The global energy system is changing, both to meet greater demand and to respond to environmental stresses. The big challenge for society is how to provide much more energy with much less carbon dioxide (CO2). CCS could deliver a significant contribution to the energy transition and climate-change mitigation, with the potential to deliver 12% of the required mitigation by 2050. CO2 emissions can be captured from large emitters such as power plants and industry and stored permanently and safely underground. Engagement and cooperation with different stakeholder groups is central to any CCS project, similar to other major projects in the oil and gas industry and elsewhere. However, engagement on CCS faces additional challenges because it is a new, unknown industry without many references.
The global energy system is changing, both to meet greater demand and to respond to environmental stresses. The big challenge for society is how to provide much more energy with much less carbon dioxide (CO2). CCS could deliver a significant contribution to the energy transition and climate-change mitigation, with the potential to deliver 12% of the required mitigation by 2050. CO2 emissions can be captured from large emitters such as power plants and industry and stored permanently and safely underground. Engagement and cooperation with different stakeholder groups is central to any CCS project, similar to other major projects in the oil and gas industry and elsewhere. However, engagement on CCS faces additional challenges because it is a new, unknown industry without many references. In light of this, any CCS project developer has the role of devoting specific attention to stakeholder concerns and needs in order to clarify the value of CCS, remove uncertainty, and create trust in the technology. Stakeholders have been engaged in two recent CCS projects, Quest CCS in Canada, which is now operating, and Peterhead CCS in the UK, which completed front-end engineering and design (FEED) before being stopped in 2015 following the withdrawal of potential funding. Both projects put considerable effort into developing effective and targeted stakeholder-engagement initiatives to build a strong and continuous relationship with the different key stakeholders and address their specific concerns.
ABSTRACT: CO2 sequestration in aquifers or depleted oil and gas fields depends on good injectivity, which is not decreasing over time, to achieve the target storage capacity of the chosen reservoir. Depending on the mineral composition of the rock formation into which CO2 is planned to be stored, dissolution of certain cement minerals at grain contacts can occur. These minerals are then free to be transported further along connected pores, until they get trapped, either due to constricted pore throats or decreasing velocity field. A simple conceptual model is presented here whereby dissolution and deposition mechanisms are related to the injection velocity, the pore throat size distribution in a feedback loop potentially creating conditions for fractures to occur. Tuning of the chemical processes in terms of timescale compared to the flow velocity and pressure changes leads to different fracture patterns.
In order to contribute to the Paris agreement goal of maintaining average global temperature rise below 2 °C, sequestration of CO2 will be a major measure, representing 13 % of the available measures to reduce emissions to the atmosphere by 2050 (IEA, 2015). To play its intended role, CCS needs to use most if not all identified available pore space in depleted oil and gas fields and aquifers around the world. This includes many different rock formations, where the principal high-permeability lithologies earmarked for storage are carbonate (Smith et al., 2013; Rohmer et al., 2016) and sandstone formations (Bertier et al., 2006; Hangx et al., 2013; Cerasi et al., 2016; Falcon-Suarez et al., 2017). For aquifer storage, the injected CO2 will inevitably mix with resident brine, leading to a reduction in the pore fluid pH (Andre et al., 2007; Wigand et al., 2008). This in turn causes dissolution of certain minerals, either coating some of the constituent grains, or cement material at grain contacts (Wang and Jaffe, 2004; Shao et al., 2010). Reduction in the solid skeleton mass locally increases the porosity, which affects the fluid velocities and pressure gradient (subject to current boundary conditions). These minerals then raise the pH of the solution flowing onwards, which at some point may lead to precipitation, with opposite consequences on local porosity and fluid flow velocity (Bacci et al., 2011). Fines from clay-like grain coating or grain cement can also physically clog narrow pore throat, given that the pore size distribution may evolve with distance from the injection well. Variation in the pore throat structure with distance from the well, associated with exposure to CO2 can destabilize the flow and encourage fingering (Espinoza and Santamarina, 2010).
IPCC's Fifth Assessment Report (published April 2014) - Compares with 445-490 ppm giving likely rise of 2.0-2.4 Source: A Picture of CO2 Storage in the UK - learnings from ETI's UKSAP and derived Projects, ETI, June 2013 ETI Appraisal of Sources and Potential Sinks of CO2 Around North Sea (Amounts in late 2020s) Ameren), retrofit oxycombustion at 229 MW coal plant, 1.1 million tonnes CO2 per year captured, aquifer storage, under construction, operational 2017
ABSTRACT: Up to 2015, about 5 million metric tons of CO2 have been injected into the Lower Tuscaloosa sandstone at Cranfield field, Mississippi. Pressure monitoring at one injection well shows that the bottom-hole pressure did not increase with the imposed injection rates as expected. Above the injection zone, pressure gauges measured a change of pore pressure of approximately 0.1 MPa in the absence of leaks. These two unexpected responses during the injection suggest potential geomechanical events induced by CO2 injection. We conducted triaxial tests in Tuscaloosa sandstone rock samples with CO2-acidified brine in order to understand chemo-poromechanical processes that may have contributed to these unexpected responses. Experimental results include measurements of permeability, relative permeabilities, quasi-static and dynamic elastic moduli, Biot coefficient, and chemically-induced creep at in-situ reservoir stresses. Results show a marked anisotropy in transport properties originated from features up to the scale of a few millimeters. Rock samples exhibited significant plastic strains upon loading and yield stress consistent with current burial depth. Creep rate increases more than one order of magnitude after CO2 injection. Chemically-induced creep deformation seems insufficient to cause significant reservoir compaction but may have contributed to horizontal stress relaxation.
Carbon dioxide (CO2) geological storage can help reduce CO2 emissions by disposal into depleted hydrocarbon reservoirs and deep saline aquifers. However, injecting large amounts of CO2 at high injection rates may upset the geomechanical equilibrium of the host formation. CO2 has been injected for CO2 enhanced oil recovery (4.5 million metric tons of CO2) and geological storage (0.5 million metric tons of CO2 in the water leg) at Cranfield site in Mississippi (Southeast Regional Carbon Sequestration Partnership - www.secarbon.org). CO2 injection and storage in the water leg used one injection well (CFU31F-1) and two monitoring wells (CFU31F-2 and CFU31F-3) (Lu et al., 2012a; Butsch et al., 2013; Hovorka et al. 2013).
Shell is progressing a portfolio of commercial-scale carbon capture and storage (CCS) demonstration projects covering an array of technologies that target applications of close relevance to the wider oil and gas industry. The portfolio includes projects such as Peterhead, Quest, Technology Centre Mongstad and Gorgon. A number of key learnings on both the technology deployment and critical project development aspects for the different project phases have been obtained. This paper provides an overview of these learnings with a specific focus on the issues faced by CCS project developers.
CCS is currently recognised as the only technology available for mitigation of carbon emissions from large-scale fossil fuel use. Before the process can be widely adopted it must be demonstrated at scale end-to-end. Learnings for all different project phases from early assess through to operations of these demonstrators need to be captured and communicated. As additional facilities to existing hydrocarbon operations, CCS projects require an approach similar to the development of other oil and gas projects.
To help enable and support other CCS projects, Shell is also committed to knowledge sharing from the projects, often agreed as part of the Knowledge Management provisions of the projects.
One of the key observations provided from the demonstration portfolio is the need for regular and informative engagement with both the public and regulators as the project progresses. Early and successful demonstrations can provide the evidence required for regulators, project developers and the public to have the confidence to proceed with future CCS projects.
It is also recognised that cost reduction will be key in driving commercial ‘deployability’ of CCS. The Quest and Peterhead projects are ideally placed to enable follow-on projects to learn and further reduce costs. The Shell portfolio of projects has also demonstrated that the drivers for technology optimisation can differ depending on the end user of the CCS technology. There is a need to demonstrate different technology aspects, for example flexibility or availability.
This talk will focus on how these issues are being addressed in two of the different projects within the Shell CCS portfolio, and highlight the key lessons learned. Furthermore, the cost-related issues of CCS will be addressed.
Adam, Ludmila (University of Auckland) | MacFarlane, Jackson (University of Auckland) | van Wijk, Kasper (University of Auckland) | Shragge, Jeffrey (University of Western Australia) | Higgs, Karen (GNS Science)
Time-lapse seismic signatures can be used to quantify fluid saturation and pressure changes in a reservoir. This is why seismic surveys are often acquired over fields where carbon dioxide is injected for underground storage, or to enhance oil recovery. In either scenario, the injection of CO2 acidifies the water, which may dissolve and/or precipitate minerals. Understanding the impact on the rock frame from field seismic time-lapse changes remains an outstanding challenge. Here, we study the effects of carbonate-CO2-water reactions on the physical properties of rock samples with variable levels of carbonate cementation, and how these effects translate to the elastic wave properties. Using a high-density laser-ultrasonic setup we observe that P-wave velocity changes range from +1.5% to -19% and correlate to sandstone grain size and porosity. To put this in perspective, this velocity change is comparable to the effect of fluid substitution from brine to CO2. This can potentialy create an ambigity in the interpretation of the physical processes responsible for time-lapse signatures in a CO2 injection scenario.
Carbon dioxide geosequestration is a proposed method to enhance hydrocarbon production while reducing its emissions into the atmosphere (Hepple and Benson, 2005; Bachu, 2003; Armitage et al., 2013; Dodds et al., 2009; Litynski et al., 2009). In these projects, monitoring the movement of the CO2 plume with geochemical, and in most instances, geophysical methods will be crucial to ensure the safe storage of this fluid in the subsurface.
As most rocks in the subsurface are water-saturated, the injection of carbon dioxide into a reservoir forms carbonic acid. This complicates the dynamics of these reservoirs as carbonic acid will react with the rock frame, changing the petrophysical and geochemical rock and fluid properties (Ross et al., 1982; Kharaka et al., 2006; McGrail et al., 2006; Pruess et al., 2003). Such rock-fluid interaction can result in mineral dissolution (Armitage et al., 2013; Vialle and Vanorio, 2011; Grombacher et al., 2012; Pimienta et al., 2014), precipitation (Oelkers et al., 2008; Wigand et al., 2008; Vialle and Vanorio, 2011; Adam et al., 2013), or, in some instances, produce no significant rock frame changes (Lebedev, 2013; Hangx et al., 2013). Commonly, these changes result from the dissolution and precipitation of carbonate, evaporite and clay minerals (Noiriel et al., 2004; Luquot and Gouze, 2009; Vialle and Vanorio, 2011; Grombacher et al., 2012; Pimienta et al., 2014). Ultimately, the physical properties of rocks resulting from mineral- CO2 interaction, such as porosity and permeability (Noiriel et al., 2004), may be picked up by remotely sensed seismic waves. Therefore, the changes should be calibrated in the laboratory, in terms of the changes seen in elastic waveforms.
Bennett, S. M. H. (Shell Global Solutions Inc.) | Boersma, D. M. (Shell Global Solutions International B.V.) | Goodyear, S. G. (Shell Global Solutions (UK)) | Maas, W. P. (Shell Global Solutions International B.V.) | Shahin, G. T. (Shell Global Solutions Inc.) | Winkler, M. (Shell Global Solutions Inc.)
As the major fields which have been the mainstay of global production mature there is a need to apply new technology and recovery techniques to extend field life and maximize economic recovery. As a result, there is growing interest in EOR. For the light oil reservoirs in the Middle East this leads to consideration of two main technology groups: miscible gas injection and chemical flooding. However the relatively high reservoir temperatures and salinity and the shortage of low cost hydrocarbon gas in many countries has so far restricted the application of EOR. The two main technology groups require different solutions to create commercial EOR systems suitable for application in the region and this paper maps out the key barriers and how they may be overcome.
For gas injection, while there are significant differences in the subsurface conditions compared to many existing projects, the key issue is the availability of miscible gas at an acceptable price for EOR. Many countries are hydrocarbon gas short, and those with the capacity to export have access to high prices through LNG or GtL value chains. The focus for gas injection is therefore the use of CO2, which is relatively abundant in anthropogenic emissions, but generally expensive to capture. Value chains linking industrial sources of CO2 to appropriate field targets are expected to be the key enabler of CO2 EOR, initially from niche sources. Robust technical and non-technical integration across the capture-transport-injection chain is required, to ensure that the potentially competing operational requirements for capture and EOR usage are reconciled, and that commercial and regulatory considerations are addressed. Existing and emerging CO2 capture options will be described and illustrated with experience from the development of CO2 value chains for projects such as Boundary Dam, Quest and Peterhead.
For chemical injection the principal challenge to overcome is the impact of the harsh reservoir conditions due to temperature and high salinity, compounded with the impact of carbonate lithology in many of the major reservoirs in the region. The development of enhanced waterflood techniques in which the TDS and ionic composition of the injected water is manipulated may give incremental benefits in itself, and also create more amenable conditions for follow-up chemical flooding. The challenge of effective sweep with modified brines, given the viscosity and density differences relative to formation brine, requires careful assessment. New polymers and surfactants are expanding the technical window of opportunity, currently chemical EOR in these environments is still commercially challenged.
EOR technology to allow cost effective recovery of remaining oil saturations after waterflooding will eventually have large scale application in the region. Both technology groups have the potential to deliver this prize, but by following different development thrusts, focusing on the surface capture issues for CO2 and the subsurface issues for chemical flooding. In the coming decade technology development and piloting in the field will show the likely scale of future application of the different EOR technologies. An integrated system approach to miscible gas and chemical EOR highlights the key technology challenges and provides a roadmap to develop commercial EOR systems.
The Girls in Energy course is an important part of Shell's STEM education programme; providing young women with the information and inspiration they need to pursue a career in the energy industry.
Every year, the UK faces a shortfall of over 81,000 people with engineering skills. Between 2010-2020 Scotland will need to recruit 160,000 people with engineering skills. To meet this demand Scotland needs to increase the number of graduate and apprenticeship engineers.
To help meet the demand, we developed the Shell Engineering Scheme in 2002 to help recruitment Technicians for the St Fergus Gas Plant, in the North East of Scotland. The bespoke scheme delivers training that allows them to enter the energy sector. However, in 2009 we received no applications from females for the course. Recognising this needed to be addressed, we developed the Girls in Energy course with North East Scotland College (NESC) to encourage more females into the industry to meet the growing skills shortage.
In 2010 we started the Shell Girls in Energy programme. It's a one year course, delivered by NESC, designed to open young women's eyes to the energy industry's wealth of career opportunities. It is targeted at girls aged 14–16 in secondary education, and when completed they will receive a (Scottish) National Qualification in Energy.
Before starting the programme many had thought that a job in the industry meant working on a platform in the middle of the North Sea. The course helps students to rethink these preconceptions and show them that there are a huge number of different careers available both offshore and onshore all over the world.
Girls in Energy pupils get to understand the future energy challenge including some of the pressing challenges we face in the world today and the role engineering plays in meeting the growing energy demand in a sustainable and innovative way.
Tutors from NESC deliver weekly lessons, workshops and field visits; providing 160 hours of engaging STEM education over the year-long course. Participants that successfully complete the end of course assessment receive an Intermediate 2-level qualification in Energy, This qualification, which was introduced by the Scottish Government to encourage students to study new subjects, provides an excellent grounding for working in the energy industry.
Shell is committed to increasing the pipeline of STEM professionals, especially among those groups, like women, that are under-represented in the energy industry. We are currently in discussions with Skills Development Scotland and Colleges Scotland about the best way to give more women the opportunity to learn about the value and opportunities available in the energy industry.
CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.