Northern Lights: Screening and maturation of CO2 storage prospectivity

Diego Vazquez Anzolaa, Renata Meneguolob & Silvia Kassoldb

a*
A/S Norske Shell, Tankvegen 1, 4056 Tananger, Norway
b
Equinor ASA, 4035 Stavanger, Norway
*Corresponding author (e-mail: diego.vazquezanzola@shell.com)

Abstract
The Northern Lights project is the transport and storage part of the world’s first full value chain CCS project
where CO2 from onshore industrial emitters will be injected and stored offshore, in the northern North Sea
(western coast of Norway). Storage resources, containment risks, information availability and development
costs are critical factors in the identification and maturation of a viable geological storage site, and are
challenging to objectively assess and compare for different geological storage concepts.
The subsurface candidates evaluated in the Northern Lights project included several geological storage
concepts such as a structural closure (Smeaheia), a depleted field (Heimdal) and a semi-regional sloping
saline aquifer (Aurora).
During the studies on the three potential storage sites, a workflow was created that incorporates a combination
of assessment parameters suitable for benchmarking, which supported the investment decision for the
Northern Lights CCS project by the three partners Equinor, Shell and Total.
Of the three candidates, the Aurora area represented the most prospective site because of its larger potential
for high resource scalability. Key data gaps were addressed by high-risk pre-investments in an exploration
well aimed at confirming and maturing the CO2 storage resources.
A set of tools are hereby proposed to highlight uncertainties, risks and opportunities when screening and
ranking CO2 prospective storage sites. These tools are to be considered an ever-green and evolving
philosophy, which form the foundation of what is considered most relevant when screening and building a
portfolio of prospective CO2 geological storage sites.

First words methodologies this article aims to propose a set of

tools to highlight uncertainties, risks and opportunities
In order to mature reliable geological storage sites, in when screening and ranking CO2 prospective storage
terms of sufficient storage resources, manageable risks site.
and development costs, a consistent set of screening
criteria are necessary. These criteria are to be It is recognized that the tools hereby proposed are
implemented as ranking tools aimed to complete a strongly inspired by the experience of the Northern
thorough prospectivity evaluation for CO2 geological Lights subsurface team, which carried out a detailed
storage resources before any investment of resources, analysis of three (3) very different prospective CO2
including manpower, is decided. storage sites. These tools are by no means finalized or
completed but are considered an ever-green and
Ringrose (2020) provides an overview of previous evolving philosophy aiming to form a foundation of
publications associated to “Site integrity and risk what is considered most relevant when screening and
management” of CO2 storage projects. Publications building a portfolio of prospective CO2 geological
such as the IEAGHG (2009) report and Pawar et al. storage sites.
(2015) define a risk management framework that is
extremely useful to describe, manage and Despite the screening parameters or criteria taken
communicate site specific risks and mitigation into consideration are often intertwined and
plans. Finally, estimation of the storage volumes interdependent, this article is an attempt to
(resources) has been defined for different storage categorize and streamline a systematic process to
types (Thibeau et al., 2014, Bachu et al., 2007). evaluate potential CO2 storage sites.
However, these are not complete or appropriate to
identify and screen suitable geological sites for CO2
storage. Given the lack of specific established
Northern Lights: A full-scale CCS project Mt/y, with the remaining capacity planned to be made
available to third parties.
In a Decarbonization and Energy Transition world,
Carbon Capture and Storage (CCS) is a proven Upscaling ambitions involving a design capacity of 5
technology that is highly needed to meet the emissions Mt/y of CO2 is planned for Phase 2, which will require
reduction commitments of the Paris Agreement. This additional investment in onshore storage tanks, wells,
is clearly reiterated in relevant CCS related pump capacity and quays. The present subsea system
publications such as Tucker (2018) and Ringrose can be expanded to include up to five (5) injection
(2020). wells in total.

The recent sanction of the Northern Lights project by Prospective CO2 storage portfolio pre-sanction
the three (3) partners (Equinor, Shell and Total) is
considered a success story of an emerging and very Halland et al. (2011) provide an excellent starting
complex business model that is key for the future point for a high-level screening of potential CO2
strategic position of the Energy sector in the transition storage resources in the Norwegian Continental Shelf
to a decarbonized industry. (NCS). For the Northern Lights project in specific,
three (3) prospective CO2 storage sites were assessed
The intention of the Northern Lights project, is to (Figure 2), encompassing a range of concepts such as
build a strong partnership with the Norwegian structural closures (Smeaheia), depleted gas fields
government to contribute in their shared ambition to (Heimdal), and a sloping semi-regional aquifer
build a CCS project that would stimulate the (Aurora).
necessary development of CCS so that long-term
climate targets in Norway and the European Union Figure 2 illustrates the position of the investigated
can be attained at a lowest possible cost. prospects in the northern North Sea, as well as the
location of the temporary storage site onshore
The Northern Lights project scope includes ship (Naturgassparken).
transport, onshore temporary storage, pipeline
transport to an offshore injection well, and injection of
CO2 for storage in the Aurora site, within the
Exploitation License 001 (EL001). A full chain
schematic is shown in Figure 1 and the locations of
the onshore facility, pipeline and injection well are
shown in Figure 2.

Fig. 1. Northern Lights full chain schematic.

A phased development is planned, starting with a

Phase 1 design capacity of 1.5 Mt/y of CO2 one (1) to
two (2) injection wells, and a planned injection period
of 25 years, starting from mid-2024. Initially,
Northern Lights is planned to receive
receive CO2 from capture sites located in South- Fig. 2. Northern Lights portfolio pre-sanction.
Eastern Norway, amounting to approximately 0.8 Location of the assessed potential storage sites in the Northern
North Sea, west coast of Norway.
The three (3) assessed prospective CO2 storage sites
(Figure 3) are different in terms of storage concept The Heimdal gas field is a four-way structural trap
and therefore presented different challenges and located in the northern North Sea and has been
degree of data availability, fundamental to assess the producing for almost four (4) decades from the ~300
primary and secondary storage units. m thick sandstone-dominated Paleocene Rogaland
Group (deep-water turbiditic Heimdal Formation,
The stratigraphic column in Figure 4 summarizes the Dalland et al., 1988). Currently it is in its tail phase,
potential reservoir storage units and main seal systems producing from one (1) of the 12 existing
for the prospects investigated. development wells. The primary seal is defined the
overlying mudstone-dominated upper parts of the
Lista Formation (Zweigel, 2018). The secondary seal
is provided by the shales of the Hordaland Group.

The Aurora area is a semi-regional sloping saline

aquifer down-dip to the giant Troll hydrocarbon fields
Fig. 3. The three (3) assessed prospective CO2 storage sites, (Figure 2). The stratigraphic storage interval is the
including a structural closure (Smeaheia), a depleted gas field Early Jurassic Dunlin Gp., characterized by high-
(Heimdal), and a semi-regional sloping aquifer (Aurora). energy sandstone wedges (Johansen and Cook
formations) encased in marine shales (Amundsen and
The Smeaheia area is characterized by structural Drake fms - Vollset and Doré, 1984). Due to its deep
closures proven dry by legacy exploratory wells. The stratigraphic position, several overburden units can
stratigraphic unit identified for storage is the Upper serve as secondary and contingency seals. The
Jurassic Viking Group, which includes well-known suitability of the Dunlin Gp. for CO2 storage has
reservoir rocks (high-energy shallow marine previously been addressed by Sundal et al. (2013)
Sognefjord, Fensfjord and Krossfjord fms - Vollset and Sundal et al. (2016).
and Doré, 1984) capped by shales of the Heather and
Draupne fms, the latter forming a semi-regional cap Besides the different stratigraphic settings and
rock. The storage units and seals are proven in the geometrical configurations, the three (3) storage
area by the two existing wells, drilled in 1996 and concepts differ largely in terms of data availability
2008. Several secondary seals in the overburden were and subsequently in degree of subsurface uncertainty.
also proven in the area by these legacy wells. This can represent a crucial factor in the evaluation of
a storage site.

The Heimdal depleted field presents a dataset of

multiple well penetration and dynamic information,
while two (2) exploratory wells were present in the
Smeaheia area at the time of evaluation, with different
degree of data availability (including 55 m of core in
well 32/4-1 T2, Figure 2). In the other end of the
range, Aurora is a largely under-appraised area with
the closest well penetration of the primary storage
units ca. 18 Km away, in the Troll area. Within
EL001, well 31/8-1 was drilled in 2011, however did
not penetrate the Dunlin Group.

Subsurface core activities for screening and

evaluating CO2 storage resources

Development and appraisal of CO2 storage resources

requires contributions from geology, geophysics, and
other subsurface disciplines, combined with a
thorough integrated containment risk assessment,
Fig. 4. Stratigraphic column highlighting the storage reservoir
which results in a risk-based monitoring plan.
units and seal systems for the prospective CO2 storage sites Together, these subsurface disciplines are required to
investigated.
mature CO2 storage resources from prospective to complex. This is done through a comprehensive
marketable capacity. overburden assessment, which incorporates the
characterization of the main seal and any other
The subsurface activities involved in any CO2 storage geological sealing systems. The traditional oil & gas
assessment can be subdivided into 3 main core overburden and geohazards assessment workflows,
activities (Figure 5). including identification of escape features, shallow
faults and permeable zones, are fundamental.

The characterization of the geological seal must also

incorporate potential geochemical and geomechanical
variations with the presence of CO2 in the reservoir
Fig. 5. CO2 Storage screening and maturation. The 3 Core
storage units through time.
Activities for CO2 storage assessments.

Core Activity I – Storage Resources & Scalability: The IEAGHG (2009) report and Pawar et al. (2015)
define a risk management framework that indicate that
This core activity includes the characterization of the the way risks are communicated is as relevant as it is
reservoir storage units using rock properties from to manage them.
available well data. The use of seismic data and
geological concepts are determinant, particularly In response to this necessity, Pawar et al. (2015),
where well data is scarce, e.g., in semi-regional Bourne et al. 2014 and Tucker et al. (2013) have
sloping saline aquifers, which are not targeted by proposed the ‘’bowtie’’ approach as an extremely
hydrocarbon exploration. useful tool to summarize and communicate any
geological and man-made (i.e., legacy wells)
Traditional hydrocarbon exploration workflows, migration paths that could possibly lead to CO2
including building alternative geological models that flowing out of the pre-established licensed storage
match seismic observations and a probability of complex. This tool is also used to summarize and
success (POS) to find an injectable, laterally extensive communicate the assessed barriers effectiveness and
and monitorable reservoir, are fundamental. potential consequences and mitigations. The bow-tie
method has also been applied to the Smeaheia and
In order to maximize storage resources, and optimize Aurora containment risk assessments, the latter is
utilization of the planned or existing infrastructure, the described in Vebenstad et al. (2021).
rate of capacity increase, or scalability, is most
relevant. The relevance of legacy wells when selecting an
appropriate CO2 storage side has been particularly
Scalability is defined as the ability to increase storage highlighted by Tucker (2018).
and/or injection capacity with additional injection
well(s), for a determined period of time. High levels Core Activity III – Costs & Risk mitigation: This
of scalability are achieved by high sustained subsurface core activity includes elements associated
injectivity per injector well, which is only possible to CO2 transport (e.g., pipelines, shipping), but also to
with a large connected pore volume. the number of wells required to reach a sustained
injection rate required to build commercial
Addressing pore connectivity implies the investigation agreements. These wells could be new or re-utilized.
of the aquifer dynamic behaviour, including time-
dependent effects on injectivity, containment and Moreover, considerations of additional investments
ultimately on storage resources. for data acquisition (e.g., exploratory or appraisal
well), but also other efforts or studies affecting
Confident estimations of CO2 storage resources & maturation time, are considered part of a risk
scalability are key inputs to define committable and mitigation plan and associated costs.
marketable volumes required to build commercial
agreements. A risk mitigation plan includes building a Storage
Complex Monitoring (SCM) plan that incorporates
Core Activity II – Containment Risk assessment: activities to ensure containment (storage safety) and
This core activity includes the identification of conformance (storage effectiveness) by monitoring the
potential CO2 migration paths out of the storage CO2 plume using proven technologies. In addition, the
SCM plan incorporates necessary response actions to Other criteria such as the abandonment condition of
address any concern related to conformance and legacy wells, fault reactivation risk, natural or induced
containment. seismicity, are considered essential input that define
the Risk factor.
Site-specific feasibility studies for borehole and
surface geophysical monitoring technologies form an Additional criteria associated to Risk that are usually
important basis for the SCM plan, including desirable but not always fundamental can be the
applicability of methods such as seismic, gravimetry, presence of a structural closure, or hydraulic isolation
and controlled source electromagnetic. from nearby hydrocarbon producing reservoirs.
Hydraulic communication with freshwater resources,
A complete SCM plan is required to build trust and or any interference with other human activities, can be
meet requirements authorities and other relevant naturally considered showstoppers, particularly for
stakeholders. Logically, a risk-based SCM plan must onshore storage sites.
also be cost effective, hence the close link between
Costs and Risk mitigation. In terms of the Cost factor, the below screening
criteria are defined based on the core activity III –
Screening criteria Costs & Risk mitigation.
Different screening criteria have been defined
covering the above-mentioned subsurface core ➢ Distance to existing infrastructure or CO2 source,
activities of a CO2 storage assessment. In order to ➢ New injectors / legacy well re-utilization,
estimate Storage Resources & Scalability (core ➢ Legacy wells requiring intervention.
activity I), beyond the static pore space volume, the
below criteria are considered critical, i.e., if they are The distance to existing infrastructure or CO2 source
insufficient or not present it would result in a serious could directly affect the engineering concept for CO2
red flag on the prospective CO2 storage site: transport, which is logically linked to the Cost factor.

➢ Injectivity, Moreover, the number and complexity of new wells

➢ Connected pore volume. needed to maintain a contracted injectivity, or the
number of legacy wells that might need to be
These two (2) criteria define the ability to maintain a intervened to avoid possible CO2 flow leading to
minimum injectivity for a determined (long) period of emissions to the water column or the atmosphere, can
time, which is key for any CO2 storage site at an quickly turn into a showstopper for any prospective
industrial scale. CO2 storage site.

Other criteria such as the presence of baffling or A less critical but essential criterion to be considered
sealing faults, pressure regime, water salinity or is the potential of re-utilizing existing infrastructure.
presence of hydrocarbons, are also relevant aspects In addition, the behaviour of the mobile CO2 plume,
associated to Storage Resources & Scalability. whether it is expected to be constrained within a
limited area or not, could significantly affect the costs
On the other hand, for the Risk factor, the screening of the SCM plan.
criteria below are considered critical, i.e., not being
present or insufficient would result on a serious red All of the screening criteria introduced are heavily
flag on the prospective CO2 storage site. depending on the Data Availability in the potential
storage site in order to make a sound subsurface
➢ Caprock Integrity / bounding fault seal capacity, assessment. This includes a confident definition of
➢ Monitorability. storage resources and a realistic assessment of the risk
picture, which might result in additional investments
These two (2) criteria are combination of elements of necessary to improve data availability.
core activity II - Risk assessment (e.g., containment
risk) and core activity III – Costs & Risk mitigation Business attractiveness
(e.g., SCM plan or legacy well intervention plan),
which results in a holistic view of the residual risks The Business Position or Business Attractiveness of a
associated to the prospective CO2 storage site. CO2 geological storage site depends upon different
cost-benefit factors, that in the Northern Lights project
could be approximated to the following relationship:
 Precambrian basin, gives clear warning signs in terms
𝑆𝑡𝑜𝑟𝑎𝑔𝑒 𝑅𝑒𝑠𝑜𝑢𝑟𝑐𝑒𝑠 & 𝑆𝑐𝑎𝑙𝑎𝑏𝑖𝑙𝑖𝑡𝑦
𝐴𝑡𝑡𝑟𝑎𝑐𝑡𝑖𝑣𝑒𝑛𝑒𝑠𝑠 = 𝑅𝑖𝑠𝑘 𝑥 𝐶𝑜𝑠𝑡
(1) of containment risks.

Storage Resources & Scalability, Risk and Cost define

a series of screening criteria based on the above
described subsurface core activities that are
most relevant to rank prospective CO2 storage sites.

A thorough Risk assessment is required (core activity

II) in order to establish risk based and cost-effective
plans as SCM (core activity III). The Risk factor in the
Business Attractiveness relationship (1) is effectively
the estimated residual risk, taking into account a
mitigation plan. Consequently, this means that the
Risk and Cost factors are closely related.

Maturation and Business Attractiveness of

investigated storage sites Fig. 6. Regional map of the Horda Platform, offshore Norway,
with Aurora and Smeaheia prospective CO2 storage sites in the
For the Northern Lights project, a Phase 1 capacity of vicinity of the Troll field. Main fault zones and most important
pressure communication links (orange arrows) are shown.
1.5 Mt/y has been defined, with an injection period of Fault traces are mapped at top Sognefjord Formation. From
25 years. A Scalability plan includes a design capacity Wu et al. (2019).
of 5 Mt/y of CO2 for Phase 2, which will require
additional investment in onshore storage tanks, wells, The main injection target are the main producing
pump capacity and quays. This could lead to the reservoir units in the giant Troll field (Viking Gp.
maturation of additional prospective CO2 storage sites. sandstones – Figure 4). Fault seal analysis of the relay
ramps along the Vette Fault zone (Figure 6) shows
Smeaheia dry structural trap: The Smeaheia area is that the Smeaheia area could easily be affected in the
the nearest prospective CO2 storage site to the onshore future by the pressure drawdown from Troll
facility at Naturgassparken (~50 Km pipeline – Figure production (Lauritsen et al., 2018 and Wu et al.,
2). 2019). Uncertainty in the timing of the pressure
recharging potential from the seabed (through
There is one (1) dry exploration well on each Alpha Quaternary sediments and Øygarden fault) is a key
and Beta structures, which are 15 Km apart (Figure 6). added element of uncertainty to the CO2 Storage
Data availability for reservoir characterization of the Resources & Scalability in this prospect.
storage unit is therefore a key strength of this
prospect. Moreover, the abandoned dry well in the Alpha
structure (32/4-1T2) may require future investments to
The Smeaheia area was initially considered most ensure CO2 containment.
attractive due to its proximity to the temporary CO2
storage facilities onshore (Figure 2). Nevertheless, the Smeaheia estimated Storage Resources & Scalability
maturity of the containment risk assessment, including might increase if stratigraphically deeper storage
status of the abandoned legacy wells, as well as units and other structural closures can be
expected dynamic effects affecting the injected CO2 in incorporated. For instance, a recent exploration well
the long term, diminished its attractiveness as a (32/4-3 S – Figure 2) drilled south of the Alpha
storage site with sufficient scope for scalability
structure (Figure 6) could add more value to
(Lauritsen et al., 2018).
Smeaheia as a CO2 storage site.
Lauritsen et al. (2018) and Wu et al. (2019) indicate
Making use of the relationship (1) and the above-
that the Øygarden fault, defining the Beta structure,
mentioned screening criteria, the estimated Business
outcrops at the seabed. This evidence does not
Attractiveness for Smeaheia as a CO2 geological
conclude on the current sealing capacity of this fault,
storage is considered to be Medium, due to a
but indicates a recent activity that, together with a
relatively low estimated Cost (pipeline length) but
juxtaposition profile against a likely fractured
also relatively higher Risk factors.
 screening criteria, resulted in the decision to invest on
Heimdal depleted gas field: Compared to other data acquisition and appraisal. More specifically:
prospective CO2 storage sites, the Heimdal gas field
(Figure 7) has a unique advantage in terms of data ➢ High perceived Storage Resources & Scalability:
availability: more than 30 years of production history semi-regional sloping saline aquifer expected, ideal
with evidence of a dynamic aquifer responding to for migration-assisted CO2 storage. Also, third
production from surrounding fields. A sizable result of party technical reviews and publications such as
storage resources within the trap and in the water leg, Gassnova (2013), Sundal et al. (2013)
and estimations of Scalability are therefore and Sundal et al. (2016), indicated sizable CO2
dramatically less uncertain than other types of CO2 storage resources.
storage sites. ➢ Low perceived Risk factor, i.e., good quality and
monitorable reservoirs in the Dunlin Gp. (Figure 4)
Previous studies have indicated its potential as a CO2 in Troll West, and a robust main seal ensuring long
storage site (Zweigel et al. 2018), indicating that re- term containment evidenced by the existence of the
use of existing wells ‘’proved to be difficult due to Troll mega closure.
their design and well status’’; i.e., new wells would be ➢ Relative vicinity to onshore facility
required. Naturgassparken (~100 Km pipeline – Figure 2).
Hence a relatively medium to low Cost factor.

Available pressure data in the area show that the

Viking Group is depleted due to Troll production,
with an extended pressure pulse seen by the southern
well 31/8-1 (2011), ca. 20 Km away from the Troll
field, inside EL001; the Brent Group is depleted
probably due to several fields in production and/or
due to hydraulic communication between the Brent-
Viking groups. Available pressure data acquired in the
Dunlin Group until 2012 indicated that there is no
pressure depletion observed, thus suggesting that the
Drake Formation claystones form a barrier between
Fig. 7. Map of the Heimdal gas field indicating its 12 the depleted Viking and Brent groups to the
development wells and nearby exploration wells. From
Zweigel et al. (2018). undepleted Dunlin Group.

A much larger distance to the onshore facilities Aurora data gaps: Given the uncertainties associated
(Naturgassparken), together with conclusions from to the expected reservoir properties, sand extension
more recent internal studies, resulted in a decision to and connectivity, but also associated to the
postpone the development of this storage site towards characterization of the overlying Drake Formation as
later stages of the Northern Lights project, particularly the main seal and possible hydraulic communication
due to the identification of possible integrity issues to the Troll field, an exploratory well was therefore
with two (2) of the legacy wells, which may require drilled and tested from December 2019 to March 2020
future investments to ensure CO2 containment. to address risks associated to:

Making use of the relationship (1) and the above- ➢ Sand presence and quality,
mentioned screening criteria, the estimated Business ➢ Monitorability,
Attractiveness for Heimdal as a CO2 geological ➢ Seal,
storage is considered to be Medium, due to a ➢ Ability to flow,
relatively high Storage Resources & Scalability but ➢ Connectivity,
higher Cost and Risk factors. ➢ Containment,
➢ Exposure to neighboring hydrocarbon bearing
Aurora semi-regional sloping saline aquifer: reservoirs.
Despite having significant uncertainties due to data
gaps, the expected high Business Attractiveness, based The estimated Business Attractiveness for the Aurora
on the relationship (1) and the above-mentioned storage site was considered sufficiently high to
warrant an additional investment, through an
exploratory well, to close significant data gaps.
 diminishing quality of the sandstone towards the top
The scalable way – 31/5-7 (Eos) well results: A of the Johansen Formation. Formation evaluation log
series of geological scenarios have been developed data, pressure mobility and core data showed excellent
pre-well and certain criteria have been set up to make quality of the sandstone units in the Dunlin Group
swift decision to decide on the success of the 31/5-7 which was confirmed during a production test in the
(Eos) exploration well and by that the success for the Johansen Formation that is interpreted to a Kh-product
continuation of the Northern Lights project within the (permeability multiplied with reservoir net thickness)
specified timeframe. These project acceptance criteria of 72 Dm and a radius of investigation of 2200 m –
were subdivided into the broad categories of seal, 3200 m without encountering any barriers (Table 2).
formation pressure and sand, including the sand lateral Given the good quality of the sandstones, the
extension and quality as well as the dynamic monitorability with 4D seismic is assessed to be
behaviour of the Johansen Formation as shown in feasible and the expectation is that CO2 can be
Table 1. monitored in layers down to 5-7 m thickness with
20% CO2 saturation.

Table 2. Reservoir properties of Cook and Johansen

formations including well test results.
Table 1. Aurora project acceptance criteria defined pre-well.

The data gathered in the 31/5-7 (Eos) exploration well

supported the expectations of the Drake Formation to
act as a reliable seal to ensure containment of CO2.
The sealing lower part of the Drake Formation (Drake
Formation 1) was encountered as a fairly homogenous
claystone with a thickness of 75 m. An extended leak-
off test (XLOT) was performed that confirmed the
sealing potential for future CO2 injection while
additional studies on the core in the Drake Formation
will further characterise the cap rock.

Formation pressure data was acquired from Viking,

Brent, Dunlin and Statfjord groups. The pressure data
confirms previous information from the area with
higher depleted formations in the Viking Gp. with
minor vertical baffles, and minor depletion in the
Brent Group also with vertical baffles to flow. The
Dunlin and Statfjord groups have been tested with
initial pressure, thus proving no hydraulic
communication of the Cook and Johansen formations
to the overlying Brent and Viking groups in the well
area. Fig. 8. 31/5-7 (Eos) well composite log in the Dunlin Gp.

The sand presence and its quality were highly Core descriptions and correlations with the Troll area
uncertain factors pre-drill due to the under-appraised were carried out to update and constrain the
nature of EL001. The 31/5-7 (Eos) well encountered depositional systems to be implemented into the static
both Cook and Johansen formations with 57 m and reservoir model. Based on core description, marginal
116 m thickness respectively. Also, the Johansen to shallow-marine systems with interplay of fluvial,
Formation contains mainly sandstone, with high tidal and wave processes, have been interpreted for
quality sandstone in the lower and middle part and the Cook and Johansen fms. The northwards extend of
the Johansen Formation in the Aurora area towards
Troll is not possible to prove with only one well.
Nevertheless, with the assessment of core data, log
correlation, assessment of seismic amplitudes and the
investigation radius from the well test, the connection
of the system from the 31/5-7 (Eos) well towards Troll
is given an increased likelihood and confidence.

The results of the exploratory well 31/5-7 (Eos)

strongly support Aurora as a suitable CO2 storage site
with a risk profile that is manageable by means of a
comprehensive Storage Complex Monitoring plan. Fig. 9. Screening criteria considered for the three (3) types of
assessed prospective CO2 storage sites: Smeaheia (dry
Screening criteria applied to the prospective CO2 structural traps), Heimdal (depleted gas field), and Aurora
storage sites investigated (semi-regional sloping saline aquifer).

Figure 9 shows a qualitative indication of how the Figure 10 compares the analysed types of prospective
analysed types of prospective CO2 storage sites may CO2 storage sites are positioned in terms of Business
generally rank when compared to each other. Attractiveness, as defined in the relationship (1). It is
also highlighted how relevant Data availability is in
This screening tool is developed from the Aurora order to close gaps linked to estimations of
project acceptance criteria (Table 1), joint with attractiveness. Error bars indicate that a detailed
learnings from the assessments done over Smeaheia assessment of each prospective CO2 storage site is
and Heimdal areas. The tool is based on an ‘’Evidence crucial to determine a Business Attractiveness with a
Support Logic’’ assessment, also known as ‘’Italian higher level of confidence.
flag’’, used to communicate the existence of evidence
in favor (green) or evidence against (red) meeting a
specific criterion. The ‘’white space’’ is used to
indicate uncertainty or data gaps.

It is evident that, before the 31/5-7 (Eos) well was

drilled, the Aurora storage site had the largest data
gaps and highest level of uncertainties. It also had the
highest upside for Scalability, lowest Risk and Cost
factors.

With the positive 31/5-7 (Eos) well results, the low

side of the Business Attractiveness range was lifted, in
particular due to the resulting higher level of
confidence on the Storage Resourses & Scalability
factor and a lower Risk. However, in relation to future
scalability, a relatively high level of uncertainty
(white space – Figure 9) still remains, since one (1)
data point cannot fully derisk a licensed area of ca.
1400 Km2. Fig. 10. Business Attractiveness VS. Data availability for the
three (3) types of assessed prospective CO2 storage sites:
The 31/5-7 (Eos) well information has provided a Smeaheia (dry structural traps), Heimdal (depleted gas field),
relevant basis for Northern Lights Phase 1 and Aurora (semi-regional sloping saline aquifer).
development, integrated with (i) understanding of the
regional geological setting, (ii) static and dynamic Figure 9 and Figure 10 are examples of screening
data collected from surrounding areas, and (iii) tools that can be incorporated into the prospectivity
seismic data covering EL001 license. ranking process of different types of CO2 storage sites.
Conclusions succession offshore mid- and northern Norway. NPD Bulletin,
4, 65 pp.
An analysis of CO2 storage prospectivity for the Gassnova, 2013. Geological storage of CO2 from Mongstad.
Northern Lights project has been presented. Three Interim report Johansen Formation.
types of prospective CO2 storage sites have been
Gassnova, 2013. Geologisk CO2 - Lager Johansen-
discussed in terms of their main strengths and formasjonen, GAP analyse iht. Statoils CVP DG2 process, Dok.
weaknesses. nr. 13/073-17.

Considerations have been presented regarding the Halland, E., Gjeldvik, I.T., Tjelta Johansen, W., Magnus,
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in CO2 geological storage. IEA Greenhouse Gas R&D
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Fifth CO2 Geological Storage Workshop Latest advances and
workflows for an efficient screening and ranking of the way forward. 21st-23rd November 2018 Utrecht, The
prospective CO2 storage sites. Different screening Netherlands.
criteria closely linked to the Business Attractiveness of
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advances in risk assessment and risk management of geologic
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Figure captions

Fig. 1. Northern Lights full chain schematic.

Fig. 2. Northern Lights portfolio pre-sanction.

Location of the assessed potential storage sites in the
Northern North Sea, west coast of Norway.

Fig. 3. The three (3) assessed prospective CO2 storage

sites, including a structural closure (Smeaheia), a
depleted gas field (Heimdal), and a semi-regional
sloping aquifer (Aurora).

Fig. 4. Stratigraphic column highlighting the potential

storage reservoir units and seal systems for the
prospective CO2 storage sites investigated.

Fig. 5. CO2 Storage screening and maturation. The 3

Core Activities for CO2 storage assessments.

Fig. 6. Regional map of the Horda Platform, offshore

Norway, with Aurora and Smeaheia prospective CO2
storage sites in the vicinity of the Troll field. Main
fault zones and most important pressure
communication links (orange arrows) are shown. Fault
traces are mapped at top Sognefjord Formation. From
Wu et al. (2019).

Fig. 7. Map of the Heimdal gas field indicating its 12

development wells and nearby exploration wells.
From Zweigel et al. (2018).

Table 1. Aurora project acceptance criteria defined

pre-well.

Table 2. Reservoir properties of Cook and Johansen

formations including well test results.

Fig. 8. 31/5-7 (Eos) well composite log in the Dunlin

Gp.