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1
Improving Energy Efficiency in Thermal Oil Recovery
Surface Facilities
N.M. NADELLA
SNC Lavalin Inc.
Summary
Thermal oil recovery methods such as Cyclic
Steam Stimulation (CSS), Steam Assisted
Gravity Drainage (SAGD) and In-situ
Combustion are being used for recovering
heavy oil and bitumen. These processes expend
energy to recover oil.
The process design of the surface facilities
requires optimization to improve the efficiency
of oil recovery by minimizing the energy
consumption per barrel of oil produced.
Optimization involves minimizing external
energy use by heat integration. This paper
discusses the unit processes and design
methodology considering thermodynamic
energy requirements and heat integration
methods to improve energy efficiency in the
surface facilities. A design case study is
presented.
Introduction
As primary oil production declines,
enhanced oil recovery (EOR) methods will be
increasingly deployed. For the recovery of
heavy oil and bitumen, thermal recovery
methods have become standard methods of
recovery. For bitumen resources in Alberta,
Canada, thermal recovery and mining are the
main recovery methods.
Thermal oil recovery methods involve use of
heat to improve the oil recovery from petroleum
reservoirs. These methods are,
• Hot water flood
• Steam methods like CSS, SAGD,
steam flood
• In-situ Combustion
There are several variations of the above
methods1 like co-injection of solvents, gases
and air as shown in Figure 1.
As shown in Figure 2, 98.1% of the thermal
EOR production is currently based on Steam,
while 1.7% is based on in-situ combustion and
0.2% based on hot water flooding2.
Surface facilities for the steam based thermal
production requires steam generation plants,
water treatment for boiler feed water
generation, produced water recycle and
wastewater treatment units in addition to well
pads, gathering systems, pipelines, oil
treatment, gas treatment units and other utilities
and offsite units.
Surface facilities for in-situ combustion
methods require air compression units, steam
generation on a smaller scale, produced gas
treatment, oil treatment, water treatment and
other utilities and offsite units. This paper
discusses surface facilities for steam based oil
recovery and in-situ combustion processes.
The surface facilities may also include
cogeneration units for electric power, sour gas
treatment, sulfur recovery, carbon capture and
sequestration units as part of the overall project.
Therefore, the process design of surface
facilities involves process integration and
energy optimization to minimize overall costs
of steam and/or power generation, maximize
heat recovery recognizing trade-offs between
capital and operating costs, and minimizing the
overall waste heat loss and utility cooling or
heating.
Description of Surface Facilities
The process units in the surface facilities for
steam based thermal oil recovery and in-situ
combustion are described below and compared
2
in Table 1. In addition, wastewater treatment,
campsites and other infrastructure facilities will
be required depending on the project location.
Steam Based Thermal Facilities
Steam based thermal processes like CSS,
SAGD or steam flood have very similar surface
facilities. Main process units in such surface
facilities are shown in Figure 3. The surface
facilities consist of the following main process
units,
• Well Pad facilities
• Pump Stations
• Central Plant and
• Pipelines
Well pad facilities include well controls,
steam distribution and control, production
control, well testing and gathering systems.
The produced fluids are sent directly to the
Central Plant if the well pads are located close
by. If the well pads are located far from the
Central Plant, intermediate pumping stations
may be required. Alternatively, Central Plant
may be combined with well pad if there is only
one well pad in the facility. Currently, the CSS
and SAGD surface facilities are being designed
for capacities of 5,000 barrels/day to 100,000
barrels/day of oil production.
The Central Plant consists of oil processing,
produced water de-oiling, water treatment,
steam generation, product storage and pumping,
utilities and off-sites.
There are several process options for each
unit of the surface facilities. These options are
listed in Table 1, column 2.
In-situ Combustion Surface Facilities
The main surface process units for In-situ
combustion are shown in Figure 4. The surface
facilities for in-situ combustion also consist of
the following main process units,
• Well Pad facilities
• Pump Stations
• Central Plant and
• Pipelines
Well pad facilities include well controls, air
and steam distribution and control, production
control, gas separation, sour gas handling, free
water knockout, de-sanding and emulsion
pumping.
The produced fluids are sent directly to the
Central Plant if the well pads are located close
by. If the well pads are located far from the
Central Plant, intermediate pumping stations
may be required. Alternatively, Central Plant
may be combined with well pad if there is only
one well pad in the facility. Currently the
design capacity of the in-situ combustion
projects is less than 10,000 barrels/day.
The process units are oil processing,
produced water de-oiling, water treatment,
steam and power co-generation, product storage
and pumping, air compression, sour gas
treatment, sulfur recovery, utilities and off-sites.
There are several process options for each
unit of the surface facilities. These options are
listed in Table 1 column 3.
Surface Facility Process Selection
The process option for each of the surface
units is selected based on the overall economics
for the project and are linked to factors like
production capacity, well-head operating
conditions, requirements and availability of
diluent, sales oil quality etc. The process
selection will be done during the conceptual
phase of the project. There will be more than
one process option that may be suitable for the
given design conditions. In such cases,
comparison of the capital and operating costs
for different processes will enable selection of
the economic design for the surface facilities.
This design will be refined through detailed
engineering phases.
Energy Consumption
Energy is consumed in the thermal oil
recovery surface facilities to generate steam or
compress air to support the oil recovery from
the reservoir. Steam generation consumes major
amount of energy in the steam based processes
while air compression requires the most energy
for in-situ combustion processes at the surface
facilities.
In this paper, energy consumed in the form of
fuel for steam generation, electricity for moving
3
fluids and treatment processes will be
considered for review and optimization.
Subsurface heat generation and energy
consumption for in-situ combustion in the
reservoir is not in the scope of this paper. The
selection of the enhanced oil recovery process
and screening parameters for a given oil
reservoir are described Green3 et al.
The fuel gas consumed in the thermal EOR
surface facilities is mainly to generate steam.
The amount of steam used per barrel of oil
production determines the overall energy
efficiency. In steam based processes, the
commonly used parameters reflecting energy
consumption are the steam to oil ratio (SOR)
and oil to steam ratio (OSR). Steam can be
injected continuously as in steam flood, or
SAGD or intermittently as in CSS process.
Also, the amount of steam injected varies
during the life of the project. Hence, cumulative
steam to oil ratio (CSOR) over the period of
steam injection is more reflective of the energy
consumption of the recovery process. This
parameter is dependent on reservoir
characteristics, development strategy and is
always optimized based on impact on oil
production. The steam to oil ratios for various
reservoir locations6 are given as,
Location OSR SOR Steam Floods, California
~ 0.25 ~ 4.0
CSS, California 0.5 - 1.0 1.0 – 2.0 CSS, Alberta 0.3 – 0.5 2.0 – 3.3 CSS, Venezuela ~ 3.0 ~ 0.33 SAGD, Alberta 0.3 – 0.5 2.0 – 3.3 The impact of SOR on energy consumed per
barrel of oil produced and the amount of heat in
the produced fluids6 is given in Figure 5.
In the in-situ combustion, the amount of air
injected per barrel of oil produced determines
the overall energy efficiency. A cumulative air
to oil ratio determines the overall project
economics. This quantity is also dependent on
reservoir characteristics.
Typical design parameters for each of the
thermal oil recovery processes have been
summarized from literature5 as,
EOR Method Typical Design Parameter
Hot water flood 9 m3 water/m
3oil
Steam Drive 1.66 – 6.29 ton steam/m3oil
Dry Combustion 3000 sm3air/m
3oil
Wet Combustion 170 – 1000 sm3 air/sm
3oil
Steam soak 0.16 – 2.0 ton steam/m3
CSS 0.3 – 3.3 ton steam/m3 oil
SAGD 2.0 – 3.3 ton steam/m3 oil
Surface facilities are designed to provide the
required steam or air for the thermal oil
recovery processes. Given the design air or
steam flow rates, the goal is to minimize energy
losses and minimize the fuel gas or other
utilities required in the surface facilities.
Energy Optimization
Energy optimization is an important part of
surface facilities process design. Some of the
general strategies to optimize the energy
consumption are,
• Evaluate and quantify the
thermodynamic limitations of the
treatment processes. Actual energy
consumption has to be higher than the
thermodynamic minimum. Select
processes with lower thermodynamic
minimum energy requirements.
• Select the surface process unit
operating conditions that match with
the reservoir operating conditions.
Thus heat exchange will be
minimized. Any heat exchange will
have efficiency limitation due to
entropy changes.
• Minimize transportation of hot fluids
for treatment to avoid insulation
losses
• Evaluate if direct contact heat
exchange is possible as this will be
more efficient than indirect heat
exchange.
• If cogeneration is required, maximize
fuel efficiency through heat recovery
steam generation.
• Avoid excess generation of low level
heat. Due to seasonal variations of
4
ambient temperatures, low level heat
from the process cooling will have to
be removed expending energy in air
or water cooling.
• Maximize heat integration between
hot and cold process streams to
minimize external heating or cooling.
• Select equipment like boilers, steam
turbines, heaters and pumps with
higher efficiencies.
• If low level heat generation could not
be avoided, consider waste heat
energy recovery units.
Some energy transfer processes specific to
thermal oil recovery processes and their impacts
are listed below,
Energy transfer process
Impact on Steam based Oil Recovery
Impact on in-situ Combustion
Heat recovery from produced liquids
High Low
Heat recovery from produced gas
Low High
Heat recovery from boiler blow down
High Low
Waste heat available for winterization
High High
Flue gas heat recovery
High High
Steam generation
High High
Air compression
Low High
Cogeneration of power
low high
Energy and Separation Processes
Energy is required for different separation
processes used in surface facilities. The
selection of these processes depends on their
suitability for treating the produced fluids i.e.,
meeting sales oil specification, and water
recycled as boiler feed water and waste water to
disposal wells.
When there is more than one suitable process
for a separation unit, energy consumption will
be important for process selection as this
impacts the operating costs for the unit.
Minimum Energy
Thermodynamics provides minimum energy
requirements and maximum thermodynamic
efficiency for a separation process,
The minimum thermodynamic work required
for separating a homogeneous mixture in to
pure products at constant temperature is given
by7,8 the increase of Gibb’s free energy of the
products over the feed. This can be expressed
as,
)1......(..........min FSTHW ∆=∆−∆=− Where, ∆H represents the change in enthalpy
between final and initial stages, ∆S represents
the change in entropy, and ∆F is the change of
the free energy. The free energy can be
expressed in terms of molal concentration of the
salt in water as,
∫∫ =∆=− dnaRTFdnW wlnmin
)2.......(....................ln2
1 0dn
p
pRT
n
n∫=
Where n represents the number of water
moles in the solution, R is the gas constant, aw
is the water activity in the solution, P is the
water vapor pressure assumed as an ideal gas.
The minimum work or energy can also be
expressed in terms of chemical potentials as,
)3..(..........min fpcFW µµµ −+=∆=− Where, the subscripts c, p, and f are
concentrate, product and feed, respectively.
Expressing chemical potential to activity
coefficients will result in an equation of the
form,
)4....(..........ln1
min ∑=
=−n
i
FiFiFi xxRTW γ
The activity coefficients for salt mixtures have
been published as relations of osmotic
constants8 and molality or as empirical relations
with temperatures for seawater desalination.
5
This minimum work estimation allows one to
evaluate various separation processes and also
signifies the difficulty of separation.
Practical Energy Consumption
In practice, the actual energy consumption
will be much higher due to,
• Fluid flow frictional pressure drops
• Heat transfer due to fluids at different
temperatures
• Non ideal mixing of fluids and mass
transfer
• Non ideal chemical reactions taking
place in the process
Practical energy consumptions for the
separation processes used in thermal oil
recovery surface facilities are given below, Separation Process (% Recovery)
Energy Consumption, kWh/1000Sm
3
Electrostatic oil-water separation (> 99)
53 – 819
Gas Floatation (>90) 21 – 26 Media Filtration (>99) 264 – 1,057 Warm Lime Softening (>90) 26 – 40 Ion Exchange for hardness removal (>99)
~ 431
Mechanical vapor compression
9 for evaporation
(97)
~ 18,494
Reverse Osmosis10 (35-55) 1,057 – 4,227
Multistage flash10 (10-20) 3,963
Multiple-effect distillation10
(>60) 1,849 – 2,642
Case Study
In order to illustrate energy optimization
methods described above, a case study for the
design of a 30,000 barrels/day SAGD facility in
Alberta is presented.
The design parameters and assumptions for
the case study and optimization results are as
follows,
30,000 BBL/day SAGD Facility
The steps in energy optimization of the
surface facilities are given in Figure 6. The
design parameters for this case are,
• Steam to oil ratio is 3.0
• Bitumen is produced using gas lift
• Well head production temperature is
179°C
• Warm lime softening and once
through steam generators are used
• Boiler blow down will be recycled
and make-up water rate is limited to
10% of boiler feed water rate.
• Low level heat generation and heat
rejection to utilities will be minimized
• Ambient temperatures vary between -
45°C to 35°C.
• Heat losses through insulation will be
neglected.
The optimized flow sheet with main process
parameters are shown in figure 7. Pinch
analysis results are shown in figures 8-10. The
results indicate,
• The only external heat required is for
steam generation.
• The heat from produced fluids is
recovered to boiler feed water, make-
up water and remaining heat is
recovered to ethylene glycol.
• Hot ethylene glycol is used for
building heating, heat tracing and
process heat requirements. Residual
heat is then used to preheat
combustion air to the steam
generators. Any remaining heat will
be dissipated through air coolers.
Some waste heat will be rejected
during summer when utility heat
requirements are reduced.
• Thermal efficiency of the surface
facilities is governed by the efficiency
of steam generators, while the
efficiency of the SAGD process is
governed by the steam to oil ratio
used.
• The fuel gas energy input is estimated
at about 0.9 to 1.3 GJ/BBL of bitumen
produced.
6
Conclusion
Thermal EOR processes and surface
facilities require high energy input to produce,
treat and transport the heavy oil from the
reservoir. In order to minimize the energy
expended per barrel of oil produced, process
integration and selection of suitable processes
for surface facilities is required. Heat
integration and Pinch analysis allows
quantification of the minimum energy
requirements and optimization of the heat
exchange networks.
Separation processes can be screened based
on energy consumption in addition to meeting
the process requirements.
Acknowledgement
The author wishes to acknowledge the
support from SNC Lavalin management in the
preparation and presentation of this paper.
ABBREVIATIONS
EOR: Enhanced oil recovery
OSR: Oil to steam ratio
CSOR: Cumulative steam to oil ratio
CSS: Cyclic steam stimulation
SAGD: Steam assisted gravity drainage
SOR: Steam to oil ratio
NOMENCLATURE
∆H = enthalpy difference
∆S = entropy difference
∆F = change in free energy
a = activity
P = vapor pressure
R = gas constant, energy/mol-
temperature
T = temperature, °K or °C
W = work, energy/mol
x = mol fraction of component
γ = activity coefficient
µ = chemical potential
Subscripts
c = concentrate
F, f = feed
i = component
min = minimum
max = maximum
n = number of components in feed
p = product
w = water
REFERENCES
1. S. Thomas, Enhanced Oil Recovery – An
Overview, Oil & Gas Science and Technology –
Rev. IFP, Vol. 63(2008), No. 1, pp 9-19.
2. Leena Kottungal, 2010 Worldwide EOR Survey,
Oil &Gas Journal, April 19, 2010; 108, 14,pp 41-
53 .
3. Don W. Green, G. Paul Willhite, Enhanced Oil
Recovery, SPE Textbook Series Vol. 6,
Richardson, Texas, 1998, Chapter 8, Table 8.1, p
302.
4. S.M. Farouq Ali, Heavy Oil – Ever Mobile,
Journal of Petroleum Science and Engineering 37
(2003) 5-9.
5. Daniel N. Dietz, Paper SPE-5558, Review of
Thermal Recovery Methods, 1975.
6. N.M. Nadella, Heat Integration and Energy
Optimization in SAGD Surface Facilities, Paper
2008-317, Proceedings of the World Heavy Oil
Congress, Edmonton, Alberta, Canada, March
2008.
7. Jimmy L. Humphrey, George E. Keller II,
Separation Process Technology, 1st Edition 1997,
pp 296-297, McGraw-Hill, New York.
8. Raphael Semiat, Energy Issues in Desalination
Processes, Environmental Science & Technology,
Vol. 42, No. 22, 2008, pp 8193-8201.
9. Heins, W.F., Start-up, Commissioning, and
Operational Data from the World’s First SAGD
Facilities using Evaporators to Treat Produced
Water for Boiler Feed Water, Paper 2006-183,
Canadian International Petroleum Conference,
June 13-15, 2006.
10. Srinivas (Vasu) Veerapaneni, Bruce Long, Scott
Freeman, Rick Bond, Reducing Energy
Consumption for Seawater Desalination, AWWA
Journal, June 2007, 99, 6; pp 95-106.
7
Table 1. Process Options for Thermal EOR Surface Facilities Process Unit Process Options (Steam based EOR) Process Options (In-situ Combustion)
Wells • Gas Lift • Electric Submersible pumps (ESP) • Pump jacks • Well-Test Skid
• Natural Lift • Steam Lift
Well Pads & Pump Stations • Group separator • Emulsion pumping • Separate gas and emulsion pipelines • Multiphase pumps • Options for heat recovery or heat
integration with Central Plant
• Gas separator • Free water knockout • Desanding tank and system • Vapor recovery on the tanks • Emulsion pumping • Separate gas and emulsion pipelines • Options for heat recovery or heat
integration with Central Plant
Oil Processing • Blend treatment using a diluent, free water knockout drum and electrostatic oil treaters.
• High temperature and low-pressure separators.
• Blend treatment using a diluent, free water knockout drum and electrostatic oil treaters.
• High temperature and low-pressure separators.
Produced Gas processing • Supply as fuel gas • Excess gas compressed and used as lift
gas or dehydrated and sent to offsite utility
• Sulfur removal unit for sour gases – several technologies
• Heat recovery from hot produced gas
• Water vapor condensation • H2S and CO2 removal • Sulfur Removal Unit with sour gas
flaring/incineration
Produced water de-oiling • Skim tanks, induced gas floatation and oil removal filters with crushed walnut shell media.
• Ceramic membranes
• Skim tanks, induced gas floatation and oil removal filters with crushed walnut shell media.
• Ceramic membranes
Water treatment • Silica and hardness removal using hot lime softeners or warm lime softeners followed by ion exchange
• Mechanical Vapor compression for evaporation
• Silica and hardness removal using hot lime softeners or warm lime softeners followed by ion exchange
• Mechanical Vapor compression for evaporation
• Ion exchange for TDS removal from condensed water
Steam generation • Once through steam generators (OTSG) • Drum type boilers • Combined steam and power generation
• Once through steam generators (OTSG) for injection steam
• Drum type boilers for superheated steam generation
• Combined steam and power generation
Emissions control • Low NOx burners • Flue gas desulfurization • CO2 capture and sequestration
• Low NOx burners • Flue gas desulfurization • CO2 capture and sequestration
Wastewater treatment • Scale inhibition and disposal to injection wells
• Membranes for waste reduction and water recycle.
• Evaporation and crystallization for zero liquid discharge
• Scale inhibition and disposal to injection wells
• Membranes for waste reduction and water recycle.
• Evaporation and crystallization for zero liquid discharge
8
EOR METHODS
THERMAL NON-THERMAL
HOT WATER STEAMIN-SITU
COMBUSTIONELECTRICAL
STEAM FLOOD
CSS
SAGD
THAI
LASER
VAPEXVAPEX+STEAM
SAGP
�CSS: Cyclic Steam Stimulation
�LASER: Liquid addition to Steam for Enhanced Recovery
�SAGD: Steam assisted Gravity Drainage
�Vapex: Vapor Extraction Process�SAGP: Steam Assisted Gas Push�THAI: Toe to Heel Air Injection
Total EOR
ProductionTotal Thermal Steam
In-Situ
CombustionHot Water
BPD 1,624,044 1,016,972 997,453 17,203 2,316
% of Total 100 63 61 1.06 0.14
Figure 1. Thermal EOR Methods
Figure 2. Production from Thermal Oil Recovery
9
DILUENT
EMULSION OIL TREATMENT
DILBIT STORAGE
OIL-WATER SEPARATION
WATER TREATMENT
PRODUCED GAS
NATURAL GASFG SYSTEM
STEAM GENERATION
STEAM TO WELL PADS
WASTE TO INJ. WELL
DILBIT TO PIPELINE
BRACKISH WATER MAKE-UP
FIGURE 3. SURFACE FACILITIES FOR STEAM BASED THERMAL EOR (SF,CSS,SAGD)
PRODUCED GAS TREATMENT (SRU)
OIL
BLOW DOWN
BFW
LIFT GAS
WELL PAD FACILITIES
DILUENT
EMULSION OIL TREATMENT
DILBIT STORAGE
OIL-WATER SEPARATION
WATER TREATMENT
PROD. GAS
NATURAL GAS
STEAM GENERATION + CO-GEN
WASTE TO INJ. WELL
DILBIT TO PIPELINE
WATER MAKE-UP
FIGURE 4. SURFACE FACILITIES FOR IN-SITU COMBUSTION
WELL PAD FACILITIES
OIL
BLOW DOWN
BFW
PRODUCED GAS TREATMENT (SRU)
AIR COMPR.
AIRSTEAM
10
SOR vs Heat Content of Produced Fluids
300,000
500,000
700,000
900,000
1,100,000
1,300,000
1,500,000
1,700,000
1,900,000
2,100,000
2,300,000
1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5SOR
Hea
t C
on
ten
t, k
J/B
BL
Bit
um
en P
rod
uce
d
31.90%
32.45%
33.00%
33.55%
34.10%
34.65%
35.20%
35.75%
36.30%
36.85%
37.40%
Fra
ctio
n o
f In
pu
t H
eat
Heat Content of Produced Fluids, KJ Total heat input to Reservoir, kJ % of Input Heat
Figure 5. Heat Content of Produced Fluids
FIGURE 6. FLOW CHART FOR ENERGY OPTIMIZATION
HEAT AND MATERIAL BALANCES
PINCH ANALYSIS AND HEAT INTEGRATION
HEX NETWORK OPTIONS
WASTE HEAT AND LOW LEVEL HEAT RECOVERY OPTIONS
UTILITY COSTS UTILITY SYSTEMS DESIGN
PROCESS CONFIGURATION
11
Figure 7. Overall Heat Integration for SAGD Surface Facilities
Figure 8. Composite Curves
Gas Lift
(RESERVOIR)
POWER(1 MW)
OIL TREATMENT
FWKO + TREATER
STEAM
GENERATION
(OTSG)
DEOILING & WATER
TREATMENT (WLS)
Ste
am
7 M
Pag
, 286
°C
120°C
Pro
duce
d W
ater
120o C
Dilbit
120oC
80o C
Dilbit
45oC
80oC
Waste Water
70oC
High TDS Water
70oC
BFW
180°C
70°CBlow down
286oC
100 GJ/hr
38 GJ/hr
93 GJ/hr-40°C
90°C
1444 GJ/hr
50 GJ/hr
POWER(1.2 MW)
5oC
HEAT TRACING, BLDG. HEAT,
PROCESS HEAT
BFW90°C
Disposal Well
Disposal Well
Pipeline/Storage
Combustion Air
Makeup Water
Diluent
5oC
165°C
Glycol S/U
Heater
30°C
Glycol Pumps
0 GJ/hr40°C
160°
C
213 GJ/hr
80 GJ/hr
POWER(7.5 MW)
1653
GJ/
hr
Pro
duce
d ga
s
131°CEmulsion
179°C
90°C
23 GJ/hr
75°C
110°C
Natural Gas
40°C
Flue Gas
144 GJ/hr
NOTES1. Bitumen Production: 30,000 BPD2. Naphtha Diluent used to produce Dilbit3. Gas Lift used for well production4. Natural Gas used in OTSG burners5. Heat transferred from steam to bitumen at 8°C6. Boiler efficiency = 90%7. The heat duty shown for boilers includes produced gas
Lift Gas
Produced Gas Treatment
Sulphur
98°C
LP Steam Sep
145°C
70°C6 GJ/hr
70°C
Recycle
64 GJ/hr
12
Figure 9. Temperature difference vs. Heat Exchanger network Area
Figure 10. Overall costs vs. ∆T minimum
top related