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Utilization of CO2 from Emitters in Poland for CO2-EOR
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 6721 – 6729
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Utilization of CO2 from emitters in Poland for CO2-EOR Anette Mathisena*, Ragnhild Skagestada Tel-Tek, Kjølnes Ring 30, N-3918 Porsgrunn, Norway
Abstract Carbon capture, utilization, and storage (CCUS) is one of several mitigation options that must be implemented in order to reduce anthropogenic CO2 emissions. The work presented in this paper is a part of the ongoing PRO_CCS project, where the emphasis is on Polish emitters located on or close to the Baltic Sea coast and possible whole chain CCS solutions for these. This paper will focus on the potential use of CO2 from these sources in CO2-EOR projects in the Baltic Sea and/or North Sea. In addition, a number of technical and non-technical CO2-EOR related aspects have been identified and discussed. Two oilfields, B8 in the Polish economic sector of the Baltic Sea and Brage on the Norwegian Continental Shelf have been selected. These two fields are matched with suitable emitters in Poland to develop two separate CCUS scenarios. The scenarios will provide a prediction on operations during the CO2-EOR project lifetime. These predictions will be based on open information about the oilfields and their current operation, and on available literature on CO2-EOR operations. The goal of the project is to assess the economic viability of the two scenarios. © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2-EOR
1.
Background and motivation
The work described in this paper is a part of the project “Economically efficient and socially accepted CCS/EOR processes”, with the short name PRO_CCS. This project is funded through Norway Grants in the Polish-Norwegian Research Programme
* Corresponding author. Tel.: +47 936 37 730 E-mail address: [email protected]
1876-6102 © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1802
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A premise was to look into the possibly of developing a CCUS chain for Polish CO2 sources located on the Baltic Sea coast. Generally, offshore storage and use of CO2 for enhanced oil recovery (EOR) involve fewer stakeholders as compared to onshore storage. Therefore, offshore CO2 storage will be less challenging (controversial) with regard to public acceptance. For Poland, transporting CO2 to oilfields in the Baltic Sea and/or North Sea could help create a future business case for CCS. The focus of this paper is to develop CO2-EOR scenarios where CO2 emitters in Poland are coupled with oilfields in the Baltic Sea and North Sea. . Nomenclature bbls CCUS EOR FOB FPSO MDEA NCS OOIP ROIP 2.
Barrels Carbon capture, utilisation, and storage Enhanced oil recovery Free on board Floating production storage and offloading Methyldiethanolamine Norwegian Continental Shelf Original oil in place Remaining oil in place
Methodology
In order to develop and evaluate whole chain CCUS solutions, relevant CO2 emission sources and sinks must be identified. Firstly, a qualitative and quantitative inventory of the Polish emitters were performed and used as input to CO2 capture plant design. The CO2 volumes that can potentially be captured are then used as input when assessing potential CO2-EOR and storage sites. The EOR and storage sites will be limited to sites located offshore in the Baltic and North Seas. Finally, the sources and sinks are connected through a transport infrastructure for CO2. The transportation modes studied are pipeline, ship and a combination of the two. Ultimately, the goal of the project is to assess the CCS solutions technically and economically, and to recommend a cost optimal solution. It is also hoped that the results are transferable to similar CCUS chains. A method for site selection, both for permanent storage and CO2-EOR is necessary when assessing sites for suitability. Such methodologies have been used for years and are available from the literature. For permanent storage the reservoir must meet criteria in regards to depth of the reservoir, petrophysical reservoir properties, integrity of the seal, and storage capacity. A challenge when it comes to screening of the potential sites is the lack of open relevant data. There is long experience with onshore CO2-EOR in the U.S. The challenge is to transfer this experience to other regions and in particular from onshore to offshore operating conditions. CO2 should be in a supercritical state (> 31 ˚C and 74 bar) when applied for EOR. This is generally considered to be at depths below 800 m. Another important parameter is the remaining oil in place (ROIP) as there should be enough oil left in the reservoir after primary and secondary recovery for this tertiary recovery method to be efficient, at least 20%. Potential oil reservoirs must meet criteria in regards to fluid properties (oil gravity, pressure, oil viscosity) and reservoir properties (ROIP, porosity). In a large-scale roll-out of CCS, a shared pipeline infrastructure is likely to be the most cost optimal solution. Here, the infrastructure connects individual CO2 emitters with one or more sinks. Sharing infrastructure in such a way reduces the transportation cost. However, this will require close cooperation between potentially a large number of parties, like emitters, infrastructure operators, sink owners, and governments. Another factor is that such infrastructure lacks flexibility. Changes are bound to occur over the infrastructure lifetime; like changed CO2 volumes and location of emitters, and location of sinks. Due to this, ship transport is becoming more attractive. Ship transport of CO2 is advantageous as a start-up option when gradually building up a complete infrastructure. Ships introduce flexibility to the CO2-chain and a ship can pick up CO2 from more than one source and bring it to the offloading point.
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3.
Scenario build-up
According to the Polish Geological Institute, there were 86 documented crude oilfields in Poland in 2015 [1]. Of these, two are located in the Polish economic sector of the Baltic Sea, and represent 20% of the exploitable resources. The two offshore fields are B3 and B8, and from these, B8 is selected for further study. In [2], 23 out of 40 Norwegian oilfields were found to be potentially suitable for CO2-EOR. Of these, Gullfaks and Brage were initially selected for further study in this project, with further narrowing to Brage only. In the recent Norwegian CCS Study, led by Gassnova on behalf of the Norwegian Ministry of Petroleum it was concluded that the Smeaheia area was best suited for large-scale permanent CO2 storage [3]. As this is the most current assessment of storage sites in the North Sea, it was also adopted as the storage site in this study. The Polish CO2 emission sources, potential CO2EOR oilfields and permanent storage sites have been identified, and their locations are shown in Figure 1. Emission source Potential storage site Potential CO2-EOR site Brage
Norway
Finland
Smeaheia area
Sweden Estonia
North Sea
Latvia Denmark Baltic Sea
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Germany
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Emission source 1 Poland 80 km
Fig. 1. Location of identified CO2 emission sources and -sinks (permanent storage and CO2-EOR sites) ©Mareano.
Different scenarios for CO2-EOR at Brage and B8 were studied. The most important aspects in the current study were how much oil could potentially be recovered when implementing CO2-EOR, and what volumes of CO2 would be needed at which time. The CO2-EOR OOIP recovery rate is expected to be lower for North Sea oilfields compared to North American ones. The main reason for this is the considerably higher recovery rates from primary and secondary production (35 – 55%, some fields even have recovery rates above 60%) for North Sea oilfields [4]. In [4], reservoir modelling of North Sea oilfields was performed. The modelling resulted in a CO2-EOR recovery rate of 4% of OOIP in a low recovery regime. In the high recovery regime, the rate was increased to 9% of OOIP for miscible projects in the North Sea. A recovery rate of 18% was used by the IEA GHG [5] for UK and Norwegian oilfields. Generally, it is expected that Polish oilfields have slightly lower recovery rates from primary and secondary production. The CO2 requirement per barrel of incremental oil was in [4] assumed to be 0.33 tonne. In a study of the UK sector of the North Sea, a minimum, maximum and a most likely value, 1.6, 2.6 and 1.8 bbl/tonne CO2, respectively, were used [6]. A ratio of 2.8 – 4.2 bbl/tonne CO2 is provided by IEA GHG [5]. The next challenge would then be to find a suitable injection scenario, which is further complicated due to the eventual production of injected CO2 from the oil field. The timing of the CO2 breakthrough and the amount of
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injected CO2 produced depends on the reservoir properties, injection regime, and EOR strategy. According to [7], approximately 40% of the originally injected CO2 can be expected to be produced together with the oil. This number is an average based on U.S. experience. A substantial increase in oil production rates shortly after CO2 injection starts is preferred. However, such a scenario necessitates that large volumes of CO2 is injected over the first few years, with gradually smaller volumes over the remaining years. The challenge with this scenario is the unpredictable volumes of fresh CO2 needed and the effect this would have on the fresh CO2 supply chain. This topic is complex and is further elaborated on in the discussion subchapter. Based on the above information from literature, the following base assumptions were decided on for the two selected oilfields; x Both fields - 3 bbls produced per tonne CO2 injected, a constant supply of fresh CO2 over 16 years, and a 40% recovery and reinjection of CO2. The total lifetime of the project is 17 years x Brage – 10% CO2-EOR recovery rate based on OOIP x B8 – 15% CO2-EOR recovery rate based on OOIP In Fig. 2 and 3, the assumed CO2-EOR scenarios are shown for Brage and B8, respectively. The data included are the fresh CO2 volumes, recovered and reinjected CO2 volumes, and increased oil production rates (CO2-EOR related production only). Note that the oil production rates in Fig. 2 and 3 will come in addition to the oil that would have been produced in this period if there was no CO2-EOR.
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Fig. 2. Brage CO2-EOR scenario.
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It can be seen from Fig. 2 and 3 that both oilfields have the same general oil production curve as a result of CO2EOR. This is not likely to be the case in a real CO2-EOR scenario, but for the lack of better predictions, this approach was adopted here. The modelling of the CO2-EOR scenario for the two oilfields gave the following key results; x Brage – 1.2 million tonne of fresh CO2 annually, with a total of 33 million tonne of CO2 injection over a 17 year period and a total increased oil production of 98 million bbls x B8 – 0.18 million tonne of fresh CO2 annually, with a total of 4.8 million tonne of CO2 injection over a 17 year period and a total increased oil production of 14.6 million bbls Based on the above assumptions a CO2 infrastructure could be developed, with known CO2 emission sources, CO2 volumes and sinks. With reference to Fig. 1; Emission source 1 is coupled with B8 and the CO2 is transported by ship over a distance of 115 km; Emission source 2 is coupled with Brage with a pipeline transport length of 1 255 km. 4.
CO2-EOR operation
With the major outlines in place, a more detailed look into the CO2-EOR and the consequences this will have on the platform operations, is needed An effort has been made to separate between technical/operational aspects, and non-technical aspects. Both will be crucial when determining the economic viability of a CO2-EOR project. These are discussed below, and finally the assumptions used in the current study are presented. It should be kept in mind that there are currently no CO2-EOR projects ongoing in the Baltic Sea or North Sea. 4.1. Technical/operational aspects If natural gas is produced, complications will arise when the CO2 injected into the field re-emerges and is produced. This CO2 needs to be reinjected into the reservoir, both from an operational and an environmental point of view. This becomes even more complicated if part of the natural gas is used as fuel for compression and power generation for platform operations. There are essentially two options; x Separation of natural gas and CO2, natural gas can then be sold and used as fuel to run platform operations with reinjection of CO2. x No separation of natural gas and CO2, after separation from the oil/water, the gas mixture is recompressed and reinjected. If natural gas and CO2 is to be separated, a new installation, expansion of the separation process, is likely needed. Such processes are common and are used when the CO2 content of the natural gas exceeds sales specifications. One such process is an amine separation process using MDEA (methyldiethanolamine). However, installing such equipment might be challenging due to potential issues with area requirements, stop in oil production during installation, and the introduction of new chemicals. An MDEA process could be installed on a floating vessel, an FPSO (floating production storage and offloading) unit. Such an installation provides the opportunity to obtain the space needed without compromising limited available platform and, in addition, only minor interruptions in oil production is to be expected. But new issues will arise however, having a floating vessel near a production platform, and transporting the gas stream from production platform to the FPSO and back will possibly render the operation more prone to production halts during challenging weather conditions. For North Sea operations this could be important. If natural gas and CO2 are not to be separated, another set of issues arises. The two most important ones are; Loss of natural gas sales revenues and the loss of fuel for compression and power turbines. The loss of revenues from natural gas sales is the least complicated from a technical point of view but will affect the cost picture of CO2-EOR. Technically, a new energy supply is needed, involving fuel change in existing turbines and a new fuel supply infrastructure (supply chain and storage on platform). There are a limited number of fuels that are applicable, when considering both ease of conversion and safety. Jet fuel, which can relatively easily replace natural gas as fuel in gas turbines, is not applicable. This is mainly due to safety, but also the relatively frequent supply ship calls that need to be made.
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Based on the above discussion, the only applicable solution seems to be electrification of the platform from mainland electricity grid or a dedicated plant. A discussion about electrification of the Norwegian Continental Shelf (NCS) is ongoing and no definite decisions have been made in this regard [8]. The main motivation behind this is to reduce CO2 emissions offshore. It is not likely that CO2-EOR will trigger electrification of fields as this has to be made based on an overall evaluation. In regard to Polish offshore oilfields, electrification does not seem to be on the agenda. The cost of electrifying platform operations will be considerable, and making this decision will be more difficult with the estimated remaining lifetime of economic oil production. Factoring in CO2-EOR implementation in such an evaluation is important as this has the potential of prolonging the lifetime of the production. More knowledge is also needed in regard to the effect of injecting both CO2 and natural gas into the reservoir. It is not clear whether this will give a positive or negative effect on oil production rate compared to injection of CO2 only. Another important topic is material quality and capacity of the existing installations; production wells, topside separation process, and injection wells. Material quality becomes an issue when both CO2 and water is present in the system. Carbonic acid is formed through reactions between CO2 and water which over time will cause corrosion. If the material quality of existing installations is of insufficient quality to handle corrosion, corrosion measures must be undertaken. Measures include, change of material, application of coatings, and/or the use of corrosion inhibitors. The first two measures will have consequences for the platform operation during recompletion, and result in a halt in oil production. The last measure could result in adding chemical which are not used on the platform today. Many of the fields considered for CO2-EOR are in tail end production. This means that the oil production and handling capacity is more than sufficient to handle the increased oil production associated with CO2-EOR implementation as the design capacity is likely to be considerably higher. However, it is common that the gas and water production increase as a field matures, but this does not necessarily mean that the amounts produced are higher than design capacity. An oilfield is expected to have both production and injection wells. Especially the production wells are likely to be of sufficient capacity if CO2-EOR is implemented during tail end production. The injection capacity, on the other hand, might be more challenging and is dependent on whether or not the produced water and gas is already reinjected, e.g. as secondary oil recovery methods or emission/discharge control. The location of the injection wells also needs to be considered, as not all might be suitable in an optimized CO2-EOR injection regime. When assessing the suitability of a well, whether for injection or production, in a CO2-EOR scenario, the well material quality must be considered. 4.2. Non-technical aspects In addition to the technical aspects, there are a number of non-technical aspects that will have implications on the economic viability of a CO2-EOR project. The most important ones will be discussed here. It should also be noted that they have a varying degree of relevance and influence, and that some are only applicable in specific countries. Oil and gas recovery operations on the NCS, are subject to taxation at 78% on the profits from oil and gas production. 27% makes up the ordinary company tax and the remaining 51% is the special tax on oil and gas production [9]. This policy is expected to be applicable for CO2-EOR projects as well. In Poland, the cooperated income tax is currently at 19% [10]. Currently there is also a tax on the mining of certain minerals, and oil and natural gas falls under this category. For conventional oil and gas production, the rates are currently 3 and 6%, respectively. The tax framework for oil and gas exploration and production will be changed in 2016, but will not be payable until 2020. The tax load will be weighted according to the degree of profit in a given year [10]. The taxation of oil and natural gas is however difficult to account for satisfactorily, as the tax follows the company/companies that operate the CO2-EOR field in question. These companies are likely to have owners interest in other operating oil and gas fields and fields under development and exploration, further complicating the matter. Ultimately, the taxation is based on the entire oil and gas operation of the company. A tax that is currently exclusive for oil and gas operations on the NCS is a CO2 emission tax. The tax was introduced in 1991 and is applicable for CO2 (and natural gas) released to the atmosphere during operation (e.g.
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unburnt natural gas, flaring of natural gas, natural gas sweetening, and power production for platform operations (gas turbines). In 2015 this tax was 1 NOK per Sm3 gas, which results in approximately 50 EUR per tonne CO2 [11]. A CO2-EOR project is currently referred to as CO2 utilization, but the project should ultimately aspire to be a CO2 storage project. It could even become a pure CO2 storage project when oil production is no longer economically viable from the field in question. In [12], it is reported that 90 – 95% of the CO2 supplied to CO2-EOR projects in the U.S. is being retained in the reservoir and the processing units, as these are connected in a closed loop. Any leakage is expected to be minimal, and mainly related to short and infrequent power outages during recondition of the CO2 and CO2 migration from the reservoir. The value of fresh CO2 supply will be viewed differently depending on whether you are a CO2 emitter, CO2 transporter or an oilfield owner. The CO2 emitter is likely to put a price on CO2 that covers the cost of capturing, the CO2 transporter will do the same. The field owner, depending on the project could be willing to pay a price, receive and use the CO2 free of charge or even demand to get payed to receive the CO2. The final value of fresh CO2 in a CO2-EOR project is very difficult to predict, and will ultimately be dependent on the other cost elements. It is likely that the value of CO2 will be used to balance the economic viability of the project. The added benefit of CO2-EOR is also a key aspect, without a sufficient added benefit, i.e. increased oil production through injection of CO2, the project is not viable. Ultimately, reservoir and CO2 injection regime simulations are needed to assess the potential for each reservoir and to make a realistic prediction on the increased oil production potential and the associated CO2 needed to achieve this. Implementing CO2-EOR on an oilfield is expected to lengthen the lifetime of the oilfield, and thereby postponing the cost associated with decommissioning of the installations (the platform and any subsea installations). This could be an added benefit of CO2-EOR projects provided that there are no major investments needed when implementing CO2-EOR. The final aspect to be discussed here is the most important parameter, the oil price. From around 2011 to 2014 the Europe Brent spot price FOB (free on board) was around 110 USD per barrel. In 2014, the oil price experienced a significant drop, culminating in a value below 30 USD in July 2016. The price has since risen, and is now (October 2016) between 40 – 50 USD [13]. 4.3. Assumptions adopted in this study A general comment regarding the Brage and B8 oilfields is that they are in very different production phases, with B8 just coming into production and Brage in the tail end production. This means that for some of the assumptions made, especially those that are capacity related (i.e. separation system and wells) are more likely to be true for Brage than for B8. However, due to the lack of detailed information about B8 and for simplicity, the technical assumptions will be similar. There are however, differences when it comes to some of the non-technical aspects, due to the oilfields being located in different countries. The following technical assumptions have been made so far for CO2-EOR implementation at Brage and B8 in the current project. These are in addition to the assumptions made regarding the potential for increased oil recovery, the associated CO2 volumes needed, and expected recycle ratio of CO2 presented in Chapter 3. x No separation of natural gas and CO2, all produced gas (some losses are expected) is reinjected into the reservoir. o At Brage today, a relatively large part of the natural gas produced is used for gas lift [14]. Gas lift is used to maintain a sufficient flow rate in production wells from reservoirs with relatively low production pressures. It is expected that using the natural gas/CO2 mixture for this purpose is maintained in a CO2-EOR scenario. In addition, produced natural gas is reinjected to the reservoir as a secondary oil recovery method for repressurisation or to maintain pressure, and as energy input to the gas turbines for platform operations [14]. o Information about the separation process and natural gas production on B8 is yet to be obtained. x Platform operation is electrified from mainland. x It is assumed that there is sufficient capacity in the separation system, i.e. no modifications needed. In order to reduce the potential consequences of corrosion, corrosion inhibitors are introduced.
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x
x
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No new production or injection wells needed. It is assumed that the wells can handle the increased volumes and are of sufficient quality. o As of 2015, there are 27 oil production, 1 gas injection and 7 water injection wells in operation at Brage [15]. o According to [16], B8 has 6 production wells and 4 injection boreholes, and there are plans to drill a water injection well. Water injection, as a secondary oil recovery method and/or to reduce discharge to sea, will continue in a CO2-EOR scenario. o Water injection is known to take place at Brage today [14]. The water injected is used for maintaining pressure in the reservoir, but also have an environmental side as it limits discharge to sea (the water is treated before release). o There are plans to drill one water injection well at B8 [16], it can therefore be assumed that water injection will take place in the future. The fresh CO2 comes pre-conditioned from ship (Brage) and pipeline (B8) and is ready for injection. The CO2 is injected via the platform through existing wells.
The following non-technical aspects are included; x No stop in oil production or sales when implementing CO2-EOR. x Loss of revenues from natural gas sales, price may vary depending on the region. o Included for Brage o Currently undecided for B8 x Taxation will be included if found reasonable, i.e. if it is possible to consider the CO2-EOR scenarios as isolated projects without being too different from a real project. x Offshore CO2 emission tax. o Included for Brage, 50 EUR per tonne CO2 emitted. o Not included for B8. x Oil price, $40/bbl (in addition a sensitivity analysis will be performed). 5.
Summary and further work
An overview of the two developed CO2-EOR scenarios are provided in this paper. A base assumption regarding the potential for increased oil recovery, the associated CO2 volumes needed, and expected recycle ratio of CO2 is presented. These are further built on when developing the scenarios. Additional technical and non-technical issues relevant for CO2-EOR projects were discussed. The assumptions arrived at for the two scenarios are similar for the technical aspects, with some differences in the non-technical aspects due to the oilfields geographic location. The goal of the project is to complete the two CO2-EOR scenarios, and based on all of the assumptions made make a prediction on operations during the CO2-EOR project lifetime. This will then be used as input in the economic evaluation of the whole CCUS scenario. The most important aspect of a CO2-EOR project is its economic viability as this will decided whether the projected has any potential. The effect of key parameters like the oil price and the value of fresh CO2 will be studied through sensitivity analysis. Acknowledgements The authors wish to thank the other partners in the project; Silesian University of Technology (Poland), Czestochowa University of Technology (Poland), and NILU (Norway). This project is funded through Norway Grants in the Polish-Norwegian Research Programme operated by the National Centre for Research and Development. References [1] Polish Geological Institute. http://geoportal.pgi.gov.pl/surowce/energetyczne/ropa_naftowa. Cited 27.09.2016
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[2] Lindeberg E. EOR på norsk sokkel – er vi for sent ute? CO2 konferansen 2015. Trondheim. Norway. 2015. [In Norwegian] [3] Norwegian Ministry of Petroleum. https://www.regjeringen.no/globalassets/departementene/oed/pdf/summary.pdf. Cited 27.09.2016 [4] Tzimas A., Georgakaki A., Garcia Cortes C., Peteves SD. Enhanced oil recovery using carbon dioxide in the European energy system. Report EUR 21895 EN. DG JRC Institute for Energy. the Netherlands. 2005 [5] IEA GHG. CO2 Storage in Depleted Oilfields: Global Application Criteria for Carbon Dioxide Enhanced Oil Recovery. Technical Report 2009-12. 2009 [6] Kemp AG., Sola Kasim A. The Economics of CO2-EOR Cluster Developments in the UK Central North Sea / Outer Moray Firth. In North Sea Study Occasional Paper. 2012 [7] Shaw J., Bachu S. Screening, evaluation, and ranking of oil reservoirs suitable for CO2-flood EOR and carbon dioxide sequestration. Journal of Canadian Petroleum Technology. vol. 41 (9). 2002 [8] Norwegian Environment Agency. Climate mitigation measures and emission trajectories up to 2030 – Summary. Report M-415. 2015 [9] Norwegian Petroleum, http://www.norskpetroleum.no/en/framework/petroleum-tax/. Cited 27.09.2016 [10] EY. Global oil and gas tax guide 2015. http://www.ey.com/Publication/vwLUAssets/EY-2015-Global-oil-and-gas-tax-guide/$FILE/EY2015-Global-oil-and-gas-tax-guide.pdf. [11] Gavenas E., Rosendal KE., Skjerpen T. CO2-emissions from Norwegian oil and gas extraction. Statistics Norway Research Department. No. 806. 2015 [12] Meltzer S. Carbon dioxide enhanced oil recovery (CO2 EOR): factors involved in adding carbon capture, utilization and storage (CCUS) to enhanced oil recovery. U.S. 2012 [13] IEA. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RBRTE&f=D. Cited 27.09.2016 [14] Wintershall. Årsrapport til Miljødirektoratet for 2015 – Brage. 2015 [In Norwegian] [15] Norwegian Petroleum Directorate. FactPages – Brage. Cited 27.09.2016 [16] Offshore Technology.com. http://www.offshore-technology.com/projects/b8-oil-field-baltic-sea/. Cited 27.09.2016
ScienceDirect Energy Procedia 114 (2017) 6721 – 6729
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Utilization of CO2 from emitters in Poland for CO2-EOR Anette Mathisena*, Ragnhild Skagestada Tel-Tek, Kjølnes Ring 30, N-3918 Porsgrunn, Norway
Abstract Carbon capture, utilization, and storage (CCUS) is one of several mitigation options that must be implemented in order to reduce anthropogenic CO2 emissions. The work presented in this paper is a part of the ongoing PRO_CCS project, where the emphasis is on Polish emitters located on or close to the Baltic Sea coast and possible whole chain CCS solutions for these. This paper will focus on the potential use of CO2 from these sources in CO2-EOR projects in the Baltic Sea and/or North Sea. In addition, a number of technical and non-technical CO2-EOR related aspects have been identified and discussed. Two oilfields, B8 in the Polish economic sector of the Baltic Sea and Brage on the Norwegian Continental Shelf have been selected. These two fields are matched with suitable emitters in Poland to develop two separate CCUS scenarios. The scenarios will provide a prediction on operations during the CO2-EOR project lifetime. These predictions will be based on open information about the oilfields and their current operation, and on available literature on CO2-EOR operations. The goal of the project is to assess the economic viability of the two scenarios. © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license © 2017 The Authors. Published by Elsevier Ltd. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2-EOR
1.
Background and motivation
The work described in this paper is a part of the project “Economically efficient and socially accepted CCS/EOR processes”, with the short name PRO_CCS. This project is funded through Norway Grants in the Polish-Norwegian Research Programme
* Corresponding author. Tel.: +47 936 37 730 E-mail address: [email protected]
1876-6102 © 2017 Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1802
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A premise was to look into the possibly of developing a CCUS chain for Polish CO2 sources located on the Baltic Sea coast. Generally, offshore storage and use of CO2 for enhanced oil recovery (EOR) involve fewer stakeholders as compared to onshore storage. Therefore, offshore CO2 storage will be less challenging (controversial) with regard to public acceptance. For Poland, transporting CO2 to oilfields in the Baltic Sea and/or North Sea could help create a future business case for CCS. The focus of this paper is to develop CO2-EOR scenarios where CO2 emitters in Poland are coupled with oilfields in the Baltic Sea and North Sea. . Nomenclature bbls CCUS EOR FOB FPSO MDEA NCS OOIP ROIP 2.
Barrels Carbon capture, utilisation, and storage Enhanced oil recovery Free on board Floating production storage and offloading Methyldiethanolamine Norwegian Continental Shelf Original oil in place Remaining oil in place
Methodology
In order to develop and evaluate whole chain CCUS solutions, relevant CO2 emission sources and sinks must be identified. Firstly, a qualitative and quantitative inventory of the Polish emitters were performed and used as input to CO2 capture plant design. The CO2 volumes that can potentially be captured are then used as input when assessing potential CO2-EOR and storage sites. The EOR and storage sites will be limited to sites located offshore in the Baltic and North Seas. Finally, the sources and sinks are connected through a transport infrastructure for CO2. The transportation modes studied are pipeline, ship and a combination of the two. Ultimately, the goal of the project is to assess the CCS solutions technically and economically, and to recommend a cost optimal solution. It is also hoped that the results are transferable to similar CCUS chains. A method for site selection, both for permanent storage and CO2-EOR is necessary when assessing sites for suitability. Such methodologies have been used for years and are available from the literature. For permanent storage the reservoir must meet criteria in regards to depth of the reservoir, petrophysical reservoir properties, integrity of the seal, and storage capacity. A challenge when it comes to screening of the potential sites is the lack of open relevant data. There is long experience with onshore CO2-EOR in the U.S. The challenge is to transfer this experience to other regions and in particular from onshore to offshore operating conditions. CO2 should be in a supercritical state (> 31 ˚C and 74 bar) when applied for EOR. This is generally considered to be at depths below 800 m. Another important parameter is the remaining oil in place (ROIP) as there should be enough oil left in the reservoir after primary and secondary recovery for this tertiary recovery method to be efficient, at least 20%. Potential oil reservoirs must meet criteria in regards to fluid properties (oil gravity, pressure, oil viscosity) and reservoir properties (ROIP, porosity). In a large-scale roll-out of CCS, a shared pipeline infrastructure is likely to be the most cost optimal solution. Here, the infrastructure connects individual CO2 emitters with one or more sinks. Sharing infrastructure in such a way reduces the transportation cost. However, this will require close cooperation between potentially a large number of parties, like emitters, infrastructure operators, sink owners, and governments. Another factor is that such infrastructure lacks flexibility. Changes are bound to occur over the infrastructure lifetime; like changed CO2 volumes and location of emitters, and location of sinks. Due to this, ship transport is becoming more attractive. Ship transport of CO2 is advantageous as a start-up option when gradually building up a complete infrastructure. Ships introduce flexibility to the CO2-chain and a ship can pick up CO2 from more than one source and bring it to the offloading point.
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3.
Scenario build-up
According to the Polish Geological Institute, there were 86 documented crude oilfields in Poland in 2015 [1]. Of these, two are located in the Polish economic sector of the Baltic Sea, and represent 20% of the exploitable resources. The two offshore fields are B3 and B8, and from these, B8 is selected for further study. In [2], 23 out of 40 Norwegian oilfields were found to be potentially suitable for CO2-EOR. Of these, Gullfaks and Brage were initially selected for further study in this project, with further narrowing to Brage only. In the recent Norwegian CCS Study, led by Gassnova on behalf of the Norwegian Ministry of Petroleum it was concluded that the Smeaheia area was best suited for large-scale permanent CO2 storage [3]. As this is the most current assessment of storage sites in the North Sea, it was also adopted as the storage site in this study. The Polish CO2 emission sources, potential CO2EOR oilfields and permanent storage sites have been identified, and their locations are shown in Figure 1. Emission source Potential storage site Potential CO2-EOR site Brage
Norway
Finland
Smeaheia area
Sweden Estonia
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Fig. 1. Location of identified CO2 emission sources and -sinks (permanent storage and CO2-EOR sites) ©Mareano.
Different scenarios for CO2-EOR at Brage and B8 were studied. The most important aspects in the current study were how much oil could potentially be recovered when implementing CO2-EOR, and what volumes of CO2 would be needed at which time. The CO2-EOR OOIP recovery rate is expected to be lower for North Sea oilfields compared to North American ones. The main reason for this is the considerably higher recovery rates from primary and secondary production (35 – 55%, some fields even have recovery rates above 60%) for North Sea oilfields [4]. In [4], reservoir modelling of North Sea oilfields was performed. The modelling resulted in a CO2-EOR recovery rate of 4% of OOIP in a low recovery regime. In the high recovery regime, the rate was increased to 9% of OOIP for miscible projects in the North Sea. A recovery rate of 18% was used by the IEA GHG [5] for UK and Norwegian oilfields. Generally, it is expected that Polish oilfields have slightly lower recovery rates from primary and secondary production. The CO2 requirement per barrel of incremental oil was in [4] assumed to be 0.33 tonne. In a study of the UK sector of the North Sea, a minimum, maximum and a most likely value, 1.6, 2.6 and 1.8 bbl/tonne CO2, respectively, were used [6]. A ratio of 2.8 – 4.2 bbl/tonne CO2 is provided by IEA GHG [5]. The next challenge would then be to find a suitable injection scenario, which is further complicated due to the eventual production of injected CO2 from the oil field. The timing of the CO2 breakthrough and the amount of
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injected CO2 produced depends on the reservoir properties, injection regime, and EOR strategy. According to [7], approximately 40% of the originally injected CO2 can be expected to be produced together with the oil. This number is an average based on U.S. experience. A substantial increase in oil production rates shortly after CO2 injection starts is preferred. However, such a scenario necessitates that large volumes of CO2 is injected over the first few years, with gradually smaller volumes over the remaining years. The challenge with this scenario is the unpredictable volumes of fresh CO2 needed and the effect this would have on the fresh CO2 supply chain. This topic is complex and is further elaborated on in the discussion subchapter. Based on the above information from literature, the following base assumptions were decided on for the two selected oilfields; x Both fields - 3 bbls produced per tonne CO2 injected, a constant supply of fresh CO2 over 16 years, and a 40% recovery and reinjection of CO2. The total lifetime of the project is 17 years x Brage – 10% CO2-EOR recovery rate based on OOIP x B8 – 15% CO2-EOR recovery rate based on OOIP In Fig. 2 and 3, the assumed CO2-EOR scenarios are shown for Brage and B8, respectively. The data included are the fresh CO2 volumes, recovered and reinjected CO2 volumes, and increased oil production rates (CO2-EOR related production only). Note that the oil production rates in Fig. 2 and 3 will come in addition to the oil that would have been produced in this period if there was no CO2-EOR.
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Fig. 3. B8 CO2-EOR scenario.
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Fig. 2. Brage CO2-EOR scenario.
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It can be seen from Fig. 2 and 3 that both oilfields have the same general oil production curve as a result of CO2EOR. This is not likely to be the case in a real CO2-EOR scenario, but for the lack of better predictions, this approach was adopted here. The modelling of the CO2-EOR scenario for the two oilfields gave the following key results; x Brage – 1.2 million tonne of fresh CO2 annually, with a total of 33 million tonne of CO2 injection over a 17 year period and a total increased oil production of 98 million bbls x B8 – 0.18 million tonne of fresh CO2 annually, with a total of 4.8 million tonne of CO2 injection over a 17 year period and a total increased oil production of 14.6 million bbls Based on the above assumptions a CO2 infrastructure could be developed, with known CO2 emission sources, CO2 volumes and sinks. With reference to Fig. 1; Emission source 1 is coupled with B8 and the CO2 is transported by ship over a distance of 115 km; Emission source 2 is coupled with Brage with a pipeline transport length of 1 255 km. 4.
CO2-EOR operation
With the major outlines in place, a more detailed look into the CO2-EOR and the consequences this will have on the platform operations, is needed An effort has been made to separate between technical/operational aspects, and non-technical aspects. Both will be crucial when determining the economic viability of a CO2-EOR project. These are discussed below, and finally the assumptions used in the current study are presented. It should be kept in mind that there are currently no CO2-EOR projects ongoing in the Baltic Sea or North Sea. 4.1. Technical/operational aspects If natural gas is produced, complications will arise when the CO2 injected into the field re-emerges and is produced. This CO2 needs to be reinjected into the reservoir, both from an operational and an environmental point of view. This becomes even more complicated if part of the natural gas is used as fuel for compression and power generation for platform operations. There are essentially two options; x Separation of natural gas and CO2, natural gas can then be sold and used as fuel to run platform operations with reinjection of CO2. x No separation of natural gas and CO2, after separation from the oil/water, the gas mixture is recompressed and reinjected. If natural gas and CO2 is to be separated, a new installation, expansion of the separation process, is likely needed. Such processes are common and are used when the CO2 content of the natural gas exceeds sales specifications. One such process is an amine separation process using MDEA (methyldiethanolamine). However, installing such equipment might be challenging due to potential issues with area requirements, stop in oil production during installation, and the introduction of new chemicals. An MDEA process could be installed on a floating vessel, an FPSO (floating production storage and offloading) unit. Such an installation provides the opportunity to obtain the space needed without compromising limited available platform and, in addition, only minor interruptions in oil production is to be expected. But new issues will arise however, having a floating vessel near a production platform, and transporting the gas stream from production platform to the FPSO and back will possibly render the operation more prone to production halts during challenging weather conditions. For North Sea operations this could be important. If natural gas and CO2 are not to be separated, another set of issues arises. The two most important ones are; Loss of natural gas sales revenues and the loss of fuel for compression and power turbines. The loss of revenues from natural gas sales is the least complicated from a technical point of view but will affect the cost picture of CO2-EOR. Technically, a new energy supply is needed, involving fuel change in existing turbines and a new fuel supply infrastructure (supply chain and storage on platform). There are a limited number of fuels that are applicable, when considering both ease of conversion and safety. Jet fuel, which can relatively easily replace natural gas as fuel in gas turbines, is not applicable. This is mainly due to safety, but also the relatively frequent supply ship calls that need to be made.
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Based on the above discussion, the only applicable solution seems to be electrification of the platform from mainland electricity grid or a dedicated plant. A discussion about electrification of the Norwegian Continental Shelf (NCS) is ongoing and no definite decisions have been made in this regard [8]. The main motivation behind this is to reduce CO2 emissions offshore. It is not likely that CO2-EOR will trigger electrification of fields as this has to be made based on an overall evaluation. In regard to Polish offshore oilfields, electrification does not seem to be on the agenda. The cost of electrifying platform operations will be considerable, and making this decision will be more difficult with the estimated remaining lifetime of economic oil production. Factoring in CO2-EOR implementation in such an evaluation is important as this has the potential of prolonging the lifetime of the production. More knowledge is also needed in regard to the effect of injecting both CO2 and natural gas into the reservoir. It is not clear whether this will give a positive or negative effect on oil production rate compared to injection of CO2 only. Another important topic is material quality and capacity of the existing installations; production wells, topside separation process, and injection wells. Material quality becomes an issue when both CO2 and water is present in the system. Carbonic acid is formed through reactions between CO2 and water which over time will cause corrosion. If the material quality of existing installations is of insufficient quality to handle corrosion, corrosion measures must be undertaken. Measures include, change of material, application of coatings, and/or the use of corrosion inhibitors. The first two measures will have consequences for the platform operation during recompletion, and result in a halt in oil production. The last measure could result in adding chemical which are not used on the platform today. Many of the fields considered for CO2-EOR are in tail end production. This means that the oil production and handling capacity is more than sufficient to handle the increased oil production associated with CO2-EOR implementation as the design capacity is likely to be considerably higher. However, it is common that the gas and water production increase as a field matures, but this does not necessarily mean that the amounts produced are higher than design capacity. An oilfield is expected to have both production and injection wells. Especially the production wells are likely to be of sufficient capacity if CO2-EOR is implemented during tail end production. The injection capacity, on the other hand, might be more challenging and is dependent on whether or not the produced water and gas is already reinjected, e.g. as secondary oil recovery methods or emission/discharge control. The location of the injection wells also needs to be considered, as not all might be suitable in an optimized CO2-EOR injection regime. When assessing the suitability of a well, whether for injection or production, in a CO2-EOR scenario, the well material quality must be considered. 4.2. Non-technical aspects In addition to the technical aspects, there are a number of non-technical aspects that will have implications on the economic viability of a CO2-EOR project. The most important ones will be discussed here. It should also be noted that they have a varying degree of relevance and influence, and that some are only applicable in specific countries. Oil and gas recovery operations on the NCS, are subject to taxation at 78% on the profits from oil and gas production. 27% makes up the ordinary company tax and the remaining 51% is the special tax on oil and gas production [9]. This policy is expected to be applicable for CO2-EOR projects as well. In Poland, the cooperated income tax is currently at 19% [10]. Currently there is also a tax on the mining of certain minerals, and oil and natural gas falls under this category. For conventional oil and gas production, the rates are currently 3 and 6%, respectively. The tax framework for oil and gas exploration and production will be changed in 2016, but will not be payable until 2020. The tax load will be weighted according to the degree of profit in a given year [10]. The taxation of oil and natural gas is however difficult to account for satisfactorily, as the tax follows the company/companies that operate the CO2-EOR field in question. These companies are likely to have owners interest in other operating oil and gas fields and fields under development and exploration, further complicating the matter. Ultimately, the taxation is based on the entire oil and gas operation of the company. A tax that is currently exclusive for oil and gas operations on the NCS is a CO2 emission tax. The tax was introduced in 1991 and is applicable for CO2 (and natural gas) released to the atmosphere during operation (e.g.
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unburnt natural gas, flaring of natural gas, natural gas sweetening, and power production for platform operations (gas turbines). In 2015 this tax was 1 NOK per Sm3 gas, which results in approximately 50 EUR per tonne CO2 [11]. A CO2-EOR project is currently referred to as CO2 utilization, but the project should ultimately aspire to be a CO2 storage project. It could even become a pure CO2 storage project when oil production is no longer economically viable from the field in question. In [12], it is reported that 90 – 95% of the CO2 supplied to CO2-EOR projects in the U.S. is being retained in the reservoir and the processing units, as these are connected in a closed loop. Any leakage is expected to be minimal, and mainly related to short and infrequent power outages during recondition of the CO2 and CO2 migration from the reservoir. The value of fresh CO2 supply will be viewed differently depending on whether you are a CO2 emitter, CO2 transporter or an oilfield owner. The CO2 emitter is likely to put a price on CO2 that covers the cost of capturing, the CO2 transporter will do the same. The field owner, depending on the project could be willing to pay a price, receive and use the CO2 free of charge or even demand to get payed to receive the CO2. The final value of fresh CO2 in a CO2-EOR project is very difficult to predict, and will ultimately be dependent on the other cost elements. It is likely that the value of CO2 will be used to balance the economic viability of the project. The added benefit of CO2-EOR is also a key aspect, without a sufficient added benefit, i.e. increased oil production through injection of CO2, the project is not viable. Ultimately, reservoir and CO2 injection regime simulations are needed to assess the potential for each reservoir and to make a realistic prediction on the increased oil production potential and the associated CO2 needed to achieve this. Implementing CO2-EOR on an oilfield is expected to lengthen the lifetime of the oilfield, and thereby postponing the cost associated with decommissioning of the installations (the platform and any subsea installations). This could be an added benefit of CO2-EOR projects provided that there are no major investments needed when implementing CO2-EOR. The final aspect to be discussed here is the most important parameter, the oil price. From around 2011 to 2014 the Europe Brent spot price FOB (free on board) was around 110 USD per barrel. In 2014, the oil price experienced a significant drop, culminating in a value below 30 USD in July 2016. The price has since risen, and is now (October 2016) between 40 – 50 USD [13]. 4.3. Assumptions adopted in this study A general comment regarding the Brage and B8 oilfields is that they are in very different production phases, with B8 just coming into production and Brage in the tail end production. This means that for some of the assumptions made, especially those that are capacity related (i.e. separation system and wells) are more likely to be true for Brage than for B8. However, due to the lack of detailed information about B8 and for simplicity, the technical assumptions will be similar. There are however, differences when it comes to some of the non-technical aspects, due to the oilfields being located in different countries. The following technical assumptions have been made so far for CO2-EOR implementation at Brage and B8 in the current project. These are in addition to the assumptions made regarding the potential for increased oil recovery, the associated CO2 volumes needed, and expected recycle ratio of CO2 presented in Chapter 3. x No separation of natural gas and CO2, all produced gas (some losses are expected) is reinjected into the reservoir. o At Brage today, a relatively large part of the natural gas produced is used for gas lift [14]. Gas lift is used to maintain a sufficient flow rate in production wells from reservoirs with relatively low production pressures. It is expected that using the natural gas/CO2 mixture for this purpose is maintained in a CO2-EOR scenario. In addition, produced natural gas is reinjected to the reservoir as a secondary oil recovery method for repressurisation or to maintain pressure, and as energy input to the gas turbines for platform operations [14]. o Information about the separation process and natural gas production on B8 is yet to be obtained. x Platform operation is electrified from mainland. x It is assumed that there is sufficient capacity in the separation system, i.e. no modifications needed. In order to reduce the potential consequences of corrosion, corrosion inhibitors are introduced.
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x
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No new production or injection wells needed. It is assumed that the wells can handle the increased volumes and are of sufficient quality. o As of 2015, there are 27 oil production, 1 gas injection and 7 water injection wells in operation at Brage [15]. o According to [16], B8 has 6 production wells and 4 injection boreholes, and there are plans to drill a water injection well. Water injection, as a secondary oil recovery method and/or to reduce discharge to sea, will continue in a CO2-EOR scenario. o Water injection is known to take place at Brage today [14]. The water injected is used for maintaining pressure in the reservoir, but also have an environmental side as it limits discharge to sea (the water is treated before release). o There are plans to drill one water injection well at B8 [16], it can therefore be assumed that water injection will take place in the future. The fresh CO2 comes pre-conditioned from ship (Brage) and pipeline (B8) and is ready for injection. The CO2 is injected via the platform through existing wells.
The following non-technical aspects are included; x No stop in oil production or sales when implementing CO2-EOR. x Loss of revenues from natural gas sales, price may vary depending on the region. o Included for Brage o Currently undecided for B8 x Taxation will be included if found reasonable, i.e. if it is possible to consider the CO2-EOR scenarios as isolated projects without being too different from a real project. x Offshore CO2 emission tax. o Included for Brage, 50 EUR per tonne CO2 emitted. o Not included for B8. x Oil price, $40/bbl (in addition a sensitivity analysis will be performed). 5.
Summary and further work
An overview of the two developed CO2-EOR scenarios are provided in this paper. A base assumption regarding the potential for increased oil recovery, the associated CO2 volumes needed, and expected recycle ratio of CO2 is presented. These are further built on when developing the scenarios. Additional technical and non-technical issues relevant for CO2-EOR projects were discussed. The assumptions arrived at for the two scenarios are similar for the technical aspects, with some differences in the non-technical aspects due to the oilfields geographic location. The goal of the project is to complete the two CO2-EOR scenarios, and based on all of the assumptions made make a prediction on operations during the CO2-EOR project lifetime. This will then be used as input in the economic evaluation of the whole CCUS scenario. The most important aspect of a CO2-EOR project is its economic viability as this will decided whether the projected has any potential. The effect of key parameters like the oil price and the value of fresh CO2 will be studied through sensitivity analysis. Acknowledgements The authors wish to thank the other partners in the project; Silesian University of Technology (Poland), Czestochowa University of Technology (Poland), and NILU (Norway). This project is funded through Norway Grants in the Polish-Norwegian Research Programme operated by the National Centre for Research and Development. References [1] Polish Geological Institute. http://geoportal.pgi.gov.pl/surowce/energetyczne/ropa_naftowa. Cited 27.09.2016
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[2] Lindeberg E. EOR på norsk sokkel – er vi for sent ute? CO2 konferansen 2015. Trondheim. Norway. 2015. [In Norwegian] [3] Norwegian Ministry of Petroleum. https://www.regjeringen.no/globalassets/departementene/oed/pdf/summary.pdf. Cited 27.09.2016 [4] Tzimas A., Georgakaki A., Garcia Cortes C., Peteves SD. Enhanced oil recovery using carbon dioxide in the European energy system. Report EUR 21895 EN. DG JRC Institute for Energy. the Netherlands. 2005 [5] IEA GHG. CO2 Storage in Depleted Oilfields: Global Application Criteria for Carbon Dioxide Enhanced Oil Recovery. Technical Report 2009-12. 2009 [6] Kemp AG., Sola Kasim A. The Economics of CO2-EOR Cluster Developments in the UK Central North Sea / Outer Moray Firth. In North Sea Study Occasional Paper. 2012 [7] Shaw J., Bachu S. Screening, evaluation, and ranking of oil reservoirs suitable for CO2-flood EOR and carbon dioxide sequestration. Journal of Canadian Petroleum Technology. vol. 41 (9). 2002 [8] Norwegian Environment Agency. Climate mitigation measures and emission trajectories up to 2030 – Summary. Report M-415. 2015 [9] Norwegian Petroleum, http://www.norskpetroleum.no/en/framework/petroleum-tax/. Cited 27.09.2016 [10] EY. Global oil and gas tax guide 2015. http://www.ey.com/Publication/vwLUAssets/EY-2015-Global-oil-and-gas-tax-guide/$FILE/EY2015-Global-oil-and-gas-tax-guide.pdf. [11] Gavenas E., Rosendal KE., Skjerpen T. CO2-emissions from Norwegian oil and gas extraction. Statistics Norway Research Department. No. 806. 2015 [12] Meltzer S. Carbon dioxide enhanced oil recovery (CO2 EOR): factors involved in adding carbon capture, utilization and storage (CCUS) to enhanced oil recovery. U.S. 2012 [13] IEA. https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=RBRTE&f=D. Cited 27.09.2016 [14] Wintershall. Årsrapport til Miljødirektoratet for 2015 – Brage. 2015 [In Norwegian] [15] Norwegian Petroleum Directorate. FactPages – Brage. Cited 27.09.2016 [16] Offshore Technology.com. http://www.offshore-technology.com/projects/b8-oil-field-baltic-sea/. Cited 27.09.2016