Key aspects of reservoir evaluation for deep water reservoirs

1. Key Aspects of Reservoir Evaluation
for Deep Water Projects
Xian ChengGang, PhD
Principal Reservoir Engineer Schlumberger
cxian@slb.com

2. Outline
• Deep Water Project Economics
• Challenges & Key Aspects
- Geomechanics
- Reservoir Characterizations
 Thin Beds & Compartimentalization
- Flow Assurance
 Accurate Fluid Characterization
• Conclusions

3. Deep Water—Major
Growth Globally
Source: Oilfield Review, US Bureau of Economic Geology, NPD, Infield

4. Deep Water Project Economics
Well Construction
DRILLEX
Subsea and Topsides
CAPEX
Field Operation Costs
OPEX
Abandonment Costs
ABEX
Recoverable Reserves =
Total Reserves * Recovery Factor
Total Cost = $$$ Total Money = $$$
Lift Cost = $$/bbl

5. Deep Water Project Economics:
DRILLEX
Well Construction
DRILLEX
Subsea and Topsides
CAPEX
Field Operation Costs
OPEX
Abandonment Costs
ABEX
Recoverable Reserves =
Total Reserves * Recovery Factor
Total Cost = $$$ Total Money = $$$
Lift Cost = $$/bbl
 Well Construction is 50-60% of total lift cost
 Drilling : 50% of Well Construction cost
 NPT : ~24-27%
 Completion : 50% of Well Construction cost
 NPT: ~30-35%
 Well Testing is very expensive – not all wells
 Field Development Frame is at the greatest
risk

6. Distribution of Costs in DW Wells
Going deeper,
rig cost getting bigger !
Rig Efficiency!

7. Deep Water Project Economics:
CAPEX
Well Construction
DRILLEX
Subsea and Topsides
CAPEX
Field Operation Costs
OPEX
Abandonment Costs
ABEX
Recoverable Reserves =
Total Reserves * Recovery Factor
Total Cost = $$$ Total Money = $$$
Lift Cost = $$/bbl
 Subsea architecture and production facilities
~40-50% of the total lifting cost
 Facility selection depends on reservoir
drainage strategy
 More production from less wells is dependent
on optimal well placement
 Reservoir Recovery factor vs. Artificial Lift
Strategy

8. Deep Water Project Economics:
CAPEX
Going deeper, Costing more
Reservoir Characterization

9. Deep Water Project Economics:
OPEX
Well Construction
DRILLEX
Subsea and Topsides
CAPEX
Field Operation Costs
OPEX
Abandonment Costs
ABEX
Recoverable Reserves =
Total Reserves * Recovery Factor
Total Cost = $$$ Total Money = $$$
Lift Cost = $$/bbl
 Intervention Cost is MOST significant
 You DO NOT want to do that if possible
 Flow Assurance requires expensive &
mechanical & chemical mitigation
 It can cost 1 bbl of 5 bbl of produced oil
 Optimal flow assurance depends on accurate
fluid characterization

10. Deep Water Challenges
Drilling Hazards
Well Integrity
Downstream Processes & Facilities
• Not all challenges are listed.
• Each one can be expanded to a long list.
• As going deeper, each individual challenge is increasingly elevated.
• Considering the life time of a project (not much we could do after construction), a tiny issue
for land could be potentially huge for deep water project.

11. Deep Water Challenge Example:
Drilling Hazards
1. VARIABLE AND
POORLY KNOWN
ENVIRONMENT
2. MASS TRANSPORT
EVENTS
3. Present-day Slope
stability
4. TURBIDITY
CURRENTS
5. BOTTOM CURRENTS
6. TSUNAMIS,
CYCLONES, STORM
SURGE
7. DRILLING PROBLEMS
– anchoring
– station keeping
– well design
– equipment design
– drilling fluids
– cementing
– shallow flow
– gas hydrates
– subsalt targets
– Monitoring
– Low Fracture Gradient
– Low Temperature
– …

12. Geomechanics Is Vital
• Shallow Hazards
• Hydrate
• Salt
• Overpressure
• Loss of well integrity
• Wellbore failure
• Sanding
• Stimulation
• Compaction and subsidence
• Fault reactivation
• Formation damage caused by
compaction
• …
Geomechanics is responsible for many challenges of DRILLEX

13. The Work Environment:
Narrow Drilling Window

14. Real Time Geomechanics
• History of NPT due to wellbore stability
problems fieldwide
• Real –Time Drilling Geomechanics utilized
all available data
– LWD data, leakoff tests, gas
information, formation integrity tests
(FIT)
• Provided 12-hr/24-hr drilling forecast
notifications
• No NPT related to wellbore stability
• Revised casing set points allowed option of
finishing in a small hole size or saving a
casing string
• Well completed 21 days faster than planned
• Surpassed ‘technical limit’ significantly

15. Final compaction Casing
Stress state along
well trajectory
Cement
Well location –
Unstructured grid
Details around the
well
Integrated Geomechanics:
Well Integrity Evaluation
Perforationzone
-722 m
-782 m
-792 m
-822 m
-837 m
-870 m
-912 m
-962 m
-988.7 m
A
A
B
B
C
C
D
D
E
E

16. Reservoirs: what, where & how?
Adapted from:
G. Shanmugam: Deep-marine tidal bottom
currents and their reworked sands in
modern and ancient submarine canyons.
Marine and Petroleum Geology 20 (2003)
471–491
Each reservoir is a result of a combination of factors(such as sediment, process, basin-geometry etc)

17. Sedimentology / Depositional
Environments

18. Petrophysical Challenges in
Deep Water
• Complex lithology where clay volume is
key
• Evaluation of reservoir quality in
environments where conventional
methods such as gamma ray and
neutron-density have proven to be
ineffective
• Presence of laminations and thin beds,
and inclusions of clay within the sands,
resulting in low contrast pay
• Low and varying or unknown water
formation salinity, again resulting in low
contrast pay

19. The cost of being wrong
Calculate using Rtapp
Rt = 2 ohm-m
Rw = 0.1
Porosity = 0.3
Sw = 0.71
BVW = 0.22
BVO = 0.08
In reality:
Rtcg = 20 ohm-m at 50% vol
Rtfg = 1 ohm-m at 50% vol
Rw = 0.1
Porosity = 0.3
Sw = 0.61
BVW = 0.18
BVO = 0.12
50% more HC

20. Thin Bed Evaluation Example
XX15
XX20
XX95
XX00
XX05
XX10
XX30
Water volume -
dielectric
Water volume –
conventional
(black) & triaxial
induction (orange)

21. Thin Bed Evaluation Example
Core and Image
Formation Evaluation Porosity Permeability Saturation
Gross (TVD) Net Pay (TVD) Av Phi Av So Av Vcl Av KINT Phi*H Phi*So*H
% Change - 78% 4% 29% -56% 74% 79% 85%
Gross (TVD) Net Pay (TVD) Av Phi Av So Av Vcl Av KINT Phi*H Phi*So*H
% Change - 3% 0% 0% 13% -19% 3% 3%

22. Reservoir Characterization :
Compartmentalization
Compartmentalized is more natural than not-
compartmentalized.

23. Reservoir Characterization :
Compartmentalization
• Conventional Methods
• Reservoir Pressures
– Pressure may be equilibrium in a
virginal reservoir
• Well Testing for Boundary Detection, DST，
Extended Well Testing, Interference Well
Testing, Multi-well Tracer
– Time Consuming, Costly,
Conclusions with high uncertainty
• Novel Approach: Fluid Properties beside
Conventional Methods
• (Real Time) Compositions (C1, C2-C5,
C6+, CO2), GOR, Colors, & Asphaltenes
• Higher Resolution & Frequency
• 2007, ExxonMobil launched a special
project “Reservoir Connectivity Analysis”
(IPTC 11375)

24. Spectrometer
Fluorescence
DV-Rod
Resistivity
P/T
Single phase
Fluid type
GOR
Composition (5)
CO2
Asphaltene
pH
Density
Viscosity
IFA
Downhole Fluid Analysis (DFA) – SPE 124365
Resistivity
Pressure
Temperature
IFA
Water / Oil
pH
GOR
Contamination
Composition (5)
Density
Viscosity
Fluorescence
P / T
Resistivity
Gas detection
CFA
Water / Oil
GOR
Composition (3)
Fluorescence
Accuracy
Fluid range
Fluid properties

25. Entropy Solubility
Gravity
Asphaltene
size / fluid
density
Fluid color
Size /
Composition /
GOR / density
New Equation of State for ASPHALTENES
Zuo, Freed, Mullins
Asphaltene Nanoscience: Yen-Mullins Model
Need GOR
Asphaltene

26. CONNECTED
NOT CONNECTED
Yen-Mullins Model
DFA + Asphaltene Nanoscience Predicts Connectivity
Chengli Dong, SPWLA-D-11-00111
Proven Correct in Production

27. Flow Assurance Domains
Production Chemistry Production
Engineering
Surveillance &
Operation
Fluid sampling, analysis,
characterization and prediction
of low assurance challenges
Definition, design and operability
assessment of production
systems
Production system optimization,
remediation, prevention and
mitigation techniques

28. Flow Assurance:
Where They Are

29. Flow Assurance:
Where They Are

30. PVT Behaviors:
More Proteins Included

31. Sample Purity Is Critical for Fluid
Characterization

32. filtrate
filtrate
Oil
kv
kh
kv
Conventional
Focused
Focused Sampling for Sample Purity

33. Focused Sampling for Sample Purity

34. Low Concentration of Non-Hydrocarbon
Contaminants in Natural Gas
• Contaminants in Natural Gas
• CO2
• H2S
• Mercury
• H2O
• Mercaptants (RSH)
• Carbonyl Sulfide (COS)
• Carbon Sulfide (CS2)
• The degree of removal depends on
downstream requirements
• They can play extremely costly roles

35. In-Situ CO2 Characterization:
SPE116501
In-situ LAB In-situ Lab In-situ Lab In-situ Lab In-situ Lab
T1 x244 Gas 64.0 70.4 29.7 20.7 1.0 2.4 0.0 3.0 4.9 2.9
S1 x414.5 Gas 63.0 72.6 22.1 20.9 0.6 2.2 0.0 2.0 4.5 1.8
S2 x466.5 Gas 60.0 61.8 29.1 28.5 0.7 2.8 0.0 3.2 7.3 3.0
S3 x497 Oil 7.5 6.2 2.2 1.9 0.5 0.4 0.9 1.1 88.8 90.3
S4 x521 Oil 1.8 2.9 3.2 2.0 0.4 0.4 1.1 1.3 93.5 93.7
S4 x521 Oil 2.0 3.3 3.1 2.3 0.4 0.4 1.4 1.1 93.1 92.8
Sandface Depth, m MD Fluid
C3-C5,wt% C6+,wt%
C1,wt% C2,wt%
CO2, wt%
IFA and Lab Results (came after 2 years of operation)

36. What Are the Operator Priorities
 Minimizing operational risk and complexity
 Rig efficiency while drilling & completing
 Completion & Production Reliability
 a. Minimize interface failures
 b. System longevity
 c. Minimize future interventions
 d. Its important to “prove up the technology” ie.. Qualification testing
 Optimize Production and Recovery Factors
 a. Stimulation required
 b. Artificial Lift required
 c. Reservoir Management required
 Vendor Accountability – minimize interfaces

37. Conclusions
• What is the biggest risk?
– Reservoir Characterization
• What is the biggest challenge?
• What would be the most critical
aspect?
– You & Me!

38. Thanks !
Questions?