for the proposed 800 MW Combined Cycle Power Plant ...

April 2005 

Study and Estimate for CO 2 

Capture Facilities 

for the proposed 800 MW Combined Cycle 

Power Plant - Tjeldbergodden, Norway 

Non-confidential

CO 2 Capture Study 

For 800 MW Power Plant – Tjeldbergodden 

TABLE OF CONTENTS 

1.0 EXECUTIVE SUMMARY 

1.0 Executive Summary 

2.0 BASIS OF DESIGN 

2.1 Power Plant 

2.2 CO 2 Plant 

2.3 Process Design Basis 

2.4 Codes and Standards 

2.5 Units of Measurement 

2.6 Equipment Numbering 

2.7 Power Plant Design Assumptions 

3.0 PROCESS DESCRIPTION & DISCUSSIONS. 

3.1 CO 2 Capture 

3.2 Cooling Water Supplies 

3.3 Energy Integration 

3.4 Off Gas Plume Dispersion 

3.5 Emissions and Effluents 

3.6 Process Utility Interfaces 

3.7 Power Plant Pre-investment 

4.0 KEY DELIVERABLES – 

PFD’s, UFD’s, Mass Balances, Equipment List 

4.1 Block Flow Diagram 

4.2 PFD Economine FG Plus 

4.3 PFD Economine FG Plus – Compression 

4.4 Heat and Material Balances 

4.5 UFD Cooling Water 

4.6 Water Balance 

4.7 Equipment list 

5.0 FACILITIES LAYOUT 

5.1 Montage of Plant 

5.2 3D Perspective of CO 2 Plant 

5.3 Plot Plan CO 2 plant 

6.0 CAPEX ESTIMATE 

6.0 Total Installed Cost 

CB2005-0022_Final Report.Doc



1.0 EXECUTIVE SUMMARY 

1.1 Introduction 

Statoil ASA are proposing to build an 800 MW combined cycle power plant as part 

of the overall expansion of their methanol plant facilities at Tjeldbergodden. The 

plant will comprise two gas turbines, two HRSGs and a single steam turbine. As 

part of the Power Plant Statoil are considering using Fluor’s Economine FG + 

CO 2 capture licensed technology for emission control. 

1.2 Executive Summary 

Fluor have developed and licensed a CO 2 capture technology to be used for 

capture of acid gases in an oxidising environment where normal amines are 

rapidly degraded, such as are found in the exhaust gases of a combined cycle 

power plant. 

Statoil ASA engaged Fluor to undertake selective studies leading to the 

development of a capital cost estimate for the process facilities comprising the 

CO 2 capture plant, to be incorporated on an adjacent plot to the proposed power 

plant facilities at Tjeldbergodden. 

This report, which presents the non-confidential aspects of this study, outlines the 

studies undertaken to define the design basis for the CO 2 Plant, establishes the 

interface considerations, and assess the issues that may influence the design 

requirements of the power plant. The study draws conclusions that support the 

completion of the capital cost estimate for this plant. 

In summary, the report concludes that a CO 2 capture plant can be built as an 

integral addition to the power plant for an indicated total installed cost of $500.MM 




2.0 BASIS OF DESIGN 

2.1 Introduction 

This section presents the general design criteria for the CO 2 Capture Study at 

Tjeldbergodden, Base Scope – 800 MW Power Plant. 

Statoil is planning to install a combined cycle (CC) power plant based on 2 

commercially available gas turbines (GT) in the 250 -300 MW class with dedicated 

waste heat boilers and one common steam turbine whose nominal power output 

would be 800 MW. The flue gas quantity and quality from the two GTs was 

estimated by Fluor using standard software. 

Statoil is assessing the feasibility of capturing carbon dioxide from these two new 

plants for Enhanced Oil Recovery (EOR) using Fluor’s proprietary Econamine FG 

Plus SM (EFG+) technology. The carbon dioxide recovery is set at 85% resulting in 

an EFG+ plant with a 6,170 Te/day (100% CO 2 ) capacity. 

2.2 Site Data 

• The EFG+ plant is located at Statoil’s existing complex in Tjeldbergodden, 

Norway. 

2.3 Process Design Basis 

Design Philosophy 

The EFG+ plant consists of three absorption trains and one common stripper 

train. Three was chosen for the number of absorption trains based on the 

maximum allowable diameter of 15 meters for each absorber column. 

Plant Life 

The plant is designed for an operating life of no less than thirty (30) years. 

On-Stream Factor 

All systems are designed to achieve a minimum on-stream availability of 330 days 

per year. 




Feedstock Properties 

The properties of the flue gas from the gas turbines were estimated by Fluor using 

the GTPRO program and are provided in Table 2-1. 

Table 2-1 – EFG+ Plant Feedstock Properties 

Description 

Flue Gas 

Temperature, °C 80 

Pressure, kg/cm 2 (g) 0 

Flow, kg/s 1384.8 

Composition (vol%) 

Nitrogen 74.65 

Oxygen 12.70 

Carbon Dioxide 3.91 

Water 7.84 

Argon 0.90 

SO 2 

0 ppm 

NO 

22 ppm 

NO 2 Component of NOx 

3 ppm 

NOx Total 

25 ppm 

Product Specification 

The specification of the carbon dioxide product is shown in Table 2-2. 

Table 2-2 – Product Specification at Battery 

Limits 

Water 

Description 

Specification 

50 ppmw (max) 

Pressure, kg/cm 2 (g) 102 




Utilities 

The conditions for the utilities are shown in Table 2-3. 

Table 2-3 – Utilities 

Temperature 

°C 

Pressure, 

kg/cm 2 (g) 

Low Pressure Steam 148 3.5 

Medium Pressure Steam 160 5.4 

Make-up Water 40 6.5-7.0 

Sea Water Cooling Water Supply 18 4.5 

Other required utilities are: 

• Service water 

• Steam condensate return 

• Plant and instrument air 

• Nitrogen for blanketing 

2.4 Codes and Standards 

Return 

28 (max) 

Fluor standards are used for the equipment codes and standards (e.g. ASME, 

API, TEMA, ANSI). 

2.5 Units of Measurement 

All units of measurement are in the metric system and are shown in Table 5-1. 

Table 5-1 

Units of Measurement 

Temperature °C 

Pressure (gauge) 

(absolute) 

kg/cm 2 (g) 

kg/cm 2 (a) 

Vacuum 

mm H 2 O 

Liquid flow 

m 3 /hr, kg/hr 

Steam flow 

kg/hr 

Gas flow 

Nm 3 /hr 

(at 0°C & 760 mmHg) 

Heat flow 

kcal, Gcal 

Power 

kW 

Viscosity 

cP 

Dimensions 

m, mm 




2.6 Equipment Numbering 

Every piece of equipment is identified with an identification letter symbol indicating 

the equipment type and a three-digit item number with the notation A/B in the 

presence of a spare. The following table shows the different identification letter 

symbols. 

Equipment Identification 

Letter Symbol 

BL 

C 

E 

F 

K 

P 

PK 

SU 

T 

V 

Equipment / Instrument 

Blowers 

Columns/Towers 

Heat Exchangers and Coolers 

Filters 

Compressors 

Pumps 

Vendor Packages 

Sumps 

Tanks 

Vessels 

An example of equipment numbering is BL-100 for the Blower. 

2.7 Power plant design assumptions. 

GT Master Simulations. ( For Simulation Reports See Section 4.8) 

The exhaust gas composition was obtained from the GT-Pro simulation. As an 

input, the following gas composition which had been provided by Statoil was 

applied under the title Statoil Gas. 

Component 

Percentage by 

volume 

Nitrogen 0.39 

Carbon Dioxide 2.03 

Methane 86.65 

Ethane 6.52 

Propane 2.29 

Butane 1.27 

Pentane 0.46 

Hexane 0.39 

TOTAL 100.00 

From this analysis GT-Pro calculated the Lower Calorific Value at 25°C as 46662 

kJ/kg, and a molecular weight of 19.28. The calorific value was applied to give 

the correct combustion conditions in the gas turbine which results in the fuel flow 

rate and hence the exhaust gas composition was derived. 


3.0 PROCESS DESCRIPTION & DISCUSSIONS. 



This section provides the process basis for the CO 2 capture facilities and 

discusses under separate headings the various Power plant interface 

considerations and design basis assumptions used to establish the CO 2 plant 

base case design. 

3.1 CO 2 Capture – Process Description 

The following is a process description for the proposed Econamine FG Plus SM 

(EFG+) plant that will be located at Statoil’s site in Tjeldbergodden, Norway. 

The plant is designed for a carbon dioxide production capacity of 6,170 Te/d. The 

product carbon dioxide is compressed and sent to the battery limits of the plant for 

Enhanced Oil Recovery (EOR). 

The non-confidential process configuration for the EFG+ plant and carbon dioxide 

compression is shown in Process Flow Diagrams PFD-001 and PFD-002. 

The EFG+ plant battery limit for the flue gas feed is at the stacks of the Heat 

Recovery Steam Generators (HRSG). All of the flue gas from the two HRSGs is 

diverted from the stacks and is routed to the EFG+ plant thus resulting in a zero 

flow of gas through the stacks to the atmosphere. 

The tie-in points are at the two stacks where the flue gas is routed to a common 

header. The flue gas is then divided equally and routed through three ducts to the 

EFG+ plants in parallel. The following is a description of Train A for absorption, 

which is identical to Trains B and C. The stripper and CO 2 compression is one 

train common to the three absorption trains. 

The flue gas, at 80°C, enters the Direct Contact Cooler (DCC) (C-100) where the 

gas is cooled to 30°C by a circulating water stream and any particulates present in 

the flue gas are removed by scrubbing. The flue gas and the circulating water are 

contacted over packing. By lowering the gas temperature, much of the water 

vapor contained in the flue gas is condensed and separated from the feed gas 

before entering the Absorber (C-101). 

The circulating water enters the DCC at 25°C and is heated to 42°C by the cooling 

and condensing of water vapor in the flue gas. The circulating water from the 

DCC is routed through the DCC Water Cooler (E-100) by the DCC Circulating 

Water Pump (P-100A/B) and returned to the DCC. Cooling water at 18°C is used 

to cool the circulating water to 25°C. All cooling water used in the EFG+ plant is 

sea water from the cooling system in the power plant. 

A slip stream is diverted from the circulating water upstream of the pump and 

routed by the DCC Filter Pump (P-101A/B) through the DCC Circulating Water 

Filter (F-100) to continuously remove particulate matter. A portion of the filtered 

water is returned to the liquid surge volume in the bottom of the DCC. Excess 

water, produced in the DCC from the condensing of water vapor in the flue gas, is 

routed to the battery limits after filtration. The flow rate of this excess water is 

controlled by a flow controller with a reset by a level controller in the DCC. 

The cooled, overhead gas from the DCC is routed to Blower (BL-100) to 

overcome the pressure drop in the system. The flow rate of the feed gas to the 

Blower is maintained by controlling the inlet guide vanes of the blower. 




The treated flue gas is routed to the Absorber (C-101). The gas flows upwards 

counter current to the circulating MEA solvent. The MEA solvent reacts chemically 

with carbon dioxide, absorbing 80-90% of the carbon dioxide in the incoming flue 

gas. Residue gas, mainly nitrogen and oxygen , is vented after the wash section 

through the top of the absorber. 

The rich MEA solvent from all three trains is pumped from the bottom of the 

Absorber to the top of the Stripper (C-102) by the Rich Solvent Pump (P-103A/B). 

It is preheated in Solvent Cross Exchanger (E-103A-L) before entering the top of 

the stripping tower. In the Stripper, the rich MEA solvent is further heated in the 

Reboiler (E-104A/B/C/D) by means of low pressure steam, releasing the carbon 

dioxide. 

From the reboiler, the lean MEA solvent is pumped by the Lean Solvent Pump (P- 

104A/B/C), cooled against rich solvent in the Solvent Cross Exchanger (E-103A-L) 

and further cooled in the Lean Solvent Cooler (E-106A/B/C). A part of the lean 

MEA solvent is routed through the Lean Solvent Filter (F-102) in order to remove 

solution contaminants. The filtered solvent returns to the main lean solvent line. 

The combined solvent is then divided equally and routed to the three absorption 

trains. 

Water in the overhead gas from the Stripper is condensed in Condenser (E- 

105A/B) and separated from the carbon dioxide product in the Overhead 

Accumulator (V-100). A portion of the condensed water is returned to the Stripper 

with the balance being equally distributed to each of the Absorbers. The carbon 

dioxide product is then sent to the battery limit. 

To maintain the highest possible absorption capacity of the MEA solvent, 

contaminants, such as heat stable salts, are removed in the Reclaimer (E-107). 

The Reclaimer is operated as a semi-batch process. Heat stable salts are 

removed using a thermal process utilizing both LP and MP steam. 

The carbon dioxide product from the Overhead Accumulator is compressed in the 

Product CO 2 Compressor (K-100) to the required 103 kg/cm 2 (a) pressure. The 

compressor consists of five stages with intercooling provided. Each stage of 

compression is followed by an air cooler (E-108, 110, 112 and 114) and trim 

coolers (E-109, 111, 113 and 115) where the carbon dioxide product is cooled to 

25°C against cooling water. After each stage of cooling, the carbon dioxide is 

routed to knock-out drums (V-103, 104, 105 and 106) to remove condensate. At 

an interstage pressure of 39.5 kg/cm 2 (a), the compressed carbon dioxide is sent 

to a Dehydration Package (ME-100), which reduces the moisture level down to 

less than 50 ppm (weight basis). 

3.2 Cooling Water Supplies 

To achieve a temperature rise of 10°C, the basic power plant requires a cooling 

water flow of 41500 tons per hour. After the carbon capture plant is added the 

steam flow to the power plant condenser is greatly diminished however the flow 

through the condenser is unchanged so that the temperature rise now becomes 

5.28°C. 

The Carbon Dioxide capture plant has been specified to use outlet sea water from 

the power plant condenser as it does not have to reach such a low temperature to 




provide thermal efficiency in the power cycle. Its consumption was based on a 

temperature rise of 10°C, which required a flow rate of 36750 tons per hour. 

It is proposed to install a booster pump to serve the carbon dioxide capture plant, 

which takes suction from the return sea water connection on the power plant 

condenser. It will boost the pressure so that there is sufficient flow through the 

carbon dioxide capture plant coolers and fill the system to its highest elevation, 

which is 6 meters above grade for the highest condenser. 

If there is a weir box to control the pressure at the outlet of the power plant 

condenser, the suction to the booster pump and discharge from the carbon 

capture plant cooling system, may be made at this weir box without any 

connections to existing piping being required 

After passing through the heat exchangers the sea water is collected in the return 

main and is discharged to the outfall pit in the power plant. This prevents outlet 

sea water returning to the booster pump inlet. 

The system is depicted on the Cooling Water utility flow diagram, and the method 

of connection using the weir box in the outfall from the main power plant 

condenser is shown in the figure below 

Given a total flow of 41500 tons per hour the overall temperature rise is expected 

to be just above 14°C. 

To arrive at a specification for the booster pump an allowance of 0.7 Bar for the 

pipework in addition to the 0.7 bar for the heat exchangers and 0.6 bar for the 

control valves has been made. The static head difference between the level in 

the main weir box and the elevated weir box (see figure below) has been taken as 

7 metres. This give a total discharge pressure of 2.7 bar and for a flow of 

40000m3/h a hydraulic power of 3000kW is calculated. These are default values 

pending a full layout study and the investigation of operating some condensers 

under vacuum on the cooling water side. It is recognized therefore that power 

consumptions could be optimized during plant design. 


C.W. Users at Carbon Capture Plant 

Elevated Weir Box for 

Carbon Capture Plant 

Return from 

Main 

Condenser 

Booster Pump 

Outfall Weir Box 

Outfall to Sea 

Flow Schematic showing Cooling Water Supply and Return connected at Outfall Weir Box



3.3 Energy Integration 

In a conventional Combined Cycle Gas Turbine power plant the steam circuit 

is arranged to follow the decay in temperature of the exhaust gas as heat is 

abstracted to give the most efficient thermal cycle as shown below: 

HP Steam 

Source 

Reheat 

Coils 

IP Steam 

Source 

LP Steam 

Source 

Condenser 

Conventional Steam Circuit for CCGT Power Plant 

Where a plant is to be fitted with Carbon Dioxide capture, a considerable 

amount of heat is required for the regeneration of the scrubbing liquor. We 

have formulated a number of rules, which will give the best thermal efficiency 

of the total unit and are: 

1. Add “source heat at as high a temperature as possible so as to achieve 

the highest possible Carnot efficiency (set by source and sink 

temperatures). Add this heat to the highest efficiency combustion system 

and do nt add auxiliary low efficiency combustion devices. 

2. Reject heat to the “sink” at as low a temperature as possible 

3. Extract as much work from the working fluids in the expansion turbines of 

the power train and only extract LP steam for amine reboilers at the 

lowest possible pressure and temperature. 

4. Reject as little heat as possible to the “sink” and utilise as much waste 

heat as possible without violating any pinch rules 

5. Use the lowest possible energy in the amine stripper. This requires the 

use of the best solvents plus intensive integration within the amine 

capture plant. 

In designing a plant where the CO 2 capture plant is commissioned with the 

power plant, the steam turbine is sized so that it is working under optimum 

conditions when steam is being extracted for the CO 2 capture plant. 

If the CO 2 capture plant is to be commissioned some time after the power 

plant, then one can either: 




1. The alternative of using an auxiliary boiler to provide the steam for the 

CO2 capture plant has been demonstrated to be of lesser thermal 

efficiency 

If the rules of integration are to be followed then the alternatives are: 

2. Install the optimum steam turbine for the capture case and accept the 

inefficiency resulting while the capture plant is not present. 

3. Install the optimum steam turbine for the capture case and add a small 

steam turbine to accept the steam which will be used by the capture plant 

when it is eventually commissioned 

4. Install the optimum steam turbine for the non-capture case and accept the 

inefficiency resulting after the capture plant is commissioned and the 

plant will be configured as shown below 

HP Steam 

Source 

Reheat 

Coils 

IP Steam 

Source 

LP Steam 

Source 

Condenser 

Steam to CO 2 

capture plant 

Steam Circuit for CCGT Power Plant with steam extraction for CO 2 

capture plant 

GT-Master versions of the abated and non-abated cases were made and 

used to demonstrate each case in the off design form. The net thermal 

efficiencies obtained are: 

With Extract Without Extract 

Small LP Turbine (Abated case) 51.71% 55.31% 

Large LP Turbine (Non-abated case) 51.50% 56.63% 

In reality these results show so little difference between either configuration of 

turbine that there is no point in considering the addition of a small temporary 

turbine (alternative 3 above). Alternative 4 will give a marginally greater 

output until the Carbon dioxide capture plant is commissioned but the capital 

cost of the turbine is likely to be higher. It is suggested that options 2 & 4 

should be developed during detailed design with a turbine supplier when the 

costs can be developed in greater detail and when the minor performance 

differences can be quantified with assurance. 




3.4 Off Gas Plume Dispersion 

Stack Gas from Absorber Towers 

The stack gas has been passed through the absorber towers, therefore it will 

have been saturated with water as well as having had the majority of its acidic 

components removed. 

These acidic components include oxides of nitrogen as well as carbon 

dioxide. Thus the final effluent gas will be air from which a portion of the 

oxygen has been removed and which is saturated with water vapour at 37°C. 

The gas is not hazardous to life, however upon contact with cooler air, a 

visible plume of water vapour will form. Under freezing conditions this could 

form ice on exposed cold surfaces. 

The need for plume dispersal by heating or dilution with ambient air, will 

depend on the location of the plume in relation to access roads and work 

areas, where it could reduce visibility; and structures, where icing could lead 

to overloading of such structures. It is recommended that this be studied in a 

later phase. 

3.5 Emissions and Effluents Introduction 

The Econamine FG Plus SM (EFG+) process produces three main 

emissions/effluents: 

• Absorber Stack Emissions: MEA and Ammonia 

• Reclaimer Waste 

• DCC Excess Water containing dissolved carbon dioxide 

3.5.1 Absorber Stack Emissions 

The expected concentrations of MEA and ammonia in the absorber stack gas 

are as follows. 

Expected Emissions 

Expected 

Emissions 

MEA 

Ammonia 

ppmv 0.2 23 

3.5.2 Reclaimer Waste 

Heat stable salts (HSS) are formed in the EFG+ process due to acid-base 

reaction between MEA and different acid products present in the flue gas or in 

the solution, including: 

• SO 2 and SO 3 in the flue gas 

• The NO 2 portion of NO x in the flue gas 

• Small quantities of acids generated by oxidation MEA 




HSS are removed from the system using thermal reclaiming. The expected 

amount of reclaimer waste and a typical waste composition as follows. 

Table 2 

Reclaimer Waste 

Expected Amount Tonnes/yr 2,300 

Composition 

MEA %wt 15 

Water %wt 7 

MEA Degradation Products %wt 75 

Inorganic Residue %wt 3 

3.5.3 DCC Excess Water 

The hot flue gas from the Heat Recovery Steam Generators must first be 

cooled to the operating conditions of the EFG+ plant to minimize amine 

degradation. The gas is cooled in the Direct Contact Cooler (DCC) by a 

circulating water stream. By lowering the gas temperature, much of the water 

vapor contained in the flue gas is condensed and separated from the feed 

upstream of the absorber. The condensed water from the flue gas is taken 

out of the DCC with the hot circulating water. A slip stream of excess water is 

taken from the circulating water stream to maintain the water balance around 

the DCC. This DCC excess water contains some dissolved carbon dioxide 

and is combined with the cooling water return. The expected amount of DCC 

excess water is shown in table 3. 

Table 3 

DCC Excess Water 

Expected Amount m 3 /hr 116.4 

pH pH 5.0 – 5.5 

It is proposed that this water be used as demineralized plant make-up after 

degassing the carbon dioxide. 

3.6 Process Utility Interfaces 

The following table provides a listing of Power plant utility interfaces with 

relevant stream information. 

ECONAMINE FG PLUS SM INTERFACE TABLE 

Commodity Unit In/Out Flow Temp. 

(°C) 

Pressure 

BAR(G) 

PROCESS 

Flue Gas 

Vent Gas 

CO 2 Product 

DCC Excess 

Water 

1000 m 3 /hr 

(actual) 

1000 m 3 /hr 

(actual) 

m 3 /hr 

(actual) 

Te/hr 

In 5,090 80 0.0 

Out 4,231 37 0.0 

Out 90,361 25 0.6 

Out 115.5 42 2.5 

UTILITIES 

Demin Water Te/hr In 55.2 40 7.0 




Seawater 

Coolant Te/hr In 36,750 18 

2.7 @ Booster 

Pump Discharge 

Seawater 

Coolant 

Te/hr Out 36,750 28 

Low Pressure 

Steam Te/hr In 424.4 148 3.5 

Medium 

Pressure Steam 

Condensate 

Nitrogen 

Instrument Air 

CB2005-0022_Final Report.Doc 

ATM @ 7m 

elevation 

Te/hr In 24.1 (Note 1) 161 5.4 

Te/hr Out 424.4 147 7.2 

Nm 3 /hr In 4,839 30 7.0 

Nm 3 /hr In 122 30 7.0 

Notes: 

1) Medium Pressure Steam is required intermittently towards the end of the reclaiming cycle 

(8-12 hours per month). 

2) Pressure drop across water cooled exchangers = 0.7 BAR. Add additional 0.6 BAR for 

variable loss. Pressure loss in inlet lines allowance = 0.7 BAR. Elevation of outlet weir 

box taken as 7 meters. 

3.7 Power Plant Pre-investment 

It is anticipated that limited pre investment would be required in the Power 

plant to accommodate the carbon capture plant. Main pre investment would 

be in the specification of the HRSG and the steam turbine where a change to 

the specification of the equipment is best accommodated prior to purchase. 

Recommended changes to the specification are as follows. 

Qualifications to HRSG Specification to facilitate addition of Carbon Capture 

`Plant 

1. Steam Extracted form the crossover form the IP to LP sections of the 

turbine should be arranged to be at 4.6 Bar (a) at the turbine, so as to suit 

the temperature requirement of the carbon capture plant. 

2. Low pressure steam supply to the Carbon Capture Plant is to be supplied 

from the boiler drum plus extraction for the IP/LP crossover of the steam 

turbine. It will be desuperheated to near saturation conditions using an 

enthalpy controlled desuperheater. (See attached sketch at the end of this 

section.) 

3. No provision for a LP superheater is needed 

4. Preferred configuration of the HRSG is horizontal to enable the ductwork 

to the Carbon Capture plant to be arranged for minimum pressure loss 

5. Space provision should be made so that the structure of the HRSG can 

have a diverter damper installed at a later date, which will divert flue gas 

from the stack to the future Carbon Capture Plant 

Qualifications to Steam Turbine Specification to facilitate addition of Carbon 

Capture Plant 

1. Pressure at the IP/LP crossover to be 4.6 bar(a) 

2. The turbine is to be constructed to enable the later addition of controlled 

steam extraction from the IP/LP crossover. 

3. The actual LP steam pressure supplied should be controlled at the turbine 

to meet the load on the carbon capture plant



Sea Water Off Take. 

Sea water for cooling of the carbon capture plant is taken from the main 

Power plant cooling water supply. It is therefore recommended that the Wier 

Box associated with the SW return from the main condenser is sized sufficient 

to accommodate the suction and discharge piping to and from the carbon 

capture plant. 

As shown in the attached accompanying diagram. 




FW 

13.14p 

26T 

109.8h 

785.3M 

5.274p 

26T 

109.8h 

785.3M 

LPE 

103560 Q 

5.12p 

139T 

584.5h 

785.3M 

LPB 

65766 Q 

5.12p 

153T 

2748.6h 

90.23M 

ST extraction 

5.12p 

304T 

3073h 

289.2M 

695.1 M 

HP/IP 

5.12 p 

153 T 

2748.6 h 

90.23 M 

4.592p 

149T 

2739.3h 

424.4M 

45 M 


4.0 KEY DELIVERABLES – 

PFD’S, UFD’S, Mass Balances, Equipment List 



4.1 Block Flow Diagram 


Battery Limits 

Flue Gas to 

Atmosphere 

Gas 

Turbine 1 

HRSG 

1 

Stack 

Gas 

NNF 

Excess 

Water 

DCC 

Train A 

Cooling 

Water 

Return 

Blower 

Train A 

Cooling 

Water 

Supply 

Absorber 

Train A 

Flue Gas to 

Atmosphere 

Steam 

Reclaimer 

Condensate 

Dehydration 

Package 

CO 2 

Compressor 

Carbon Dioxide 

Product 

6,170 MTPD 

Gas 

Turbine 2 

HRSG 

2 

Stack 

Gas 

NNF 

Excess 

Water 

DCC 

Train B 

Cooling 

Water 

Return 

Cooling 

Water 

Supply 

Blower 

Train B 

Absorber 

Train B 

Flue Gas to 

Atmosphere 

Steam 

Stripper 

Reboiler 

Condensate 

Cooling 

Water 

Return 

Cooling 

Water 

Supply 

DCC 

Train C 

Blower 

Train C 

Absorber 

Train C 

Excess 

Water 

Abbreviations: 

DCC - Direct Contact Cooler 

HRSG - Heat Recovery Steam Generator 

MTPD - Metric Tons per Day 

NNF - Normally No Flow 

Cooling 

Water 

Return 

Cooling 

Water 

Supply 

Flue Gas 

Solvent 

CO2 Product 

Steam/Condensate 

Cooling Water 

Rev. Date Revision Description By 

A 2/15/05 Issued to Client. VJF 

Chk 

JG 

Appv 

SR 

Statoil 

Block Flow Diagram 

® 

Drawing Number: BFD-001



4.2 PFD Economine FG Plus 




4.3 PFD Economine FG Plus – Compression 




4.4 Heat and Material Balances 


Statoil 

Revision A 

Econamine FG Plus SM 

Contract: A0NL 

Overall Heat and Material Balance March 31, 2005 

Stream Description 

Flue Gas to Direct 

Contact Cooler 

Absorber Overhead to 

Atmosphere 

Make-Up Wash Water 

to Absorber 

Excess Water from 

DCC 

Carbon Dioxide 

Product 

Compressed CO2 

Product 

Stream Numbers 

Temperature, °C 

Pressure, kg/cm² (a) 

1 (Note 2) 

80.0 

1.03 

2 (Note 2) 

36.9 

1.03 

3 (Note 2) 

40.0 

1.03 

4 (Note 2) 

41.7 

3.53 

5 

25.0 

1.65 

6 

124.0 

103.43 

Component Flows MW kgmol/hr mol% kgmol/hr mol% kgmol/hr mol% kgmol/hr mol% kgmol/hr mol% kgmol/hr mol% 

H 2 O 18.02 13,782 7.8% 10,332 6.2% 3,072 100.0% 6,402 100.0% 120 2.0% 0 0.0% 

CO 2 44.01 6,873 3.9% 1,032 0.6% 0 0.0% 0 0.0% 5,841 98.0% 5,841 100.0% 

MEA 61.08 0 0.0% Trace 0.0% 0 0.0% 0 0.0% Trace 0.0% 0 0.0% 

N 2 + Ar 28.02 132,801 75.5% 132,801 79.8% 0 0.0% 0 0.0% 0 0.0% 0 0.0% 

O 2 32.00 22,323 12.7% 22,323 13.4% 0 0.0% 0 0.0% 0 0.0% 0 0.0% 

HSS - 0 0.0% 0 0.0% 0 0.0% 0 0.0% 0 0.0% 0 0.0% 

Total kgmol/hr 

Total kg/hr 

Molecular Weight 

Density, kg/m³ 

Liquid Flow, m³/hr 

Vapor Flow, m³/hr 

175,779 

4,985,400 

28.4 

0.980 

1,696,580 

166,488 

4,665,900 

28.0 

1.103 

1,410,319 

3,072 

55,200 

18.0 

992 

18.5 

6,402 

115,500 

18.0 

992 

38.8 

5,961 

259,200 

43.5 

2.869 

90,361 

5,841 

257,000 

44.0 

720 

356.9 

NOTES: 

1) Stream information corresponds to Process Flow Diagram PFD-001. 

2) Stream flow rate listed is the total flow to/from all three absorption trains of the Econamine FG Plus plant. Flow to/from each absorption train is 

one-third of the indicated flow.



4.5 UFD Cooling Water 


12,984 Te/hr 

28°C 

Seawater 

Return 

129.8 

Gcal/hr 

229.5 Gcal/hr 

2.24 

Gcal/hr 

1.95 

Gcal/hr 

1.85 

Gcal/hr 

2.08 

Gcal/hr 

E-100/200/300 

DCC Water 

Coolers 

Econamine FG 

Plus SM Absorption 

and Stripping 

E-109 

Compressor 

Trim Cooler #1 

E-111 

Compressor 


E-113 

Compressor 


E-115 

Compressor 


22,955 Te/hr 

223 Te/hr 

194 Te/hr 

185 Te/hr 

208 Te/hr 

Seawater from 

Power Plant 

18°C 

36,749 Te/hr 


A 4/4/05 Issued to Client JPG 

Chk 

VJF 

Appv 

SR 

Statoil 

Cooling Water Utility Flow Diagram 

Non-Confidential Version 

Drawing Number: UFD-001 

®



4.6 Water Balance 


186.0 Te/hr 

H 2 

O in Absorber 

Vent to Atmosphere 

H 2 

O in Flue Gas from 


Demin H 2 

O from 


248.4 Te/hr 

55.2 Te/hr 

CARBON DIOXIDE 

RECOVERY UNIT 

2.1 Te/hr H 2 

O in CO 2 

to 

Compression 

115.5 Te/hr DCC Excess H 2 

O to 



A 2/14/05 Issued to Client JPG 

Chk 

VJF 

Appv 

SR 

Statoil 

Water Balance 

® 

Drawing Number: BFD-002



4.7 Equipment list 



Preliminary Equipment List 

Compressors / Blowers 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Actual Inlet 

Flow 

Inlet Flow 

Suction 

Pressure 

Normal Pres. 

Rise 

Power 

m 3 /hr kg/hr kg/cm 2 (g) kg/cm 2 kW 

Materials 

Comments 

BL-100 Blower Data is Fluor Confidential 

BL-100M Blower Motor Data is Fluor Confidential 





K-100 

CO 2 Product 

Compressor 

90,361 259,200 

0.620 

102 22,281 316L SS 

Major Ticket Item: Cost = $3,922,695 

5-stage - 3 body centrifugal compressor. 

Cost does not include interstage coolers or interstage 

knockout pots. 

Cost basis: Factored from another vendor budgetary quote.



Exchangers 

Statoil 


Date: 04-Apr-2005 

Tag No. 

E-100, E-200, 

E-300 

Description 

Pres Temp Pres Temp 

Gcal/hr m 2 kg/cm 2 (g) °C bar (g) °C 

DCC Water Cooler Plate 43.3 1,548 6.0 125 6.0 125 CS Titanium 

E-101, E-201, E- 

Wash Water Cooler 

301 

TEMA 

Type or 

Plate 

Exch. 

Operating 

Duty 

Surface Area 

Shell/Hot (for Plate or 

AC) 

Design Conditions 

Tube/Cold 

(for Plate or AC) 

Shell/ 

Frame/ Fin 

Cost = $490,000 (per train) 

Cost basis: Vendor budgetary quote. 

Data is Fluor Confidential 

E-103 Solvent Cross Exhanger Data is Fluor Confidential 

Material 

Tube/ Plate 

Comments 

E-104 Reboiler Data is Fluor Confidential 

E-105 Condenser Data is Fluor Confidential 

E-106 Lean Solvent Cooler Data is Fluor Confidential 

E-107 Reclaimer Data is Fluor Confidential 

E-108 

CO 2 Compressor Air 

Cooler #1 

Air Cooler 2.33 - 4.5 125 - - Aluminum 304L SS 

Cost = $349,000 

Cost basis: In-house sizing and pricing 

E-109 

CO 2 Compressor Trim 

Cooler #1 

AEU 2.24 739.5 4.5 125 6.0 125 304 SS Titanium 

Cost = $425,000 


E-110 


Cooler #2 


Cost = $315,000 


E-111 


Cooler #2 


Cost = $416,000 


E-112 


Cooler #3 


Cost = $286,000 


E-113 


Cooler #3 


Cost = $414,000 


E-114 


Cooler #4 


Cost = $321,000 


E-115 


Cooler #4 


Cost = $486,000 

Cost basis: In-house sizing and pricing



Filters 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Operating 

Vol. Flow 

Part. Size 

Op. 

Temp 

Pressure 

Design 

Temp 

m 3 /hr micron °C kg/cm 2 (g) °C 

Material 

Comments 

F-100, F-200, F- 

300 

DCC Circulating Water Filter 105.1 5 42 6.6 125 

Shell: 304LSS 

Internals: 304 SS 



F-101, F-201, F- 

301 

Wash Water Filter 


F-102 Lean Solvent Filter Data is Fluor Confidential 

F-103 Solvent Sump Filter Data is Fluor Confidential



Columns and Vessels 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Vertical / 

Horizontal 

Dimensions 

Diameter T/T 

meter 

meter 

Design 

Press Temp 

kg/cm 2 (g) °C 

C-100/200/300 Direct Contact Cooler Vertical 13.8 15.9 0.7 125 

Material 

CS with 0.10" 

min 304L 

cladding 

Comments 

Major Ticket Item: Cost = $1,942,605 (per train) 

Cost basis: Factored from another project. 

Internals 

304 SS 

Major Ticket Item: Cost = $1,948,500 (per train) 


C-101/201/301 Absorber Data is Fluor Confidential 

Internals 


C-102 Stripper Data is Fluor Confidential 

Internals 


V-100 Overhead Accumulator Data is Fluor Confidential 

V-101 A/B 

Reboiler Condensate 

Drums 


V-102 

Reclaimer Condensate 

Drum 

Data is Fluor Confidential



Columns and Vessels (continued) 

Statoil 


Date: 18-Feb-2005 

Tag No. Description V/H 

Dimensions 

Diameter T/T 

meter meter 

Design 

Press Temp 

kg/cm 2 (g) °C 

Material 

Comments 

V-103 

CO 2 Compressor KO 

Drum #1 

Vertical 3.4 4.5 3.5 125 316 SS 

Cost = $108,700 

Cost basis: K-base 

V-104 


Drum #2 

Vertical 2.9 3.9 7.4 125 316 SS 

Cost = $86,800 


V-105 


Drum #3 

Vertical 2.4 3.4 17.0 125 316 SS 

Cost = $90,700 


V-106 


Drum #4 

Vertical 2.0 3.1 41.6 125 316 SS 

Cost = $116,100 


V-107 

Reclaimer Waste 

Vessel 




Pumps 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Pump Type 

Operating Diff. Hyd. Spec. 

Material 

Flow Head Power Grav. 

m 3 /hr m kW @ PT Impeller Casing 

Comments 

P-100/200/300 A/B DCC Circulating Water Pump Centrifugal 2,652 35.6 280.1 0.99 316L SS 316L SS 

P-101/201/301 A/B DCC Filter Pumps Centrifugal 105 53.7 15.5 0.99 CS CS 





Class S-4, if CS construction 

P-103/203/303 A/B Rich Solvent Pump Data is Fluor Confidential 

P-104 A/B/C Lean Solvent Pump Data is Fluor Confidential 

P-105 A/B Reflux Pump Data is Fluor Confidential 

P-106/206/306 A/B Wash Water Cooler Pump Data is Fluor Confidential 

P-107 Solvent Make-up Pump Data is Fluor Confidential 

P-108 Solvent Charge Pump Data is Fluor Confidential 

P-109 A/B 

Reboiler A/B Condensate 

Pump 


Tag No. Description Pump Type 



Pumps (continued) 

Operating Diff. Hyd. Spec. 

Material 

Flow Head Power Grav. 

m 3 /hr m kW @ PT Impeller Casing 

Statoil 


Date: 18-Feb-2005 

Comments 

P-110 A/B 

Reboiler C/D Condensate 

Pump 


P-111 A/B Solvent Sump Pump Data is Fluor Confidential 

P-112 A/B/C Seawater Booster Pump Data is Fluor Confidential



Sumps 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Dimensions 

Length Width Depth 

meter meter meter 

Comments 

SU-100 Solvent Sump Data is Fluor Confidential



Tanks 

Statoil 


Date: 04-Apr-2005 

Dimensions 

Design 

Tag No. 

Description 

Diameter 

T/T 

Pres 

Temp 

Material 

Comments 

meter 

meter 

mm H 2 O (g) °C 

TK-100 

Solvent Storage Tank 

(with Solvent Pump Suction Heater H- 

100) 




Miscellaneous 

Statoil 


Date: 04-Apr-2005 

Tag No. 

Description 

Material 

Comments 

PK-101 Soda Ash Injection Package Data is Fluor Confidential 

ME-100 

Dehydration Package 

Major Ticket Item: Cost = $1,914,885 


Glycerol Dryer dehydrating product CO2 to 50 pp (wt ) of water (-46°C water dew point): All equipment skid mounted. 

CR-01 

Cranes, Hoists, etc, CO2 

Compressor Building Service 

Crane 

Cost = $276,400



5.0 FACILITIES LAYOUT 

5.1 Montage of Plant 




5.2 3D Perspective of CO 2 Plant 




5.3 Plot Plan CO 2 plant 


THE INFORMATION ON THIS DRAWING DEPICTS THE IMPLEMENTATION OF FLUOR'S 

SM 

ECONAMINE FG PLUS TECHNOLOGY, WHICH IS CONFIDENTIAL AND THE SOLE PROPERTY 

OF AND PROPRIETARY TO THE FLUOR CORPORATION. 

CONFIDENTIAL

SECTION AA 

SECTION BB 


SM 



CONFIDENTIAL


SM 



CONFIDENTIAL


SM 



CONFIDENTIAL



6.0 CAPEX ESTIMATE 

6.0 Total Installed Cost 


SECTION 6 

TOTAL INSTALLED COST 

Direct Field Costs 

Other Costs 

$325 MM 

$175 MM 

Total Installed Cost 

$500 MM

for the proposed 800 MW Combined Cycle Power Plant ...

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