVD ~ 9000 ft
• 42 deg API
• ~8000 ft laterals
Permian (Spraberry) Example 2
Spraberry Example – Benchmark model created using long pinpoint well
• Benchmark model is validated using short pinpoint well data
Validation of Benchmark Model
Model outperforms data
Benchmark Model Compared to P&P Well
Benchmark220 Mstb (6 yr)
Actual140 Mstb (6 yr)
Lynch A Unit 9HS (h=307ft, xf=200ft)
Company: On Stream: 19/12/2015Field: SpraberryCurrent Status: Flowing
Gp: 48 MMscfNp: 44.327 MstbWp: 55.096 MstbQcond: 0.000 Mstb
102
103
7 . 101
8
9
2
3
4
5
6
7
8
9
Op
Oil
Rate (s
tb/d
)
105
0
5
10
15
20
25
30
35
40
45
50
55
60
65
70
75
80
85
90
95
100
Cumulative O
il Production (M
stb)
December January February March
2015 2016
Daily
Oil
Rate
(BO
PD)
Benefit of Pinpoint = 10,000 STB
Benchmark versus Actual after 90 Days
• Impact of completion technology is important but may be masked by more dominant variables
• Reservoir flow capacity (k, h)
• Reservoir storage capacity (pi, h, ct, f)
• Well construction (lateral length, stage count, treatment size)
• We have been able to quantify (in stock tank barrels) the benefit of pinpoint completions using RTA benchmarking workflow
Assessing the Impact of Completion Technology:Conclusions
• Quantifying impact of frac fluid selection on well performance
• Identifying poorly performing proppant as the culprit of declining well productivity
• Assessing impact of well trajectory on well performance – azimuth and toe up/down
Other Applications for RTA Benchmarking
• Connecting net pay – maximize frac height
• Importance of economics• Is bigger always better?
5 yr Oil Recovery
Optimizing Stage Spacing and Treatment Size
• The same total treatment size delivered using different completion technologies can yield drastically different and unanticipated results
k =0.55 mdxf = 90 ftFCD = 0.5Drainage = 279 ac(exceeds well spacing)
Bone Spring Example
P&P (Benchmark)
Pinpoint (comparison)
Connecting Net Pay – Bone Spring Example
A
B
C
D,E
40,000 lbs
• Designed volume going into each entry point
• Likely not connecting the A & B sands
Pinpoint Completion
Connecting Net Pay – Bone Spring Example
P&P Completion
A
B
C
D,E
+120,000 lbs
• Designed for 30-40 k lbs per cluster but most of the proppant and fluid going into only one entry point!
• A & B sands likely contributing to well performance
Breakdown pressures ra
nge
from 3700 to
8700 psi
Connecting Net Pay – Bone Spring Example
• Treatment size / stage density economics for different oil prices
31 m / 35 T15 m / 45 T
$30 oil
$40
$50
$60
$70
$80
Larger job / denser spacingonly becomes optimum above $70 oil
Importance of Economics – Liquids-Rich Montney
• Treatment size / stage spacing economics at $40 oil
45 m / 80 T45 m / 60 T45 m / 45 T45 m / 35 T31 m / 35 T31 m / 45 T31 m / 60 T31 m / 80 T15 m / 45 T
Highest recovery but worst economics
Sparse stage spacing with larger treatment size per stage wins
Importance of Economics – Liquids-Rich Montney
Attaining Predictable and Scalable Results
SRV = 2xfLehf(1-sw)
2 xf
h
Le
A =
4 nf x f h
• Can we see a proportional benefit from scaling up horizontal well length at fixed stage spacing / treatment size?
Completion Effectiveness Measured• A and SRV from Rate Transient Analysis – Liquids-Rich Montney
SQRT Time
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2200
2400
2600
2800
3000
3200No
rmal
ized
Pre
ssur
e ((
106 p
si2 /
cP)/M
Msc
fd)
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Gas Linear Superposition Time (d1/2) / Gas Material Balance Square Root Time (d1/2)
Legend4-19 NCS13-30 NCS14-25 NCS15-25 NCS13-17 OH14-30 OH5-23 PNP8-20 PNP16-17 PNP16-25 PNP2-18 PNP
92,630 md1/2ft
9.3 MMsqft @ 100 nd
20,602 md1/2 ft
2.1 MMsqft @ 100 nd
FMB
0.015
0.000
0.001
0.002
0.003
0.004
0.005
0.006
0.007
0.008
0.009
0.010
0.011
0.012
0.013
0.014
Gas
Nor
mal
ized
Rat
e (M
Msc
fd/(1
06ps
i2 /cP
))
0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00 2.20 2.40 2.60 2.80 3.00
Normalized Gas Cumulative Production (Bscf)
Legend4-19 NCS13-30 NCS14-25 NCS15-25 NCS13-17 OH14-30 OH5-23 PNP8-20 PNP16-17 PNP16-25 PNP2-18 PNP
Square Root Time Plot- Total Frac Area- Well Productivity
Flowing Material Balance- Stimulated Reservoir Volume- Decline Rate / Reserves
SRV = 3 bcfSRV = 1.6 bcf
Sqrt Material Balance Time Normalized Cumulative ProductionNor
mal
ized
Prod
uctio
n Ra
te
Nor
mal
ized
Flow
ing
Pres
sure
Pinpoint Achieves Predictable Results
Pinpoint Achieves Scalable Results
0.050.0
100.0150.0200.0250.0300.0350.0400.0450.0
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
EUR
(Mst
b)
Hz Well Length (ft)
Condensate EUR per Foot of Horizontal Well Length
Pinpoint
OH
Plug and Perf
0.050.0
100.0150.0200.0250.0300.0350.0400.0450.0
0 500000 1000000 1500000 2000000 2500000 3000000 3500000
EUR
(Mst
b)
Total Proppant Pumped (kg)
Condensate EUR per kg of Proppant Pumped
Pinpoint
OH
Plug and Perf
Long pinpoint wells on trend
Large pinpoint jobs on trend
0.050.0
100.0150.0200.0250.0300.0350.0400.0450.0
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
EUR
(Mst
b)
Hz Well Length (ft)
Condensate EUR per Foot of Horizontal Well Length
Pinpoint
OH
Plug and Perf
0.050.0
100.0150.0200.0250.0300.0350.0400.0450.0
0 500000 1000000 1500000 2000000 2500000 3000000 3500000
EUR
(Mst
b)
Total Proppant Pumped (kg)
Condensate EUR per kg of Proppant Pumped
Pinpoint
OH
Plug and Perf
Long pinpoint wells on trend
Large pinpoint jobs on trend
Infill Wells – PinpointParent Wells – Plug and Perf
131H
133H
132H - Gas Condensate- TVD ~ 8,200 ft
700 ft
700 ft
Maximizing Completion Effectiveness for Infills – Eagle Ford Example
Completion Effectiveness Comparison
P&P
Pinpoint
P&P
Highest connected fracture area
Lowest apparent fracture conductivity
Stimulated Reservoir Volume Comparison
132H NCS
Comparison View
0.010
0.000
0.001
0.002
0.003
0.004
0.005
0.006
0.007
0.008
0.009
Gas
Nor
mal
ized
Rat
e (M
Msc
fd/(1
06ps
i2/c
P))
3.100.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00 2.10 2.20 2.30 2.40 2.50 2.60 2.70 2.80 2.90 3.00
Normalized Gas Cumulative Production (Bscf)
P&P WellsOGIP = 1.5 and 1.8 bcf
Pinpoint WellOGIP = 2.9 bcf
Productivity falls off after frac hits
Performance versus Treatment Size
2000000 2500000 3000000 3500000 4000000 4500000 5000000 55000000
0.5
1
1.5
2
2.5
3
3.5
SRV versus Total Proppant
2000000 2500000 3000000 3500000 4000000 4500000 5000000 55000000
2000
4000
6000
8000
10000
12000
Aggregate xf versus Total Proppant
50000 55000 60000 65000 70000 75000 80000 85000 90000 950000
0.5
1
1.5
2
2.5
3
3.5
SRV versus Total Fluid
50000 55000 60000 65000 70000 75000 80000 85000 90000 950000
2000
4000
6000
8000
10000
12000
Aggregate xf versus Total Fluid
SRV
(bcf
)Ag
greg
ate
x f (ft)
Proppant Pumped (lbs)
P&PP&P
PinpointP&P
P&P
Pinpoint
Total Fluid (bbl)
• RTA benchmarking provides an effective way to cut through the “noise” and identify key completion parameters
• Pinpoint is a quantifiable performance driver in Permian and Montney
• Effective frac height is the most important consideration in optimizing completion design
• May need $70 oil to support 1 joint spacing in the Montney
• Pinpoint completions in the Montney demonstrate predictability and scalability – Double hz achieved 2X performance
• Pinpoint appears to be a promising technology for infills – Eagle Ford
So… What Have We Learned?
Thank You!
Questions?
