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Ship transport of CO2 Status and Technology Gaps

Tel-Tek report no. [2214090]

Ragnhild Skagestad, Nils Eldrup, Hans Richard Hansen, Stefan Belfroid, Anette Mathisen,

Agnieszka Lach, Hans Aksel Haugen, 16.09.2014

Tel-Tek

Kjoelnes ring 30 NO-3918 Porsgrunn

NORWAY

Tel-Tek Telephone: Bank giro: Business register no.: Kjoelnes Ring 30 +47 35 57 40 00 2801 30 82881 NO 943 161 895 MVA N-3918 Porsgrunn, NORWAY E-mail: [email protected] Web: www.tel-tek.no

REFERENCE PAGE

Author(s)

Ragnhild Skagestad, Nils Eldrup, Hans Ri-chard Hansen, Stefan Belfroid, Anette Mathi-sen, Agnieszka Lach, Hans Aksel Haugen,

Report no.

[2214090]

Date

16.09.2014

Classification*

Internal

Pages/ Appendices

33/ 4

Report Title

Ship transport of CO2

Subtitle

Status and Technology Gaps

Project no

2214090

Report prepared for

Gassnova

Contact person

Hallvard Høydalsvik

Abstract

This report provides an overview of the current status of CO2 transport by ship, and gives a descrip-tion of identified gaps that need to be closed to bring CCS chains up and running. There are a few CO2 ships in daily use for food industry, but no CO2 is shipped today for storage purposes. The pro-ject has uncovered gaps in all parts of the chain from preparation for transport, via loading, shipping and unloading, to injection. For the studied case a way forward with the aim to close these gaps is suggested. If the gaps are closed, the studied scenario can probably be feasible, but should also be compared to alternative cases. The largest cost elements are the ship itself and the liquefaction. Operational cost (energy, crew) constitutes the most significant part of total cost per ton. The project also points to barges as an al-ternative not only to ships with tanks on board, but to fixed onshore installations. Likewise, the cold may in itself represent a possibility for energy saving if it can somehow be re-used. Both these ideas should be investigated further. Compared to pipeline transportation, ships/vessels have advantages when distances increase and volumes are not too high. Ships also constitute a way to start CO2 transportation at an earlier stage as compared to pipelines because of their flexibility and relatively low up-front investment cost.

Project leader: Ragnhild Skagestad

Signature:

Department leader: Hans Aksel Haugen

Signature:

Keywords CO2, ship transport, cost estimates for ship

transport

English Norwegian

Key 1 CO2transport Key 1

Key 2 Ship transport Key 2

Key 3 Cost estimates for ship case Key 3

*Classification:

Open – report can be cited, given proper citation, Internal – report is internal, Confidential

Tel-Tek Classification: Internal

Report no. [2214090] of 52

EXECUTIVE SUMMARY There are few CCS reports that only cover CO2 transport by ship. Nevertheless, commercial maritime transport of CO2 has been going on for many years, and many projects point out that shipping can be a good alternative to pipeline transport under certain conditions. This report provides an overview of the current status of CO2

transport by ship, and gives a description of identified gaps that need to be closed to bring CCS chains up and running. In CCS chain ships are only one element of the total transport chain. In addition, several elements need to be included, from liquefaction to unloading equipment. Pro-ject has uncovered gaps in all parts of chain. In order to better understanding requirements of CO2 transport, is necessary to dis-cuss advantages and disadvantages of all transport option. CO2 can be transported between sources and storage sites by pipelines, by road/rail way or by ships. Due to large amounts of CO2 to be transported, pipelines and ships are the most viable transportation alternatives for CCS purposes. Ship transport is most beneficial when it comes to small volumes and long distances, and is ideal if there are uncertainties about the volume and route in the year to come. Pipelines have the benefit of con-tinually flows/injection and can be laid both onshore and offshore. The case investigated in this report is based on two sources of CO2, which is cap-tured and liquefied, loaded into a ship and transported to permanent storage in a sa-line aquifer (Johansen formation). Prepared cost estimation shows the most signifi-cant parts of the total cost and ideas of which should be investigated further have been discussed. It has been a general understanding that CO2 transport is a relatively speaking straight forward part of the CCS chain and that few, if any, significant technological gaps exist. This report shows that this is not the case for ships. On the contrary, the project has uncovered gaps in all parts of the chain from preparation for transport, via loading, shipping and unloading, to injection. For the studied case a way forward with the aim to close these gaps is suggested. If the gaps are closed, the studied scenario can probably be feasible, but should also be compared to alternative cases. The largest cost elements are the ship itself and the liquefaction. Operational cost (energy, crew) constitutes the most significant part of total cost. The project also points to barges as an alternative not only to ships with tanks on board, but to fixed onshore installations. Likewise, the cold may in itself represent a possibility for en-ergy saving if it can somehow be re-used. Both these ideas should be investigated further. Compared to pipeline transportation, ships/vessels have advantages when distances increase and volumes are not too high. Ships also constitute a way to start CO2 transportation at an earlier stage as compared to pipelines because of their flexibility and relatively low up-front investment cost.


Report no. [2214090] of 52

Cost data for ship transport (Nth of a kind):

Cost data for ship transport (1st of a kind):

CAPEX

(kNOK)

OPEX

(kNOK/an)NOK/ton CO2

940 000 100 000 233

CAPEX

(kNOK)

OPEX

(kNOK/an)NOK/ton CO2

1 290 000 110 000 280


Report no. [2214090] of 52

CONTENTS 1 Introduction ........................................................................................................... 7

2 Ship transport of CO2 ............................................................................................ 8

2.1 Refrigerated, liquid CO2 transport ........................................................... 8

2.2 Compressed CO2 transport .................................................................... 9

2.3 Barge transport ....................................................................................... 9

3 Ship transport compared with pipelines ................................................................. 9

4 Short description of Ship transport status ............................................................ 11

4.1 Maturity of each element ...................................................................... 11

4.2 Safety ................................................................................................... 12

4.3 Storage tanks and liquefaction plant..................................................... 13

5 Injection ............................................................................................................... 15

5.1 Introduction ........................................................................................... 15

5.2 Johansen injection case ....................................................................... 15

5.3 Conclusions .......................................................................................... 16

6 Identified gaps ..................................................................................................... 17

6.1 Gaps related to preparation for ship transport ...................................... 17

6.2 Gaps related to ships ............................................................................ 17

6.3 Unloading related gaps ......................................................................... 18

6.4 Injection related gaps ........................................................................... 19

7 Other Possible solutions/innovations................................................................... 20

8 Description of scenario ........................................................................................ 20

9 Cost estimation ................................................................................................... 23

9.1 Assumptions ......................................................................................... 23

9.2 First of a kind (FOAK) and Nth of a kind (NOAK) ................................. 26

9.3 Cost estimates ...................................................................................... 26

9.4 Cost results .......................................................................................... 29


Report no. [2214090] of 52

10 Results/conclusion .............................................................................................. 31

11 Suggestion for further work ................................................................................. 32

12 Acknowledgements ............................................................................................. 33

Attachment 1 References /litterature ......................................................................... 34

Attachment 2 Ship Transport Cost data sheet from Hans Richard Hansen ............... 40

Attachment 3: Injection Simulation model and results ............................................... 43

Attachment 4: Possible steel types for low temperature service ................................ 52


Report no. [2214090] of 52

1 INTRODUCTION

There are few CCS reports that only cover CO2 transport by ship. Nevertheless, commercial maritime transport of CO2 has been going on for many years, and many projects point out that shipping can be a good alternative to pipeline transport under certain conditions. This report provides an overview of the current status of CO2

transport by ship, and gives a description of identified gaps that need to be closed to bring CCS chains up and running. The report is based on previous studies from ZEP, IEA, Tel-Tek, SINTEF as well as other CO2 transport studies. Conclusions from a workshop with an expert group held 13.08.2014 in Porsgrunn are also used as background. CO2 can be transported between sources and storage sites by pipelines, by road/rail, truck or by ship. If large amounts of CO2 are to be transported, pipelines and ships are the only viable transportation alternatives for CCS purposes. The use of ships provides flexibility in operation both with regard to the type and number of sources as well as storage sites. Ships also offer benefits due to short de-livery time and potential for reuse in other projects or non-CO2 transport and are as a result well suited for demo CCS projects or projects with limited lifetime, and also as start-up solution if building up a large scale pipeline-based infrastructure. CO2 Characteristics: Table 1. CO2 characteristics

Molecular weight 44.01 g/mol

Melting point (1.013 bar and 0 °C)

-56.57 °C

Solid density : 1562 kg/m3

Liquid density (-20 °C and 19.7 bar) :

1256.74 kg/m3

Triple point -56.56 °C , 5.187 bar


Report no. [2214090] of 52

Figure 1. CO2 phase diagram

2 SHIP TRANSPORT OF CO2

There are different options for ship transport of CO2:

Ships carrying liquefied CO2-

Ships carrying compressed CO2

Barge transport with either of the two

2.1 Refrigerated, liquid CO2 transport

CO2 can be transported under pressure as a refrigerated liquid. Liquid CO2 has virtu-ally the same properties as water, and can therefore be pumped during loading and unloading. It is a low viscosity colourless fluid, with density about 1.1 t / m 3, depend-ing on the temperature. At the triple point, liquid CO2 converts to dry ice. CO2 is routinely shipped for commercial use (food and beverage, cleaning, chemical, fire extinguishers etc.) today. For these relatively small quantity applications CO2 is transported in liquid form with a pressure between 15-18 bar and approx. -22 to -28 ºC. For the much larger quantities of full scale CCS transport it will effectively have to be transported near the triple point, i.e. at 7- 8 bara and -50ºC. Depending on the temperature and the amount of CO2 there will be a rise in pressure


Report no. [2214090] of 52

of 0.1 to 0.2 bar / day on board due to thermal leakage. Equipment for decompress-ing on board is not required for realistic transport distances.

2.2 Compressed CO2 transport

Ship transport with compressed CO2 can be compared with transport of CO2 in pipe-lines. Transport conditions will therefore be similar to pipeline, but with more flexibility and easier to inspect than offshore pipelines. The temperature will be about 25 °C, and the pressure needs be above 75 bar to reduce the risk for two phase flow. The concept of compressed CO2 on ships was developed by Knutsen OAS Shipping, but remains unproven and there are no international regulations for such transportation of CO2.

2.3 Barge transport

Barge transport is likely to be utilized in rivers and channels, but could also be suit-able in some cases in open sea. Barges have been used to transport liquefied gases for many decades in Europe. A lot of barges are in operation today, but not for CO2 transport. Barge transport may in some cases provide cost and regulatory advan-tages but is on the other hand so far not considered to be a practical solution in case of offshore discharge of CO2.

For the base case scenario described in section 9, refrigerated, liquefied CO2 is most

feasible transport option. This is due to large volumes, long distances and weather

conditions in the North Sea.

3 SHIP TRANSPORT COMPARED WITH PIPELINES

The most proven alternative to ship transport is pipeline. Both transportation methods have advantages and disadvantages. Pipeline transport has been considered to be the method of choice when it comes to transport of large amount of CO2. This is be-cause both on- and offshore transport is possible, there are few additional installa-tions needed (mainly a compression facility) and it has a low operational cost. On the other hand the investment cost is high and will in most cases be a sunk cost (few possibilities for re-use), difficult to access for maintenance and limited capacity in-crease potential. In a well-established large scale CCS network with predictable CO2 flows and storage site(s). Pipelines are likely to be the best option unless the dis-tance is very large. In a more uncertain setting, which we currently have in regard to the future development of CCS, ship transport seems to be an attractive choice. This is because of the relatively low investment cost, flexibility in CO2 volume and route, the reuse potential of the ship as well as relatively short lead time. The disadvan-tages associated with ship transport are the high operational cost and the additional onshore facilities needed (liquefaction and onshore storage).


Report no. [2214090] of 52

Table 2. Pipeline vs ship transport

Pipelines Ships

+ - + -

Low

OPEX

High CAPEX Low

CAPEX

High OPEX

Onshore

needs:

Com-

pression

Relatively

low flexibility

Large

flexibility

(volume and route)

Onshore need for

intermediate stor-

age and liquefac-

tion plants

Can be

built both

onshore

and off-

shore

Low poten-

tial for re-

use

Potential

for reuse of

ships for

petroleum

gases as

well as al-

ternative

CO2 pro-

jects

Large sunk

cost

High

maintenance

costs

Lower sunk

cost

Booster sta-

tions?

Short de-

livery time

(2 years?)

capacity

available

for growing

Using ships for transportation of CO2 in Norwegian waters can be advantageous for several reasons:

Cold cooling water available for liquefaction process

CO2 sources located close to sea/at the seaboard

Oil and gas activity for decades

Maritime tradition

Experienced commercial CO2 companies


Report no. [2214090] of 52

4 SHORT DESCRIPTION OF SHIP TRANSPORT STATUS

Ships are only one element of the total transport chain. In addition, several elements need to be included, from liquefaction to unloading equipment. Some of these ele-ments have been used for decades, but some are not proven and are only suggested in literature. The table gives an overview of the different elements of the transportation chain and their supposed technological maturity.

4.1 Maturity of each element

Table 3. Status ship transport elements.

Element Maturity Reference list

Liquefaction Proven for other pres-sure/temp

17,18, 35

Storage tanks-steel Proven 9, 29

Storage tanks – new materi-als

Some literature, rock storage is proven , but not for CO2

7

Storage tanks- mobile tanks on barges

Some literature 22, 40

Loading equipment: Loading arms, flexible hoses etc.

Proven for CO2 Yara’s experience

Refrigerated CO2 ship trans-port

Proven for LPG and ethylene at down to -

104 ˚C CO2 ship (-50 ˚C, 8 bar only in stud-ies)

IM Skaugen, Maersk, Tee-kay

Ship transport of compressed CO2

Few studies Knutsen OAS

Utilizing the cold Very few studies

Unloading arm – to storage tank or ship

Proven for other pres-sure/temp

Yara’s experience

Unloading buoy- to injection Proven for oil/ NG 20, 33, 34


Report no. [2214090] of 52

Heating before injection Literature/studies 22, 38

CO2-EOR Studies, proven for on-shore oilfields

31, 36, 37, 42, 43

4.2 Safety

Safety is an important issue regarding CO2 transport. Large ships with comparable gases are in daily use, although there are differences as compared to CO2. One im-portant difference is that CO2 is non-flammable/non-explosive and forms a solid (dry ice) if depressurized. The table below compares CO2 to LNG and LPG. Table 4. Hazard og gases

Source: The UK P&I Club, 2005

DNV has conducted a detailed study in which they reviewed the security aspects and consequences of adverse events associated with the entire chain in CO2 transport [40].

Hazard LNG LPG /LNH3 Liquefied CO2

Toxic No No No

Carcinogenic No No No

Asphyxiant Yes (in confined

spaces)

Yes (in confined

spaces)

Yes (in confined

spaces)

Others Low temperature (-160

Deg C)

Moderately low

temperature (-

50Deg C)

Moderately low

temperature (-50Deg C)

Flammability Limits in

Air (%) 5-15 2-10

Non-flammable

Storage Pressure Atmospheric Often pressurised Pressurised

Behaviour if spilt Evaporates forming a

visible ‘cloud’ that

disperses readily and is

non-explosive, unless

contained

Evaporates

forming an

explosive vapour

cloud

Solidifies to ‘dry ice’ (if

no sufficient heat

around) and then

sublimates as

surrounding

temperature increases


Report no. [2214090] of 52

4.3 Storage tanks and liquefaction plant

The intermediate storage tanks must store the cold CO2 before ship transport. These tanks may be produced in carbon steel or stainless steel, and is normally spheri-cal/cylindrical tanks.

The size of the storage tanks is calculated from the production rate of CO2, pressure and tempera-

ture of CO2, the size of the ships and how often the ships loads / unloads CO2. The wall thickness, and thereby weight of the cylindrical tanks, is proportional to the diameter and the internal overpres-

sure. In some reports, it is assumed storage tank size of 1.5 times the vessel capacity. This has been

done to account for unexpected events with the ship. In the case present in this report, the spherical tanks are equal the size of the ship and are assumed build in carbon steel, ref attachment 4. This is done to reduce the costs, and if the ship cannot collect the CO2, the capture plant will stop.

The figure below shows how the cost level for carbon steel and stainless steel tanks varies with different sizes. The cost data has been calculated with Aspen In plant cost estimator.

Figure 2. Carbon Steel and Stainless Steel tanks

The liquefaction plant consists of several different cost elements. An example of the results of cost estimation for a liquefaction plant is shown in the table 5. The largest cost driver is the equipment including the assembly and piping.

0

2

4

6

8

10

12

14

16

0 2000 4000 6000 8000 10000 12000

kNO

K/m

3

Size m3

Unit cost - kNOK/m3

ss

cs


Report no. [2214090] of 52

Table 5. Detail cost for a liquefaction plant

.

Cost estimate

IBL

Equipment

IBL Bulk

materiel

IBL Hour

Cost OBL Sum

kNOK kNOK kNOK kNOK kNOK

Equipment costs 24 294 0 0 0 24 294

Erection cost 0 2 160 0 2 160

Piping incl. Erection 4 784 5 467 0 10 251

Electro (equip & erection) 3 013 3 443 0 6 456

Instrument (equip. & erection) 2 551 4 374 0 6 925

Ground work 782 2 085 0 2 867

Steel & concrete 3 059 3 496 0 6 554

Insulation 681 778 0 1 459

Direct costs 24 294 14 870 21 803 0 60 967

Engineering process 1 709 0 1 709

Engineering mechanical 766 0 766

Engineering piping 3 157 0 3 157

Engineering el. 1 696 0 1 696

Engineering instr. 2 143 0 2 143

Engineering ground 445 0 445

Engineering steel & concrete 1 025 0 1 025

Engineering insulation 232 0 232

Engineering 11 174 0 11 174

Procurement 589 0 589

Project control 615 0 615

Site management 3 661 0 3 661

Project management 3 392 0 3 392

Administration 8 256 0 8 256

Commissioning 1 270 0 1 270

Identified costs 81 667 0 81 667

Contingency 16 333 0 16 333

Total costs 2010 98 000 0 98 000

Escalation to start construction 0 0 0

Escalation during construction 0 0 0

Inetrest during Construction 0 0 0

Total costs incl. Escalation & intrest 0 0 98 000


Report no. [2214090] of 52

5 INJECTION

5.1 Introduction

Apart from the economic constraints of expensive, large diameter and often submerged pipelines, there are technical restrictions on the injection rates and injection conditions. These requirements on the injection stem from limitations set by for instance: - Thermal or hydraulic cracking in the reservoir due to the large influx of cold CO2. - Integrity of the tubing, casing and cement linked to large pressure and temperature

gradients along the well. - The possibility of CO2 hydrates forming in the near wellbore area, due to the

presence of water from the reservoir. - Water or even dry ice formation at low temperatures. - Noise, pulsation and vibration induced by high flow velocities. In case of shipping, there are additional issues due to the low (storage) temperatures which requires additional heating and pumping and due to generally strict require-ments on offloading times. Injection rates are limited by thermal gradients (cooling and heating of tubing, casing and cement), erosion limits and vibration limits. All these restrictions render the operation of transport and injection lines complex and a case to case analysis will be required. Cyclic conditions are very important and are one factor which must be analyzed. However, according to ship transport, the number of cycles is not that large so it is not really any high cycle fatigue or so which is the problem (but indeed it can be). For the temperature, the gradients in the length direction and in radial direction are im-portant (gradients in tubing, casing, cement and rock layers). But as no information is available on this at this stage it has not been calculated. The minimum and maximum temperatures are important for material specifications and perhaps also for hydrate problems, as the pressure requirement is dependent on the injection temperature. These results are further described in appendix 3. Here, a short initial evaluation of injection at the Johansen aquifer field is given, while a detailed model discussion and simulation results are presented in appendix 3.

5.2 Johansen injection case

The site considered is a 3050m deep saline aquifer at a reservoir pressure of 350 bar(a). A series of simulations were performed to evaluate potential issues at offloading (see results in appendix 3). These simulations were performed to scan for potential is-sues. As the simulations were performed in general terms only, it is recommended to update the used models if more details are available.


Report no. [2214090] of 52

The simulations focused on: - Shut-in simulation to determine close-in wellhead condition at varying res-

ervoir pressures. This is important as at lower wellhead pressures, two-phase conditions

might occur. This increases the complexity of start-up and shut-in. At start-

up potentially large pressure drops might occur across the wellhead choke

resulting in low temperatures. At shut-in, gas is formed which can expand,

again potentially resulting in low temperatures.

- Steady state injection cases with a variation in mass flow rate and injection temperature. The steady state simulations give a temperature profile along the well and

the required injection pressures. Furthermore, the velocities are calculated

in the complete well. At high velocities, vibration and erosion issues might

become critical.

- Injection cycle of a start-stop scenario. The injection cycle was simulated to evaluate the issues related to pressure

drops across the choke at start-up and shut-in. Furthermore, actual required

injection pressures and temperatures were evaluated. The main results are

the mass flow rates during injection and the resulting flow velocities.

From the simulations, the following can be concluded:

- At shut-in conditions, the wellhead is at a typical pressure of 106 bar. This means that the complete well is at single-phase conditions. At the start of injection, the ship offloading pumps must generate at least this pressure. At these high close-in wellhead pressures, no issues related to large tem-perature drop will occur.

- At a nominal offloading rate of 111 kg/s (based on an offloading time of 36 hrs) the required injection pressure is approximately 170 bar. If the injection time is halved, the required injection pressure increases to above 300 bar. This will increase costs of pumps, hoses, offloading buoys etc. The base case (36 hrs offloading) results in velocities in the well of ap-proximately 6 m/s. This is in general a maximum allowed flow rate from the point of view of vibrations and erosion. This might be increased if the well layout is known and potential particle concentrations are known. As a gen-eral rule, 6 m/s is a maximum. This means either that more injection wells will be required, or the offloading rate is limited to 36 hrs.

- At an offloading rate of 36 hrs, at normal start- stop scenarios no extremely large gradients or velocities are observed which confirm that at nominal conditions, injection would be a viable solution.

5.3 Conclusions

For the Johansen case, at injection rates as proposed, no extreme injection pres-sures or temperatures are required. A start-stop interval of 36hrs would also limit ve-


Report no. [2214090] of 52

locities in the well. A shorter injection times, the velocities and pressures would in-crease and will put design constraints on pumps, piping, buoys and the well comple-tion. The analysis seems to indicate that intermittent injection at high pressure and with a temperature in the range of 0-10 ⁰C is feasible. It is however clear that this subject will need further static as well as dynamic analysis and evaluation.

6 IDENTIFIED GAPS

Gaps have been analysed by evaluating both the level of cost of each item, as well as the planning uncertainty and risk involved in the item. Gaps impacting the feasibil-ity of ship transport should have the highest priority. Thereafter, gaps related to high cost elements should be considered, as well as other gaps which, if solved, would improve performance of the ship transportation chain. We have thus given the de-scribed gaps a suggested priority from 1 to 3. In order to group the identified gaps in an orderly way, they are discussed in terms of appearance throughout the chain. It should be noted, that cost reductions can with advantage be studied as a whole, considering the total chain and not part by part.

6.1 Gaps related to preparation for ship transport

Need for pre-treatment of captured CO2 from sources A and B: Both selected CO2 sources may present challenges with regard to purity of the cap-tured CO2. Purity is again a function of capture technology. A specification of CO2

quality requirements for critical parts of the total transport chain which can be com-pared to the expected composition of captured CO2 produced by relevant capture technologies will form a basis for defining the eventual importance of this gap. Critical parts of the chain may be material requirements in ships and storage tanks or in the injection well, or restrictions on impurities set by the reservoir into which the CO2 will be injected. Priority: 3. Buffer storage: It has been generally accepted that buffer storage at the source in the form of tanks should be 50% larger than the ship size. The premises for this assertion can be questioned, and should be examined. Barges can be an alternative to onshore stor-age tanks. This is mainly a cost item, priority 2.

6.2 Gaps related to ships

Ship cost: The ship CAPEX and OPEX constitutes on the order of half of the total transport cost. Cost data need updating and checking with the appropriate sources. Since this analysis is site specific, there will be an opportunity to obtain better cost data than has been the case for many previous studies which were not site-specific. Priority 2


Report no. [2214090] of 52

Ship size: There are divergent opinions on what is an optimal and/or maximum/minimum size of a CO2 carrier that will deliver CO2 directly to an offshore installation. It is obviously a need to clarify why this is the case, and then try to resolve the divergence or suggest a way forward. This gap could be addressed in conjunction with the gap on ship cost. Priority 2. Ship type: Will new-built or existing ships (reconstructed) present the most optimal and cost-efficient choice? Different solutions have been presented and should be summarized and evaluated. Liquefied CO2 is the most obvious choice for transport, but even ships carrying compressed CO2 have been suggested. Use of barges may represent an-other alternative, not only as an alternative to a ship with tanks on board, but to fixed installations onshore. This gap could eventually also be addressed together with the two above mentioned gaps. Otherwise, priority 3. Logistics: What is the optimal logistic solution? This is probably just a small issue with only two sources located close to each other, and one delivery point, but should nevertheless be addressed. Priority 3. Energy: How much heat is available on the ship? Could heat from the sea be used for heating the cold CO2 before injection? The cold itself also represents energy. How to take care of "cold energy" from the vessel when unloading has not been given much at-tention, but may deserve proper evaluation. How to keep the pressure / temp in mind when returning ship after unloading? All these questions should be addressed and eventually dismissed. Priority 3.

6.3 Unloading related gaps

Energy: The interface between ship and unloading facilities includes partly the same chal-lenges as mentioned above. Priority 3. Unloading systems: There are different possible systems for offshore unloading, which should be re-viewed and evaluated with regard to technical and economic feasibility. Such sys-tems include buoy types including bottom hull buoys and even the possibility of using barges or FPSOs. Selection of materials as a consequence of pressure and temperature changes dur-ing discharge of cold CO2 should also be evaluated. Is it for instance possible to use mobile storage tanks, so the ships load the full tanks onto the installation instead of pumping the CO2 from the ship into a tank on the installation? Can be evaluated to-gether with the next gap. Priority 2. Unloading time and regularity:


Report no. [2214090] of 52

The choice of unloading buoy design and its costs in such a deep-water location as Johansen needs a thorough review. It is particularly important since cost will be di-rectly influenced by the unloading rate, intermittency and condition of the CO2. Fur-thermore, it will have direct influence on the regularity of the shipping operation. In the cost analysis regularity has been (hopefully conservatively) evaluated to be in the range of 80 to 90% for these fairly small ships. The Johansen site is however in a harsh weather area and the regularity warrants a proper statistical analysis as it will also influence the number of unintended, weather caused, thermal cycles in the well. Furthermore, there are some basic questions which should be answered: Batch in-jection as opposed to continuous injection should be considered carefully. Is it more cost efficient to reduce the time between injections and have more ships as com-pared to one ship with longer time between injections? Is regularity a well issue or is it just important for the injection? Or maybe regularity is not an important issue for a saline aquifer site as the Johansen formation. Priority 2.

6.4 Injection related gaps

This is the one area that is seen as involving what could be termed a technical uncer-tainty or gap. We are not aware of any study that effectively concludes what condition the CO2 can have at the wellhead during injection, or at what rate the CO2 can be injected and how many thermal cycles the well will accept. Condition rate and ther-mal cycles may be highly important for the performance and lifetime of the well as well as the reservoir. It is however additionally highly important because the choice of these parameters has a significant influence on the operation and cost of the ship(s) and the offloading buoy system. This gap also includes temperature and pressure control during injection and especially during emergency shutdown (ESD). The temperature at the buoy is low and there will be two-phase flow down the tubing to the well. This leads to issues regarding material choice and heating needs, for in-stance in the riser. What is the optimal pressure / temp for injection will sea water act as a large heat exchanger and how will CO2 behave in a flexible tube when it is full / empty? What type of material to be used in the riser? If an ice cap is formed on the tube during injection, what implications would it have on operations and safety? There is as a result a high priority demand for both static and dynamic analysis of flow, temperatures, pressures and resulting stresses and material requirements, in both the piping and well design. This analysis has to cover the piping system from the ships discharge pumps, through the buoy and its hose, as well as the sea-bottom pipeline and the well itself, and it ought to be performed for different assumed condi-tions and flow rates at the ship manifold. This gap is given Priority 1. We foresee that it will be feasible to equip and operate the ships in such a way that the injection requirements can be satisfied.


Report no. [2214090] of 52

7 OTHER POSSIBLE SOLUTIONS/INNOVATIONS

In addition to the identified gaps, there are possible new solutions/innovations that deserve further attention, having a potential to reduce costs and improve perform-ance of the CO2 ship transport chain. The use of floating barges to provide space for the liquefaction plant and storage tanks should be considered. Barges are flexible and can be reused on other sites or for other purposes. The feasibility of installing equipment on floating barges will be site dependent. For onshore sites with limited available area combined with restricted quay capacity this solution could be feasible. The barge would thus be suitable as a loading quay for the ship. We suggest the pros and cons of different barge designs both as alternative quay solutions, transport alternative as well as for offshore loading, are studied further. Liquefaction of CO2 is an energy intensive process and therefore costly. Possibilities of recovering and reusing this cold energy when the CO2 is heated again after trans-port should be investigated. This cold could be utilized for e.g. a freeze store and for LPG transport. Both of these utilization possibilities probably necessitates unloading from the CO2 ship to an onshore hub. A concept that to our knowledge so far has not been studied (or suggested?) is to construct a new type of storage tanks which can be used all the way through the transport chain. At the offshore end, such tanks can be submerged to the sea bed, and the CO2 can be heated up from -50 ˚C here before injection to the well. Storage tanks will act like a large heat exchanger with the sea water, and therefore extra heating on-board the ship can be reduced or removed. There are many potential challenges to such a concept and none of these have been investigated. On the other hand, if successful, such concept would probably also introduce possibilities for cost savings throughout the chain.

8 DESCRIPTION OF SCENARIO

The ship transport case involves two industrial sources in the Grenland area, South-ern Norway, each capturing 50 t CO2 /h, amounting to approximately 400 kt CO2 per year from each. The distance between the sources is 10 km. Both sources are lo-cated on the coast; however, source B is located further up the fjord. The capture plant is not considered in the study, but liquefaction of the captured CO2 is. CO2 from source B is transported by pipeline at 70 bar, both onshore and offshore is possible, to source A. At source A, the CO2 from both sources are liquefied at 7 bar and -50 °C, and loaded onto a ship for transport to permanent storage in a saline aq-uifer (the Johansen formation) located 670 km away. The number of dedicated ships depends on several factors which will be discussed later in this report. When the ship arrives at the offshore unloading buoy, the CO2 is conditioned for unloading on board before it is pumped into the saline aquifer. The unloading buoy (or the seabed below the buoy) is the cut-off point/battery limit of the cost estimation; however, the condi-


Report no. [2214090] of 52

tions in the saline aquifer and the depth will affect the conditioning needed before unloading.


Report no. [2214090] of 52

Figure 3. Scenerio description

a ture

a ture

i uefactio Stora e Shi tra s ort loadi to buoy

ectio to te late o seabed

Stora e

i eli e tra s ort

attery li it

50 t CO2/h

50 t CO2/h Up to 70 bar 10 km

pipeline + compression

-50⁰C, 7 bar 670 km

oadi

300 m below sea 3050 m below

sea, 90 ⁰C

attery li it


Report no. [2214090] of 52

9 COST ESTIMATION

The cost estimation can be executed in several different methods, but in this estimate the detail factor estimate method has been used. As a basis, the estimates in the “Zero emission platform” (ZEP) has been used as reference. The cost estimation has been executed by Nils Henrik Eldrup, which also did the cost estimation in ZEP re-port regarding CO2 transport. To verify data, cost estimation and ship data from Hans Richard Hansen has been included. The base case scenario has been given by Gassnova. Transport of CO2 differs in many ways from traditionally petroleum gas transport. The oil and gas companies have transported petroleum products for decades, and the cost and security of supply is generally high. There are several reasons for these dif-ferences:

Oil and Gas industry is a general high–cost industry where both investments

and operation is often more costly than for land based industry. This is due to

offshore handling, space limitation, very high safety regulations, security of

supply, etc.

LNG and LPG are saleable products, and CO2 is a «waste» This means that

the « value» of the gases is not comparable, and that will influence the needs

for back-up systems, delay costs ect.

Environmental issues: Petroleum products may have negative local impact if it

is released to sea, but CO2 is not a local problem, and if CO2 is to be realised

from a ship or a tank, it is not likely that it will lead to environmental damage.

CO2 is a global problem, and if it is realised after it has been captured, CO2

quotes must be bought. The quote price is not expensive now but this can

change in the years to come.

The cost input used in this report reflects cost levels in ship transport and land based industries, and is lower than the general cost level in oil and gas industry. We assumed that the liquefaction plant and loading facilities are placed in a non-ex area and access to labour and construction equipment are good. (Location factor near 1.0). The uncertainty of the cost estimates is assumed to be ± 50 % for the described scope.

9.1 Assumptions

It is several options for each element in the transport chain. In this table, the chosen solution is presented, and also possible alternative options that might influence the cost, but these options are not cost estimated in this report.


Report no. [2214090] of 52

Table 6. Option for key elements.

Transport chain element Chosen in the scenario estimate

Alternative options (not estimated)

Transport of CO2 from source B to Source A

• Compressed 70 bar and 20ºC, Small pressure pipeline onshore

• CO2 at actual pres-sure (gas), trans-ported in chan-nel/pipeline

Liquefaction plant

• Pressure relief of Compressed 70 bar and re-compressing flash gas (both sources has to compress the CO2

to dense phase)

• CO2 at actual pres-sure (gas), Cooled with an ammonia cooling circle

Intermediate storage • Steel pressure ves-sel. 7 bar and -50ºC.Vessels placed onshore (100 % of ship size)

• Caverns • Steel pressure ves-

sel. 7 bar and -50ºC.Vessels placed on barge (100% of ship size)

Loading

• Loading arm(s)

• Hoses

Ship

• 100 % utilization, max size ca 40 000 ton. EU crew. Posi-tioning system. 7 bar and -50ºC, with injection pumps and heating equipment.

• Onshore unloading. • International crew

Unloading

• Offshore unloading STL type

• Onshore unloading , onshore HUB with intermediate stor-age and preparation for injection, Pipe-line to storage site.

• Barge at the injec-tion site

• Buoy for extreme weather conditions


Report no. [2214090] of 52

Basic assumptions used in the cost estimates: Table 7. Cost data asumptions

Rate of return 7,50 %

Number of years 25

Cost of electricity (NOK/kWh)

0,4

Escalation from 2010 to 2014

6,70 %

Exchange rate NOK/EUR 8

Capacity (tonne CO2/year) Tonn CO2/an 800 000

Offshore unloading yes

Distance (km) km 670

Loading (hours) Hours 16

Discharge offshore (hours) Hours 40

Max ship size Tonne 40 000

Sailing hours pr year Hours/year 8 400

Ship speed knots nm/hours 14

Ship speed km/h Km/hours 26

Sailing time (one way) Hours 25,8

Total rountrip (hours) Hours 108

No of days Days 5

No of roundtrip pr years No. 70

Ship size m3 12 422

Ship size ton 14 285

No of ship No. 1

Ship size m3 13 300

Included

contingency

Transport B to A 20 %

Liguefaction 20 %

Storage 20 %

Loading 20 %

Ship 0 %

Pumping & Heating 20 %

Buoy 0 %

Pipeline & Wellhead 20 %

Well na


Report no. [2214090] of 52

9.2 First of a kind (FOAK) and Nth of a kind (NOAK)

It is always difficult to execute cost estimations for new industries, and that is due to the difference between mature technology, Nth-of-a-kind (NOAK), and initial first-of-kind (FOAK) estimates. To ensure that the facilities work, vendors will incorporate technical safety margins in FOAK beyond what is customary for mature technology. This is reflected in increased capacity in the different parts of the transport chain, expensive materials and heavy instrumented. This is done to ensure that the chain collectively satisfy requirements for capacity and regularity. The cost estimates for the first of a kind and Nth of a kind will differs, even if the same cost level is used. CAPEX is generally approx. 70 % higher for FOAK compared with NOAK, but in this case, loading equipment and ships are well known, and only 10 % has been added to the first ship of this kind. The dif-ference in OPEX is smaller.

9.3 Cost estimates


Report no. [2214090] of 52

Figure 4. Cost estimation with detail cost information for each element (Nth of a Kind)

CAPEX (kNOK) 119 500 CAPEX (kNOK) 62 700 CAPEX (kNOK) 78 000

OPEX (kNOK/an) 510,0 OPEX (kNOK/an) 19 200 OPEX (kNOK/an) 3 900

NOK/ton 14,2 NOK/ton 31,1 NOK/ton 13,8


OPEX (kNOK/an) 430 OPEX (kNOK/an) 62 200 OPEX (kNOK/an) 2 000


CAPEX (kNOK) 170 700 CAPEX (kNOK) 85 400 CAPEX (kNOK) -

OPEX (kNOK/an) 8 540 OPEX (kNOK/an) 4 270 OPEX (kNOK/an) -

NOK/ton 30,1 NOK/ton 15,1 NOK/ton -

NOAK ; nth of a kind

A 400 000 t/anB, 400 000t/an

Liquefaction 800 000 t/an Storage

Loading Ship (650 km) Pumping & Heating

Buoy Pipeline & Wellhead Well

Pipe transport

A 400 000 t/anB, 400 000t/an




Pipe transport (10 km)


Report no. [2214090] of 52

Figure 5. Cost estimation with detail cost information for each element (First of a Kind)


OPEX (kNOK/an) 561,0 OPEX (kNOK/an) 19 910 OPEX (kNOK/an) 4 790



OPEX (kNOK/an) 530 OPEX (kNOK/an) 62 200 OPEX (kNOK/an) 2 310


CAPEX (kNOK) 267 860 CAPEX (kNOK) 134 010 CAPEX (kNOK) -

OPEX (kNOK/an) 10 480 OPEX (kNOK/an) 5 240 OPEX (kNOK/an) -

NOK/ton 43,6 NOK/ton 21,8 NOK/ton -

A 400 000 t/anB, 400 000t/an




Pipe transport

A 400 000 t/anB, 400 000t/an




Pipe transport


Report no. [2214090] of 52

9.4 Cost results

Table 8. Cost estimation case results (Nth of a kind)

The table shows how CAPEX and OPEX influences the total cost per ton trans-ported. It is the ship and buoy that serves the highest capital cost, but the liquefaction plant influences also on the operational costs. Table 9. Cost estimation case results (First of a kind)

The ship costs are the main cost drivers in this estimation. This is influenced by the renting cost for ships, the crew (in this case operated by EU- crew, which is more expensive than international crew) and also the utilization on the ship

CAPEX OPEX

kNOK kNOK NOK/ton

Transport B to A 119 500 510 14,2

Liguefaction 62 700 19 200 31,1

Storage 78 000 3 900 13,8

Loading 8 500 430 1,5

Ship 388 200 62 200 121,9

Pumping & Heating 27 600 2 000 5,6

Buoy 170 700 8 540 30,1

Pipeline & Wellhead 85 400 4 270 15,1

Well - - -

Total 940 600 101 050 233,3

CAPEX OPEX

kNOK kNOK NOK/ton

Transport B to A 187 520 561 22,0

Liguefaction 98 390 19 910 36,1

Storage 122 400 4 790 19,9

Loading 13 340 530 2,2

Ship 427 000 62 200 126,3

Pumping & Heating 43 310 2 310 7,8

Buoy 267 860 10 480 43,6

Pipeline & Wellhead 134 010 5 240 21,8

Well - - -

Total 1 293 830 106 021 279,7


Report no. [2214090] of 52

Since the ship costs are so important, a couple of different alternatives have been estimated, see attachment 3. These alternatives shows Nth of a kind.These cost elements focuses on the ship, so liquefaction, buoy and intermediate storage is not included. Costs regarding ship (both CAPEX and OPEX) and port fee and heat-ing/compressing CO2 on-board are included. Attachment 3 gives an overview what is included or not in these alternative cost estimates. These alternatives show different sensitivities in ship transport. Changes in distance, injection conditions and volumes of CO2 influences the costs and affects the most suitable solution.

1. Cold CO2 injection

Fast (24h) discharge at 70 bar without any heating. If this is acceptable for in-

jection it is the preferred and cheapest alternative. It is however uncertain

doubtful that this CO2 condition is acceptable for the deep Johansen aquifer

2. Slow Discharge, heated onboard (Base case)

Slow discharge (36h) heated onboard using seawater plus onboard waste

heat. This condition is the same as it will be during injection from a transport

pipeline. There will however be much more frequent starts/stops with associ-

ated thermal cycling in the well. There is thus a need for significant further

analysis also for this case

3. Semi-continuous discharge using two ships

This alternative uses two ships allowing only a break in injection to exchange

ships at the buoy. To what extent this could solve any thermal cycling issues in

the well requires further analysis.

4. Longer distance transport

The longer distance (600nm corresponding to Rotterdam-Johansen) has been

included to allow an estimation of cost sensitivity to distance.

5. Long distance and full scale quantities

This alternative provides sensitivity to larger (5million mt/y) quantities as would

be relevant for full scale projects.

A summary of the transport cost per ton are shown in the following table: Table 10. Cost estimation “ship transport” results

Alternative Transport cost (NOK/ton injected)

1. Cold CO2 injection 104

2. Heated onboard (base case) 119

3. Semi-continuous discharge 187

4. Long Distance 134

5. Long Distance and Large

Volume

86


Report no. [2214090] of 52

The conclusions to be drawn from this table are mainly: If heating onboard is required it will increase transport cost with more than 10%

If additionally semi-continuous discharge should be required, it will increase transport

cost by a further more than 50%, however some of this will be saved by a reduction in

size of the loading buffer storage.

Sensitivity to distance is limited in that a 100 % increase in distance will increase

costs by only about 15%

Sensitivity to volume is significant up to a volume of about 2.5 Mill mt/y (= max ship

size) with a cost reduction of almost 60% for a 2.5 times increase in volume

The main cost contributor to the liquefaction cost is the cost of electricity. The el price is assumed to be 0,4 NOK/KWh, and the total energy demand is 950 KW pr year Offloading equipment is utilized partly, and if CO2 from other sources could be added to the well, the utilization of the buoy and injection pipeline will improve and the share of cost will decrease.

10 RESULTS/CONCLUSION

It has been a general understanding that CO2 transport is a relatively speaking straight forward part of the CCS chain and that few, significant l gaps exist. The pre-sent study of ship transport does however, point out that there is a significant uncer-tainty related to the required condition of the CO2 during ship unloading. Before this is more clearly settled there will be a significant uncertainty in the estimation of the costs of a CCS ship transport chain. The project has uncovered gaps in other parts of the chain from preparation for transport, via loading, shipping and unloading, to injec-tion. Only gaps related to the injection of CO2, however, are of such a character that the feasibility of ship transportation is questioned. For the studied case a way forward with the aim to closing these gaps is suggested. When the most significant gaps are closed, the studied scenario is likely to be feasible, but should also be compared to alternative cases. The largest cost elements are the ship itself and the liquefaction. Operational cost (energy, crew) constitutes the most significant part of total cost. The project also points to barges as an alternative to fixed onshore installations. Likewise, the cold may in itself represent a possibility for energy saving if it can somehow be re-used. Both these ideas should be investigated further. Compared to pipeline transportation, ships/vessels have advantages when distances increase and volumes are not too high. Ships also constitute a way to start CO2 transportation at an earlier stage as compared to pipelines because of their flexibility and relatively low up-front investment cost.


Report no. [2214090] of 52

The Johansen formation has no platforms today. The case is developed supposing a subsea template with injection well and offshore unloading of CO2. If delivery to an existing platform is an alternative, we suppose no major changes of the conclusions. However, this will depend on several factors which are partly site dependent, such as whether the platform would be operating or abandoned.

11 SUGGESTION FOR FURTHER WORK

To mature CO2 ship transport solutions the identified gaps/focus areas should be sys-tematically investigated with the aim to close the gaps. One possible plan for further work could be to deal with the four main parts of the ship transportation chain as separate projects, to be run serially or in maybe partly in parallel to each other. Thus there could be four projects:

1. Gaps related to preparation for ship transport

2. Gaps related to ships

3. Unloading related gaps

4. Injection related gaps (Highest priority, to be addressed first)

The recommended way forward however, would be to address the cost related gaps as a whole, after first addressing the injection related gaps. The cost related gaps have strong interconnections, and therefore they should not be addressed independ-ent of each other. The lowest priority gaps could then be reassessed, and closed af-ter new evaluation. The other possible solutions/innovations mentioned in this report, can be subject to new R&D projects, possibly under CLIMIT. The gaps identified in this project are related to ship transportation to a saline aquifer. If CO2 is going to be shipped to other reservoir types, like an oil field for EOR pur-poses, or even an abandoned natural gas field, additional gaps/challenges will occur which are not mentioned here. Such cases will therefore require new analyses in or-der to identify which gaps are critical, even though some gaps will be identical to the ones described in this study. Ships calling at an onshore hub with a pipeline connection to storage site(s) instead of at an offshore installation may represent advantages as to long term cost. Analys-ing onshore hubs was outside the scope of this project, but could be subject to a separate future study. Likewise, delivery to an existing platform instead of a buoy/template, may present challenges or opportunities that are not mentioned in this study.


Report no. [2214090] of 52

12 ACKNOWLEDGEMENTS

The authors will like to thank Gassnova and Per Arne Nilsson of Panaware for con-tributing to fruitful discussions and for input to the work.

Attachments:

1 References /literature overview

2 Ship Transport Cost data sheet from Hans Richard Hansen

3 Injection simulation model and results


Report no. [2214090] of 52

ATTACHMENT 1 REFERENCES /LITTERATURE

Table 1. List of literature and references.

Number

Title Year Authors Organiza-tion

Type Note

1 CO2-håndtering kondensering, mellomlagring og transport

2004 Georg Heger-land John Pande

Project In-vest

Article CC chain

2 Ship transport of CO2

2004 IEA IEA Report PH4/30

CCS chain

3 IPCC Special Report on Carbon dioxide Capture and Storage-chapter 4

2005 Bert Metz, Ogunlade Davidson, Heleen de Con-inck, Manuela Loos and Leo Meyer (Eds.)

Cambridge University Press/IPCC

Rap-port

Ship and pipe-line

4 OFFSHORE UNLOADING OF SEMI-PRESSURIZED CO2 TO AN OILFIELD

2005 A. Aspelund1*, T. Weydahl1, T.E. Sandvik2, H. Krogstad2, L.R. Wongra-ven2, Roar Henningsen2 Jan Fivelstad2, Narve Oma3, and Tor Hilden3

SINTEF, VIGOR ,STATOIL

Article GHGT

Offhore unload-ing

5 SHIP TRANSPORT OF CO2 Technical So-lutions and Analysis of Costs, Energy Utilization, Exergy Effi-ciency and CO2 Emis-sions

2006 A. ASPELUND, M. J. MØLNVIK og G. DE KOEIJER2

SINTEF Energy Re-search, Trondheim, Norway STATOIL, Stavanger, Norway

Article Costs and en-ergy use in the CCS chain

6 SHIP-BASED TRANSPORT OF CO2

2006 M. Barrio, A. Aspelund, T. Weydahl, T.E. Sandvik, L.R. Wongraven, H. Krogstad, R. Henningsen, M. Mølnvik, S.I. Eide

Sintef Statoil

Article GHGT

Costs and en-ergy use in the CCS chain


Report no. [2214090] of 52

7 Transportation Infrastructure for CCS – Experiences and Expected Development

2006 Richard Svendsson, Michael ODen-berger, Fillip Johnson, Lars Strømberg

Chalmers og Vatten-fall

Article GHGT

8 Life Cycle As-sessment of Selected Technologies for CO2 Transport and Sequestration

2007 Caroline Wild-bos

Swiss Fed-eral Institute of Technol-ogy Zurich

Student theses

9 Liquefaction of captured CO2 for ship -based transport

2007 A. Aspelund, T.E. Sandvik, H. Krogstad, G. De Koeijer

SINTEF Report

10 Ship transpor-tation of CO2 as an enabler of CCS projects

2008 Hans Richard Hansen

Teekey Presen-tation CCS work-shop

11 Options for transporting CO2 from coal fired power plants Case Den-mark.

2009 Haugen H.A., Eldrup N., Bernstone C., Liljemark S., Pettersson H., Noer M., Hol-land J., Nilsson P.A., Hegerland G., Pande J.O

Tel-Tek, PI , Vattenfall

Article GHGT

12 The Liquefied Energy Chain

2009 Audun ASpe-lund Truls Gunder-sen

NTNU Artikkel GHGT

Ship transport

13 Impurities in Carbon Diox-ide Capture and Transport

2009 Magnus Eriks-son

NTNU Master theses

Inpurities

14 Mulighetsstu-die infrastruk-tur for CO2 rik naturgass fra nye felt i nors-kehavet

2010 Petter Røkke og Audun Aspelund

Sintef en-ergi AS

Report LNG and CO2

15 CO2 transport from sources to storage in the Skager-rak/Kattegat region

2010 Anette Mathisen Ragnhild Ska-gestad Nils Eldrup Hans Aksel Haugen

Tel-Tek Article GHGT

Ship and pipe-line

16 Towards a 2010 Konsortsium CO2 Ship and pipe-

http://www.sciencedirect.com/science/article/pii/B9780080447049503700




Report no. [2214090] of 52

transport infra-structure for large-scale CCS in Europe

Europipe line

17 CCS from mul-tiple sources to offshore stor-age site com-plex via ship trans-port

2010 Masahiko Ozakia, Takashi Ohsumib, 1

The Univer-sity of To-kyo bCentral Research Institute of Electric Power In-dustry, 1646 Abiko, Abiko 270-1194, Ja-pan

Article GHGT

18 New CCS sys-tem integration with CO2 car-rier and lique-faction process

2010 Byeong-Yong Yooa, Sung-Geun Leea, Key-pyo Rheeb, Hee-Seung Naa, Ju-Mi Parka, a

DAEWOO SHIPBUILDING & MARINE ENGINEERING CO.,LTD, 85, Da-Dong, Jung-gu, Seoul, 100-180, Korea b Seoul National Universtiy, San 56-1, Sillim-Dong, Gwanak-Gu, Seoul,151-744, Korea

Article GHGT

Ships and lique-faction

19 Maersk Tank-ers – a pioneer in CO2 ship-ping

2011 An-ders.Bradt.Schulze

Maersk Feature Articles , 2010 (Car-bon Cap-ture Jour-nal)

Ship transport

20 CO2 maritime transportation

2010 Decarre, S. Berthiaud, J. Butin, N. Guil-laume-Combecave, J. L

IFP et al.. Article IGGC

21 DNV CO2 2011 Sven-Erik Bør- DNV Short


Report no. [2214090] of 52

SHIPPING PAPER

resen article

22 Safety study for Liquid Logis-tics Shipping Concept

2011 Peter Koers Maarten de Looij

DNV Report Safety ship transport

23 Development of CO2 lique-faction cycles for CO2 se-questration

2011 Abdul-lah Alabdulkarem, Yunho Hwang Reinhard Radermacher

Center for Environ-mental En-ergy Engi-neering, Department of Mechani-cal Engi-neering, University of Mary-land,USA

Liquefaction

24 The cost of CO2 transport

2011 ZEP-konsortsium

ZEP Report CO2 transport

25 Den maritime næringens tilnærminger til design av CO2-skip

2011 Gaute Lås-negård

Høgskolen Stord/Haugesund nau-tisk utdan-ning

Student work

Ship , combined ship

26 Transport of dense phase CO2 in C-steel pipelines – when is corro-sion an issue?

2011 Arne Dugstad Bjørn Morland Sigmund Clau-sen

IFE Gassco

Article CO2 impurities

27 Transport av CO2 status

2011 Skagestad, Eldrup

Tel-Tek Report CO2 transport

28 Transport & storage eco-nomics of CCS networks in the Netherlands

2013 Rotterdam cli-mate initiative

GCCSI Report CO2 transport

29 Cargo condi-tions of CO2 in shuttle trans-port by ship

2013 Noriyuki Kokub-una, Kiyohiko Kob, Masahiko Ozaki

Chiyoda Corpora-tion, Sa-sebo Heavy Industries Co., The University of Tokyo,

Article Energy Proce-dia

Injection, stor-age tanks

30 Benchmarking of CO2 trans-port technolo-gies: Part II – Offshorepipe-line and ship-ping to an off-

2014 Simon Roussa-naly, Amy L. Brunsvold, Erik S. Hognes

SINTEF Article Transport


Report no. [2214090] of 52

shore

31 CO2-EOR off-shore resource

2014 Taylor Malone Vello Kuuskraa, Phil DiPietro

ESPA DOE NETL

Report Internation CO2-EOR combina-tion

32 Ship-based Offshore CCS Featuring CO2 Shuttle Ships Equipped with Injection Facili-ties

2013 Masahiko Ozaki, Takashi Oh-sumi, Ryuichiro Kajiyama

Central Re-search Insti-tute of Elec-tric Power Indus-try,Chiyoda Corpora-tion, The University of Tokyo,


Direct injection from ship

33 Offshore Op-erational Availability of Onboard Di-rect Injection of CO2 into Sub-seabed Geological Formations

2013 Tsuyoshi Miya-zaki, Hiroyuki Osawa, Masami Matsu-ura,Makoto Ohta, Masahiko Ozaki

Japan Agency for Marine-Earth Sci-ence and Technology, Mitsubishi Heavy In-dustries, The Univer-sity of To-kyo,


Injection

34 Ship-based CO2 Injection into Subsea-bed Geological Formations using a Flexi-ble Riser Pipe Pickup System

2013 Naoki Naka-zawa,Kyozo Kikuchi,Ken-ichi Ishii,Takumi Yamaguchi, Makoto Ohta, Masahiko Ozaki

Systems Engineering Associates, SEMTEC, Furukawa Electric Co., Mitsubishi Heavy In-dustries, The Univer-sity of To-kyo,


Injection

35 Efficiency En-hancement for Natural Gas Liquefaction with CO2 Cap-ture and Se-questration through Cycles Innovation and Process Opti-mization

2014 Abdullah Alab-dulkarem

University of Mary-land, Col-lege Park, CEEE

PhD study

Liquefaction

36 A CO2-Infrastructure for EOR in the North Sea (CENS): Mac-

2002 P. Markussen, J. Michael Austell, Carl-W. Hustad,

Elsam AS, Denmark INCO2 ApS, Den-mark

Report Cost challenges for EOR from 2002


Report no. [2214090] of 52

roeconomic Implications for Host Countries

CO2-Norway AS, Norway

37 Opportunities for CO2 Stor-age around Scot-land

2009 Anne Glover, University of Edin-burgh, Scot-tish Centre for Carbon Storage

Report EOR

38 Preliminary Feasibility Study on CO2 Carrier for Ship-based CCS

2011 A. Omata, R. Kajiyama

Global Car-bon Cap-ture and Storage Institute Ltd

Report CO2 carrier, transport

39 , CO2 capture and storage in Rotterdam

2011 City Center and Public Spaces

A Net-work Ap-proach

CCS chain

40 Safety study for Liquid Lo-gistics Ship-ping Concept

2011 Solutions BeNeLux

DET NORSKE VERITAS BV

Report Cryogenic transport TRANSPORT OF CO2 BY BARGE

41 CO2 Capture & Storage

2010 IEA ETSAP Tech-nology Brief E14

CCS Chain

42 CO2 Utilization from “Next Generation” CO2 Enhanced Oil Recovery Technology

2013 V. A. Kuuskra, M.L. Godec, P.Dipietro

Advanced Resources Interna-tional, U.S. De-partment of Energy,

Article CO2-EOR

43 CO2 storage atlas-Norwegian Continental shelf

2014 NPD Report CO2-EOR


Report no. [2214090] of 52

ATTACHMENT 2 SHIP TRANSPORT COST DATA SHEET FROM HANS RICHARD HANSEN


Report no. [2214090] of 52

SHIP COSTSShip Transport Costs Alternative 1 Alternative 2 Alternative 3 Alternative 4 Alternative 5

Cold CO2 Heated on Board Two ships Long Distance Large Volume

Distance 362 nm Distance 362 nm Distance 362 nm Distance 600 nm Distance 600 nm

Discharge location Offshore, STL Offshore, STL Offshore, STL Offshore, STL Offshore, STL

Discharge type Fast liquid 20 bar Slow, warm, 140 bar As Alt 2 As Alt 2 As Alt 2

CO2 production

CO2 peak production [ton/day] 2 857 2 857 2 857 2 857 14 286

Plant capacity [ton/year] 1 000 000 1 000 000 1 000 000 1 000 000 5 000 000

Plant capacity [m3/year] 869 565 869 565 869 565 869 565 4 347 826

Plant utilization rate 85 % 85 % 80 % 85 % 90 %

Annual CO2 weight [ton/year] 850 000 850 000 800 000 850 000 4 500 000

Annual CO2 volume [m3/year] 739 130 739 130 695 652 739 130 3 913 043

Sailing input

Total sailing distance [nm] 362 362 362 600 600

Total sailing distance [km] 670 670 670 1 110 1 110

Ship speed in water [knots] 14 14 14 14 15

Discharge pressure [bar] 70 140 140 140 140

Ship size factor 1,07 1,07 1,07 1,07 1,07

Conversion rate [EUR/USD] 0,74 0,74 0,74 0,74 0,74

Fuel price per ton [USD] 750 750 750 750 750

Fuel price per ton [EUR] 555,00 555,00 555,00 555,00 555,00

Roundtrip calculation

Transit time one way [hrs] 25,9 25,9 25,9 42,9 40,0

Loading time [hrs] 12 12 12 12 12

Port maneuvering per roundtrip [hrs] 4 4 4 4 6

DP offshore [hrs] 4 4 4 4 4

Discharge[hrs] 24 36 44 36 36

Roundtrip [days] 4 5 5 6 6

Spare time per roundtrip [days] 0,01 0,51 0,18 0,10 0,25

Ship size calculation

Operating days per year 350 350 350 350 350

Roundtrips per ship per year 88 70 70 58 58

Max ship size [m3] 40 000 40 000 10 000 40 000 40 000

Required ship capacity [m3] 9 938 12 422 12 422 14 907 74 534

compared with max ship size 0,25 0,31 1,24 0,37 1,86

Number of ships 1 1 2 1 2

Required ship size [m3] 9 938 12 422 6 211 14 907 37 267

Actual ship size [m3] 10 700 13 300 6 700 16 000 39 900

Roundtrip description

Loading [hrs] 12,0 12,0 12,0 12,0 12,0

Port maneuvering per roundtrip [hrs] 4,0 4,0 4,0 4,0 6,0

DP offshore [hrs] 4,0 4,0 4,0 4,0 4,0

Discharge [hrs] 24,0 36,0 44,0 36,0 36,0

Sea transit [hrs] 51,7 51,7 51,7 85,7 80,0

Idle [hrs] 0,3 12,3 4,3 2,3 6,0

Fuel consumption

Fuel consumption - per ship per day

Loading [ton/day] 2,50 2,50 2,50 2,50 3,50

Port maneuvering per roundtrip [ton/day] 5,22 6,03 3,82 6,82 15,43

DP offshore [ton/day] 6,89 7,96 5,04 9,00 0,00

Discharge/pumping offshore [ton/day] 11,49 28,56 14,39 34,36 85,69

Sea transit [ton/day] 20,87 24,12 15,27 27,29 61,72

Idle [ton/day] 2,50 2,50 2,50 2,50 3,50

Fuel consumption - per roundtrip per ship

Loading [ton] 1,3 1,3 1,3 1,3 1,8

Port maneuvering per roundtrip [ton] 0,9 1,0 0,6 1,1 3,9

DP offshore [ton] 1,1 1,3 0,8 1,5 -

Discharge [ton] 11,5 42,8 26,4 51,5 128,5

Sea transit [ton] 45,0 52,0 32,9 97,4 205,7

Idle [ton] 0,0 1,3 0,4 0,2 0,9

Total Bunker Consumption Roundtrip [ton] 59,8 99,7 62,5 153,1 340,7

Total Bunker Price Per Round Trip [EUR] 33 170 55 338 34 673 84 982 189 115

Annual bunker cost total fleet [EUR] 2 902 387 3 873 645 4 854 200 4 957 265 22 063 449

Port fees

Total port fee per roundtrip [EUR] 7 133 8 867 4 467 10 667 26 600

Annual port fee, total fleet [EUR] 624 167 620 667 625 333 622 222 3 103 333

Capex

Ship cost per standard 10000m3 ship [USD] 36 000 000 36 000 000 36 000 000 36 000 000 36 000 000

Ship cost actual size [EUR] 27 875 416 32 248 894 20 370 624 36 500 147 67 326 503

Additional due to DP operation 6 000 000 6 000 000 6 000 000 6 000 000 6 000 000

Offshore discharge adaptation 2 000 000 2 000 000 2 000 000 2 000 000 2 000 000

Ship cost per ship [EUR] 35 875 416 40 248 894 28 370 624 44 500 147 73 326 503

Pre-delivery finance cost [% of total ship price] 9 % 9 % 9 % 9 % 9 %

Engineering and site supervision [% of total ship price] 4 % 4 % 4 % 4 % 4 %

Total investment per ship [EUR] 40 539 220 45 481 250 32 058 805 50 285 166 82 858 949

Total investment [EUR] 40 539 220 45 481 250 64 117 611 50 285 166 165 717 898

Total investment (USD) 54 782 729 61 461 148 86 645 420 67 952 927 223 943 105

Depreciation period 25 25 25 25 25

Interest rate 8,0% 8,0% 8,0% 8,0% 8,0%

Annual capex [EUR] 3 797 665 4 260 628 6 006 459 4 710 653 15 524 250

Operation and Maintenance

Fixed O&M cost per ship year 3 000 000 3 000 000 3 000 000 3 000 000 2 000 000

O&M per year as % of investment 2 % 2 % 2 % 2 % 2 %

Annual O&M [EUR] 3 810 784 3 909 625 7 282 352 4 005 703 7 314 358

Annual OPEX (Voyage+O&M) 7 337 338 8 403 937 12 761 886 9 585 191 32 481 140


Report no. [2214090] of 52

Summary

Ship size [m3] 10 700 13 300 6 700 16 000 39 900

No of ships 1 1 2 1 2

Roundtrip [days] 4 5 5 6 6

Voyage costs

Annual fuel costs [EUR] 2 902 387 3 873 645 4 854 200 4 957 265 22 063 449

Annual port fee [EUR] 624 167 620 667 625 333 622 222 3 103 333

Time charter costs

Annual capex [EUR] 3 797 665 4 260 628 6 006 459 4 710 653 15 524 250

Annual O&M [EUR] 3 810 784 3 909 625 7 282 352 4 005 703 7 314 358

Sum annual costs [EUR] 11 135 003 12 664 565 18 768 345 14 295 844 48 005 390

Transportation cost per ton delivered [EUR] 13,1 14,9 23,5 16,8 10,7

Transportation cost per ton delivered [USD] 17,7 20,1 31,7 22,7 14,4

Daily Time charter rate [USD/day/ship] 29 376 31 545 25 654 33 654 44 090


Report no. [2214090] of 52

ATTACHMENT 3: INJECTION SIMULATION MODEL AND RESULTS

In this section, first the simulation model is described. With the model a different number of simulations were performed:

- Shut-in simulation to determine close-in wellhead condition at varying res-ervoir pressures. This is important as at lower wellhead pressures, two phase conditions

might occur. This increases the complexity of start-up and shut-in. At start-

up potentially large pressure drops might occur across the wellhead choke

resulting in low temperatures. At shut-in, at shut-in gas is formed which can

expanse, again potentially resulting in low temperatures.

- Steady state injection cases with a variation in mass flow rate and injection temperature. The steady state simulations give the temperature profile along the well and

the required injection pressures. Furthermore, the velocities are calculated

in the complete well. At high velocities, vibration and erosion issues might

become critical.

- Injection cycle of a start-stop scenario. The injection cycle was simulated to evaluate the issues related to pressure

drops across the choke at start-up and shut-in. Furthermore, actual required

injection pressures and temperatures were evaluated. The main results are

the mass flow rates during injection and the resulting flow velocities.

It must be remarked that these simulations are very provisional as no detailed infor-mation was available on composition, potential well layout and reservoir properties. Also the start-stop simulation was simplified as no pump information was available. No emergency scenarios such as an Emergency Shut-Down (ESD) were evaluated at this point. Model description A single ID straight vertical injection well is modelled. A small section of horizontal section was included (100m). No shipping processing piping or offloading hoses were included at this moment. A valve is located at x= 50 m for opening and closing the well. For the well, a large size tubing was considered as new wells will be drilled.

Table1: Model setup

Parameter

Depth [m] 3050

ID [m] 0.1548

Wall roughness [m]

5e-6

Pure CO2

Model Single component model OLGA


Report no. [2214090] of 52

7.2.2

Cell size [m] 50 m

Single injection point

1.73e-005 [kg/s]Pa]

Ship capacity [tons]

14400

Linear outside temperature (ver-tical)

90 – 10 °C

U value [W/m2K] 40

Reservoir pres-sure (base) [bara]

350

Steady state shut-in conditions For the close in conditions the pressure (and temperature) profiles are given in Figure 1. The close-in wellhead pressures as function of reservoir pressures are plot-ted in Feil! Fant ikke referansekilden.. For reservoir pressures higher than 300 bar, the wellhead pressure is high enough to maintain single phase flow conditions in te well. At the base case condition of Pres = 350 bar, a close-in wellhead pressure is P = 106 bar at single phase liquid conditions. The wellhead pressure of 106 bar is the minimum required pump exit pressure. A pressure of 106 bar is a normal operating pressure so from this point of view no is-sues are expected. Furthermore, the wellhead is at single phase conditions, which makes injection easier as no potential two phase flow at the pump exit is present. Also no large pressure drops at choke opening will occur. So large temperature drops at start-up can be avoided.


Report no. [2214090] of 52

Figure 1: Shut-in pressure and pressure profile.

-100 -50 0 50 1000

50

100

150

200

250

300

350P

ressu

re [b

ar]

Temperature [degC]

Pres = 100 bar

Pres = 150 bar

Pres = 200 bar

Pres = 250 bar

Pres = 300 bar

Pres = 350 bar

Phase line

0 1000 2000 3000 40000

50

100

150

200

250

300

350

Along length (vertcial starts at x= 100m) [m]

Pre

ssu

re [b

ar]

Pres = 100 bar

Pres = 150 bar

Pres = 200 bar

Pres = 250 bar

Pres = 300 bar

Pres = 350 bar


Report no. [2214090] of 52

Figure 2: Closed in wellhead pressure as function of reservoir pressure.

At a wellhead temperature of 10°C, the phase line pressure is 45 bar. The fact that the pressures do not exactly match the phase line is due to the slow equilibrium time. Steady state flow rate variations At a ship capacity of 14400 ton and a typical unloading rate of 36 hrs a base unload-ing rate is m = 111 kg/s. In Figure 3, the wellhead pressure is plotted as function of reservoir pressure. At the base case the required pressure is approximately 170 bar. This is a very reasonable injection pressure which can be achieved by pumps and does not put unreasonable demands on piping and material classes. At lower temperatures, this requirement of 170 bars lowers ( Figure 4), of course at the cost of all lower temperatures in the complete well.

50 100 150 200 250 300 350 4000

20

40

60

80

100

120

Reservoir pressure [bar]

Clo

se

d in

we

llhe

ad

pre

ssu

re [b

ar]


Report no. [2214090] of 52

Figure 3: Wellhead pressure as function of mass flow rate (Pres = 350 bar).

50 100 150 200 250 300 3500

100

200

300

400

500

600

700

Mass flow rate [kg/s]

We

llhe

ad

pre

ssu

re (

Tin

= 0

de

gC

) [b

ar]

-60 -40 -20 0 20 400

100

200

300

400

500

600

Pre

ssu

re [b

ar]

Temperature [degC]

m = 50 kg/s

m = 75 kg/s

m = 100 kg/s

m = 200 kg/s

m = 300 kg/s

Phase line


Report no. [2214090] of 52

Figure 4: Wellhead pressure as function of wellhead temperature (Pres = 350 bar, m = 110 kg/s).

Start-stop scenarios

-60 -40 -20 0 20100

120

140

160

180

200

Wellhead temperature [degC]

We

llhe

ad

pre

ssu

re (

Pre

s =

35

0 b

ar)

[b

ar]

-60 -40 -20 0 20 40 600

50

100

150

200

250

300

350

400

450

Pre

ssu

re [b

ar]

Temperature [degC]

T = -50 degC

T = -40 degC

T = -30 degC

T = -20 degC

T = -10 degC

T = 0 degC

T = 10 degC

T = 20 degC

Phase line


Report no. [2214090] of 52

One start-stop scenario was simulated. This involved initial initialisation time of 7 hrs with a closed in choke (to reach equilibrium). After this a CO2 mass flow rate is in-creased from 0 to 111 kg/s in half an hour (at a temperature of 0degC). At the same time of 7hr, the choke is opened 6 minutes. The flow is maintained for 35.5 hrs, after which the mass flow is decreased down to 0 in half an hour (at 43.5 hr). At 43.5hrs, the well is closed in 6 min again (Figure 5).

Figure 5: Source flow and valve opening as function of time.

Results are plotted in Figure 6. In these figures, the downhole and wellhead pressures are plotted. No extreme low pressures and temperatures at shut in (or start up) are observed. At the high flow rates, the maximum velocity remains below 6 m/s (Figure 7) which is in general acceptable flow rate for liquids. At higher injection rates, the velocity will increase and therefore puts potentially limits on the offloading time.

0 10 20 30 40 500

20

40

60

80

100

120

Time [hrs]

So

urc

e r

ate

[kg

/s], v

alv

e o

pe

nin

g [%

]

Source

Valve opening


Report no. [2214090] of 52

Figure 6: Wellhead and downhole pressure and temperature as func-tion of time.

0 10 20 30 40 500

100

200

300

400

500

Time [hrs]

Pre

ssu

re [b

ar]

Wellhead (downstream choke)

Downhole

0 10 20 30 40 50-40

-20

0

20

40

60

80

100

Time [hrs]

Te

mp

era

ture

[d

eg

C]

Wellhead (downstream choke)

Downhole


Report no. [2214090] of 52

Figure 7: Velocity in the well at high flow rate.


Report no. [2214090] of 52

ATTACHMENT 4: POSSIBLE STEEL TYPES FOR LOW TEMPERATURE SERVICE

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