Transcript OCT PRESENTATION

OUR “NEW TRICKS”
FOR
YOUR “OLD RESERVOIRS”
Oil Chem Technologies, Inc.
Sugar Land, TX
Oil Recovery Overview
PRIMARY
15%
RESIDUAL
OIP
33%
WATER
18%
TERTIARY
34%
BAVIER; BASIC CONCEPTS OF EOR PROCESSES(1991)
YOUR “OLD RESERVOIRS”
0
6
4
4
3
Oman
India
UK
France
Germany
3 0.9
Romania
Denmark
Dubai
7
Norway
12 10 10 9
Brazil
Canada
Mexico
Qatar
20
China
Nigeria
Libya
40
Russia
60
Venezuela
Abu Dhabi
80
Kuwait
84
Iraq
Iran
100
USA
180
S. Arabia
Billion Bbls
CHEMICAL IOR TARGET IN
SELECTED COUNTRIES
173
160
140
120
100
77
63 61
51
40
26 24
0.6 0.3 0.2
REPORTED CHEMICAL IOR
PROJECTS WORLDWIDE
Indonesia
Venezuela
USA
India
France
China
Total Number of Projects: 27
OGJ April 12, 2004
REPORTED CHEMICAL IOR
PRODUCTION WORLDWIDE
France
Indonesia
USA
China
Total oil production: 300,000 B/D
OGJ April 12, 2004
LOUDON FLOOD - EXXON
1983
2.3% surfactant
 96% of the connate salinity
 0.3% pore volume
 0.1% Xanthan gum
 56 million pounds surfactant was
injected in 9 months
 68% ROIP

BIG MUDDY – CONOCO
1981
3% surfactant
 5% Isobutyl alcohol as cosurfactant
 0.6% salt
 0.22% polyacrylamide
 0.1 pore volume
 15% ROIP

ROBINSON – MARATHON
1983
10% surfactant – petroleum sulfonate
 0.8% hexanol as co-surfactant
 2.5% salt
 No polymer
 0.1 pore volume
 19 –21% ROIP

IOR BY CHEMICAL FLOOD
Limited commercial success for the
past two decades - Reasons?
Sensitivity to oil price
 Large up-front investment
 Unpredictable return on investment
 Availability of chemicals
 Limitations of chemicals
 Poor scaling from lab to field

PAST PROBLEMS
High surfactant concentration
 Salinity optimization required
 Optimum salinity shift in the
formation
 Potential emulsion block
 Potential residual additive in the
produced oil
 Economical Feasibility

however,
Extensive lab evaluations support the
feasibility of chemical flooding
 Field data proves chemical flooding is
an effective way to recover residual oil
 New chemicals and processes open the
door for new opportunities

OUR “NEW TRICKS”
FOR
YOUR “OLD RESERVOIRS”
MECHANISM

Solubilization

Mobilization
• Micellar
•
•
•
•
• High surfactant
concentration
• Low surfactant
concentration
ASP
LASP
OASP
Super Surfactant
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
AP vs SP
o
Oil API Gravity = 9.5 BHT = 30 C
1
0.1
IFT mN/m
0.5% Na2CO3
1.0% Na2CO3
0.01
2.0% Na2CO3
0.1% B-1688
0.1% B-1688 Unsoftened
0.001
0.0001
0
30
60
90
Elapsed time, min
120
AP VS. SP
Properties
IFT, (mN/m)
Alkali Polymer (AP)
Surfactant
Polymer (SP)
~10 0 - 10 –1
 10 -2
Potential Alkali reaction
in formation
2NaOH + Ca+2 2Na+ + Ca (OH)2
Effect on Polymer
will effect the polymer
viscosity
None
2NaOH + Mg+2 2Na++ Mg(OH)2
No effect
Water Treatment
Yes
No
Chemical Cost / bbl *
~ $1.0 - $1.36 /bbl
~ $0.64 /bbl
Potential corrosion
/scale problems
Yes
No
* The price is based on 0.1% surfactant and polymer, 1.0% NaOH
RELATIONSHIP BETWEEN CAPILLARY
NUMBER AND OIL RECOVERY
% Oil Recovered
100
80
60
40
20
Nc =  µ /
Nc = Capillary Number
 = Darcy Velocity
µ = Viscosity
 = Interfacial Tension
0
1.E-06
1.E-05
1.E-04
1.E-03
1.E-02
Capillary Number
Chatzis and Morrow, SPEJ, (1994) 561.
AP vs. SP
% Oil Recovered
100
80
60
40
Using Surfactant
20
0
1.E-06
1.E-05
1.E-04
Capillary Number
1.E-03
1.E-02
AP vs. SP
AP: 0.1% polymer / 1.0% NaOH
SP: 0.1% surf. / 0.1% polymer
AP
SP
Chemical Cosr, $ /
bbl
$1.22
$0.61
Polymer Increase
Due to NaOH
$$$
0
Equipment
Corrosion
$$$
0
Scale Formation
$$$
0
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
ASP SURFACTANTS
ORS & ORS-HF
SERIES
ADVANTAGES
 Field Proven
 Consistent quality
 Low concentration required
 One component system
 Low viscosity
SHO-VEL-TUM FIELD



On production > 40 yrs, extensive water flood,
produced 4 bbl/day
ASP started on 2/98, using Na2CO3 and ORS62
Total incremental oil > 10,444 bbl in 1.3 years
SPE 84904
OIL SATURATION AFTER ASP
INJECTION
35
So, %PV
30
25
20
15
10
5
0.00
0.10
0.20
0.30
0.40
(SURFACTANT CONC, % )(ASP SLUG SIZE)
SPE 84904
ORS-62HF(2)
ORS-46HF
ORS-41
ORS-41HF
ORS-97
SS-7593
ORS-62
SS-B6688
ORS-57HF
ORS-41HF
INJECTED, ON-GOING & APPROVED PROJECTS
SELECTED REFERENCES
USING ORS SURFACTANTS
 SPE 100004, 84904, 84075, 71491,
57288, 49018, 36748
 Hart’s Petroleum Engineering
International, Dec. 1998.
 DOE/PC/910087-0328 (OSTI ID: 3994)
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
LOW ALKALI SURFACTANT
POLYMER FLOOD
(LASP)
ASP - POTENTIAL PROBLEMS?
After extensive ASP flood in China, results
were successful, however:





Alkali causes corrosion of the equipment
Scale forms in the formation
Produced wells plugged and require
fracturing treatment to produce oil again
Alkali is detrimental to polymer viscosity
Extra polymer, NaOH and maintenance costs
SPE 71492, 71061
ASP







LASP
Combines the advantages of ASP and SP
Use 0.1 – 0.6% alkali
Reduces surfactant adsorption
Reduces polymer degradation
Reduce the maintenance cost
Reduce the scale formation
Reduces the total cost of the treatment
ASP vs. LASP
Common ASP: 0.1% surf. / 1.0% NaOH
Common LASP: 0.1% surf. / 0.2% NaOH
ASP
LASP
$1.22
$0.79
Polymer Cost
Due to NaOH
$$$
$
Equipment
Corrosion
$$$
$
Scale Formation
$$$
$
AS, $ / bbl
LASP - IFT vs. % NaOH
0.1% ORS-62HF, TDS ~ 3,500 ppm, API Gravity ~ 40, Temp ~ 40 C,
IFT, mN/m
1
0.1
0.01
0.001
0.0
0.2
0.4
0.6
% NaOH
0.8
1.0
1.2
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
ORGANIC ALKALI
SURFACTANT POLYMER
FLOOD
(OASP)
SPE 99581
COMPATIBILITY
WITH HARD WATER
Na2 CO3 + Ca ++
CaCO3
Na2 CO3 + Mg ++
MgCO3
NaOH + Ca ++
CaCO3
NaOH + Mg ++
MgCO3
BRINE COMPATIBILITY
ASP INJECTION SITE DIAGRAM
Produced Water
Alkali
Water Treatment
Surfactant
Injection Well
Polymer
OASP INJECTION SITE DIAGRAM
Produced Water
Organic Alkali
Surfactant
Polymer
Injection Well
OASP INJECTION SITE
DIAGRAM
Produced Water
Alkali
Water Treatment
Surfactant
Injection Well
Polymer
ECONOMIC COMPARSION
CUMULATIVE COST
100
75
ORGANIC ALKALI
50
CONVENTIONAL ASP
25
0
0
2
4
6
YEARS
8
10
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
SUPER SURFACTANTS
SS Series
ADVANTAGES
 Super Effective
• Ultra-Low concentration required
(0.02% - 0.2%)
• Provides ultra-low IFT
 Super Convenient
• No alkali is required
• No water treatment is required
ADVANTAGES - Continued
 Super Tolerant
• High TDS brine
• High divalent cations
• High temperatures
ADVANTAGES - Continued
 Super Savings
•
•
•
•
•
•
•
•
Surfactant
Alkali
Polymer
Water treatment
Sludge disposal
Surface equipment
Potential scale formation
Equipment maintenance
SS IN HIGH SALINITY BRINE
TDS ~190,000ppm, Ca, Mg ~ 95,000 ppm
Temp. ~ 50 C, API Gravity ~ 35
IFT, mN/m
1
0.1
0.01
0.001
0
0.05
0.1
0.15
SS 6-105, % Wt.
0.2
0.25
SS IN HIGH TEMP. HEAVY CRUDE
TDS ~ 250 PPM, TEMP.~ 100 C, API GRAVITY ~15
IFT, mN/m
1.0000
0.1000
0.0100
0.0010
0.0001
0.00
0.05
0.10
0.15
SS-B2550, WT%
0.20
0.25
SELECTED REFERENCES USING
SS SURFACTANTS

SPE 75186 – SPE IOR Meeting,
April, 2002

SPE 80237 – SPE Oil Field Chemistry
Meeting, Feb., 2003
ON-GOING LAB EVALUATION STAGE PROJECTS
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
SMART SURFACTANT








One component system
Provides low IFT and proper viscosity
Salt and divalent cation tolerant
No water treatment required
No polymer required
No dissolving or hydration unit required
Minimal up-front investment
Minimal risk factor
US Patent Pending
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
WATER FLOOD
Injector
Producer
SURFACTANT FLOOD
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SURFACTANT FLOOD
Injector
Producer
SMART SURFACTANT
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT
Injector
Producer
SMART SURFACTANT™
Injector
Producer
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects
FLOW IMPROVER
Creating a low viscosity pseudoemulsion that is easily transported
through the pipeline.
PRESENTATION OUTLINE

Why Do We Need Surfactant
• AP vs. SP

Our New Tricks – For Your Old Reservoirs
•
•
•
•
•
•

ASP
LASP
OASP
Super Surfactant
Smart Surfactant
Flow Improver
Start Your IOR Projects


Reservoir Analysis
Reservoir Characterization
History Matching –reservoir model,
production history













IOR Feasibility
Prescreening
Lab Studies
Simulations
Pilot Test
Pilot design
Monitoring operations
Result Interpretation
Field Operation
Spacing pattern
Well completion
Surface Equipment
Injection Fluid design
IOR Project Summary
Economical analysis
Decision on other projects
Comparison of different Scenarios
HOW TO PLAN A FLOOD







Choose a process likely to succeed
in a candidate reservoir
Determine the reasons for success
or failure of past projects using the
process
Carry out lab studies. Optimize the
chemicals/processes
Determine process mechanisms
Field pilot test
Establish chemical supply
Financial incentives essential
SURFACTANT SCREENING
Oil Company
IOR Surfactants
Specialty Company
Testing Lab or Oil
Company in-house lab
OIL COMPANY
Geology and mineralogy
 Well history
 Field based research
 Environmental restrictions
 Financial incentives essential
 Choose a process likely to
succeed in a candidate reservoir
 Determine process mechanisms

IOR SURFACTANT
SPECIALTY COMPANY
State of the art surfactant technology
 Chemical implementation details

•
•
•
•
•
•
Surfactant customization
Surfactant properties
Surfactant compatibilities
Surfactant optimization
Raw material availability and economics
Potential surfactant localization for enlarged
field flood
IOR SURFACTANT SPECIALTY
COMPANY (Cont’d)

IOR process optimization
•
•
•
•
•
•
•
•
Alkaline
Polymer
ASP
LASP
OASP
SP
CO2
Etc.
IOR SURFACTANT SPECIALTY
COMPANY (Cont’d)

Continue working with oil
company and testing company
to further optimize the surfactant
/process based on their data.
OPTIMIZATION OF SURFACTANT
Sho-Vel-Tum Field, 30 oC
0.1000
0.0100
ORS-41
ORS-62
ORS-57
0.0010
0.0001
0.25
0.50
0.75
1.00
1.25
Na2CO3, %
1.50
1.75
2.00
TESTING LAB OR OIL
COMPANY IN-HOUSE LAB
Product and process evaluation
 Other additive evaluation
 Core flood
 Injection sequence design
 Simulation
 Work with the oil company and IOR
surfactant specialty company to further
optimize the injection design

ENLARGED FIELD FLOOD

Raw material supply
• Source
• Availability

Manufacturing Location
• Shipping, tax, etc.
• Improve local economy
 Capital investment
• Up-front investment
• Operational cost

Flexibility of the plant
CONCLUSIONS

Two trillion bbl of oil remain in
depleted or abandoned wells

Chemical floods offer the only chance
in many depleted and water flooded
reservoirs

Chemical IOR must be re-evaluated
based on current technical and
economic conditions
CONCLUSIONS – CONT’D

Chemical flooding can maximize the
reserves in known reservoirs

Improved processes and chemicals are
available

Better scaling and modeling has been
developed
START PLANNING ON YOUR
CHEMICAL IOR PROJECTS
TODAY!!
COMPLIMENTARY
SURFACTANT EVALUATION
 You
send:
• Oil and injection brine
samples
• Brief field history
• Reservoir properties
COMPLIMENTARY
SURFACTANT EVALUATION
 We
will:
• Perform initial Surfactant screening
• Send you the sample for your
detailed evaluation and injection
design or submission to an
independent testing lab
• Further optimize the surfactant
based on your result
Etc.
TEAM WORK - KEY TO SUCCESS
THANK YOU !
Oil Chem Technologies, Inc.
12822 Park One Drive
Sugar Land, TX 77478
281-240-0161
www.oil-chem.com