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