Les enjeux de l`extraction pétrolière en conditions extrêmes non

Les enjeux de l’extraction pétrolière
en conditions extrêmes non
conventionnelles
Arnaud ETCHECOPAR
SCHLUMBERGER
Quality
Low Perm
Tight Gas
Unconventional
Oil
Sands
• large volumes
• difficult to
Gas Shales HP-HT Heavy Coalbed
develop
Oil
Methane
Gas Hydrates
Oil Shales
Improved Technology
Conventional Resources
•small volumes
High –
•easy to develop
Medium
Increasing Pricing
RESOURCE TRIANGLE
Nouveaux objectifs
•
•
•
•
Tight sands gas (very low permeability)
Center basin shales (source rocks)
Heavy oil (viscosity problems)
Low resistivity carbonates (impossible to evaluate
using conventional resistivity methods)
• Hydrates
• Increasing oil recovery
– Estimation of the remaining oil
– decrease the oil wetability
– Improvement of the exchanges matrix to fracture
Nouvelles conditions
• High temperature, High pressure
• Ultra deep offshore
Sismique dans l’artique?
Tight sand gas
U.S. Annual Percentage of Gas vs. Oil Rigs Operating
100.0%
90.0%
80.0%
70.0%
60.0%
Percent of Gas Rigs
50.0%
Percent ofOil Rigs
40.0%
30.0%
20.0%
10.0%
0.0%
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
U.S. Natural Gas Production Per Well
200
180
160
MMcf/Well
140
120
100
80
60
40
20
0
70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 00 02
Tight Gas Development Challenges
• Mainly geomechanical problems
• Long intervals of stacked sands (500-1000m)
–
–
–
–
–
All zones require hydraulic fracturing
Optimizing frac designs
Optimizing number of frac stages
Differential depletion
Stress profile and rock properties
• Very close well spacing required
– Well spacing and positioning
– Length/ orientation of fracs
• High efficiencies required (low margins)
p0
p1
p2
Center basins shales (source rocks)
(micro to nano Darcy)
•
What are they?
– Organic-rich shales
– Source rocks
– TOC : Adsorbed and free gas
Common traits of gas shale reservoirs
– Abundant gas (40 to 120 BCF/section)
– Very low permeability (no production if
no fracture)
– Low recovery efficiency (8 to 12%)
– Require natural fracture stimulation,
then produce much more than expected from
Darcy’s lows
– Horizontal wells
– Long well life
Longitudinal View of Microseismic Events
Scaled by Occurrence
8,600
8,800
9,000
Depth (TVD) (ft)
•
9,200
9,400
Events from Start of Pumping-15:25
Haygood Lois #10
Perforations:
Geophones
9,600
9,800
-1,200 -1,000
-800
-600
-400
-200
0
200
400
Distance Along Projection (ft)
600
800
1,000
1,200
Low resistivity carbonates
Archie :
Sw=80-90%
.525 psi/ft water
.454 psi/ft water
5450 BOPD,
0WC
Resistivity from close wells : similar Rt, different Sw
OIL
Water
Wetability
Which measurement to replace resistivity?
Increasing oil recovery
– Estimation of the remaining oil, not so obvious
• An objective for seismic methods?
– decrease the rock wetability to oil
• How chimical fluids diffuse inside rocks?
– Improvement of the exchanges between matrix
and fractures
How to manage fractured reservoirs?
?
100m
From borehole images it is possible to describe precisely a fractured
reservoir (orientation, density, aperture, length etc) but…Oil recovery
factors significantly lower than average (<< 35%)
How to optimize fractured reservoir producibility?
N
A Common Scenario:
Excellent initial production from
the oil contained in fractures,
followed by rapid depletion
What is the best trajectory to produce
such a reservoir?
In case of water coning, is it possible to
accelerate the exchanges between the
matrix and the fractures?
Another Common Scenario:
Reservoir under water injection
Porosity <15%, permeability < 5 mD, strongly oil-wet matrix, and connected
fractures
ÎVery limited water imbibition in the oil-wet matrix Æ Very low recovery factor <
10%
Definition of High-pressure, Hightemperature (HPHT) Environment
Global HPHT Fields and Prospects
–
HPHT wells begin at
150 degC [302 degF] and
68.95 MPa [10000 psi]
–
Ultra-HPHT wells begin at
205 degC [401 degF] and
137.90 MPa [20000 psi]
–
HPHT-hc wells have
bottomhole conditions
greater than 260 degC [500
degF] and 241.32 MPa
[35000 psi]
650
HPHT-hc
South Sumatra - HO
Liaohe
(HO)
Reservoir Temperature
Deep Gas
(Antietam?)
Salak mountain, West Java (Steam)
550
PDO South
Oman (HO)
450
PDO Central Oman (HO)
Oxy South Oman (HO)
UltraHPHT
Gulf of
Thailand
South Umm Gudair Eocene (HO)
Krishna
Godawari
Scorpio (North Padre Island)
Mobile Bay
Victoria
Jackdaw
Xinjiang
Pemex
South
350
UDW Angola
Khuff D
HPHT
Thunderhorse
Jack
250
Kaskida
Tubular Bells
Tahiti
Mad Dog
150
0
5000
10000
15000
20000
25000
30000
35000
Reservoir Pressure
This definition does not specify, nor depend on, the source of heat or pressure.
(i.e. wells having a source of heat introduced to the well bore for extraction purposes can still be governed by this definition.)
Source document: HPHT Definition v1.doc
Wells vs Burial Depth
Burial Depth (m)
Year
Joseph
Deep Offshore
Knotty Head
Slide source: Deeply Buried Reservoir Project - TOTAL presentation to SLB Jan. 2007
Original data source: IHS 2005
Why is HPHT Different?
•Effects of high-pressure impacts:
•Effects of high-temperature:
– Formation
– Thermal expansion/contraction
•
•
•
Pore pressure
Fracture pressure
Compaction and effective stress
(slower ROP)
– Wellbore
•
•
•
•
•
Drilling mud density
Completion fluid density
Cement density, viscosity
Downhole tools (MWD, LWD, WL,
Testing, Completions, AL)
Tubulars
– Surface Equipment
•
BOPs, wellheads
•
•
•
•
•
reservoir fluids
wellbore fluids
Cement (and spacers)
tubulars
seals
– Electronics
•
•
stability
longevity
– Surface Equipment
•
Handling of mud and drill pipe
Much less measurements
… and usually accompanied by significant concentrations of H2S and CO2.
HPHT Operations – Drilling Challenges
•Well Placement
–
Adequate ratings (P&T) for all equipment used in drilling wells in “conventional” environment (Motors, RSS,
MWD)
– Casing wear/increased exposure as a result of slower ROP
Well Control
– ECD management – Pore pressure is near frac gradient, drilling fluid density, rheology, surge/swab pressure .
– Mud loss is an issue due to lithology and geopressure.
– Hole ballooning causes mud storage problems. The walls of the well expand outward because of increased
pressure during pumping. When pumping stops, the walls contract and return to normal size. Excess mud is
then forced out of the well.
– Borehole stability – geomechanics modeling
– Fluid stability – Water-based mud realistically works to 425°F while oil and synthetic mud is stable up to
500°F. Gas solubility in OBM.
– Early kick detection –significant gas expansion from bottomhole conditions to surface.
Slow ROP or Non-Productive Time
– Drilling in HPHT formations are 10% of normal drilling conditions
– Stuck pipe and twisting off
– Trip Time – caused by tool failure (LWD/MWD) and bit trips
– Suboptimal decision making caused by lack of XHPHT experience (the “learning curve”)
– Safety issues associated with handling hot drilling fluids, hot drill strings
HPHT Operations – Cementing Challenges
Performance
–
Fluid properties
•
Gas flow must be controlled (significant in HPHT environment) .
•
Pumpable and stable/homogeneous at elevated temperature/pressure
•
Filtrate loss must be controlled at BHCT
•
Compatible with all well fluids at BHCT
•
Limited shrinkage over time
•
Consider formation damage issues
–
Mechanical properties
•
Adequate strength for long-term structural integrity
•
Wellbore strengthening/stability products to reach targets
•
Must provide a good shear bond
•
Low permeability
–
H2S and CO2 stability
Design and Test
–
Rheological model – accurate computer simulations and rheology measurements that occur in downhole conditions are required
in predicting wellbore pressures during cement placement.
–
Lab testing at BHST/BHP – No standards of test format for use with HPHT wells.
–
Alternative Sealants –replacements for conventional Portland cement.
Operations
–
Sealant Density Control – Equipment must be capable of mixing high density sealants accurately.
–
Bond Logs and Evaluation – Ensure zonal isolation and bond to the formation and the pipe.
–
Friction Pressure – to take into account for very long work strings that may be encountered.
–
Optimizing Placement – Develop procedures and methods to optimize drilling fluid displacement during cement jobs in HPHT
conditions.
–
Equipment ratings – plug and float, ECP’s, Liner Packers
HPHT Operations – Completion Challenges
•Fluids
– Expansion, upper limits to fluid density, stability, corrosion
– Formation compatibility
Flow Assurance
– Temperature limits of inhibitors, high injection pressures
– Compatibility with well effluents
Equipment Ratings/Reliability
– Time/temperature stability of (perforating) explosives, gun pressure ratings
– Measurements (sensors and system longevity)
– Seal longevity (dynamic, metal-metal, new polymers)
– Packer performance – rig time (intervention), casing stress from slips
– Metallurgy
– Thermal cycling and tubing stresses
•Operations
– Intervention rig time (especially subsea) and equipment specs
– Training in HPHT operations
Equipment Testing Facilities
Conclusion
• Ca fait beaucoup de changements pour une
industrie tres conservatrice…