Time filter

Source Type

Grant
Agency: Cordis | Branch: FP7 | Program: CP | Phase: ENERGY.2010.5.2-3 | Award Amount: 5.31M | Year: 2011

CO2CARE aims to support the large scale demonstration of CCS technology by addressing the research requirements of CO2 storage site abandonment. It will deliver technologies and procedures for abandonment and post-closure safety, satisfying the regulatory requirements for transfer of responsibility. The project will focus on three key areas: well abandonment and long-term integrity; reservoir management and prediction from closure to the long-term; risk management methodologies for long-term safety. Objectives will be achieved via integrated laboratory research, field experiments and state-of-the-art numerical modelling, supported by literature review and data from a rich portfolio of real storage sites, covering a wide range of geological and geographical settings. CO2CARE will develop plugging techniques to ensure long-term well integrity; study the factors critical to long-term site safety; develop monitoring methods for leakage detection; investigate and develop remediation technologies. Predictive modelling approaches will be assessed for their ability to help define acceptance criteria. Risk management procedures and tools to assess post-closure system performance will be developed. Integrating these, the technical criteria necessary to assess whether a site meets the high level requirements for transfer of responsibility defined by the EU Directive will be established. The technologies developed will be implemented at the Ketzin site and dry-run applications for site abandonment will be developed for hypothetical closure scenarios at Sleipner and K12-B. Participation of partners from the US, Canada, Japan and Australia and data obtained from current and closed sites will add to the field monitoring database and place the results of CO2CARE in a world-wide perspective. Research findings will be presented as best-practice guidelines. Dissemination strategy will deliver results to a wide range of international stakeholders and the general public.


Zhang M.,Alberta Innovates Technology Futures | Bachu S.,Alberta Innovates Technology Futures
International Journal of Greenhouse Gas Control | Year: 2011

Carbon dioxide storage in geological media is a climate change mitigation technology that is based on the ability of certain geological media to retain CO2 in supercritical phase or dissolved in formation water and to prevent its return to the atmosphere for very long periods of time. However, in certain cases there are flow pathways, natural or manmade, conducive to CO2 leakage. Depending on their condition, existing oil and gas wells may provide such leakage pathways due to either mechanical defects developed during well drilling, completion and/or abandonment, or to chemical degradation of well cements and/or casing. In the case of CO2 storage, there is a concern that well cement in existing wells will degrade in the presence of water-saturated CO2 and/or CO2 saturated formation water/brine, thus creating new leakage pathways and compromising the integrity and security of CO2 storage. In this paper we review the status of knowledge in regard to the failure of existing wells, with special attention to the laboratory experiments, field investigations and numerical simulations carried out in the last several years in attempts to elucidate the behavior of well cements in the presence of CO2. Extensive carbonation has been observed in well cements in both laboratory and field studies. However, in CO2-rich environments, severe cement degradation is associated with the dissolution of calcite from the carbonated cement. This is not expected under typical geological storage conditions because CO2-saturated brine is likely in equilibrium with carbonate minerals that are present in virtually all formation rocks. © 2010 Elsevier Ltd.


Ivory J.,Alberta Innovates Technology Futures
Journal of Canadian Petroleum Technology | Year: 2013

Only 5-10% of the oil in Lloydminster heavy-oil reservoirs is recovered during cold heavy-oil production with sand (CHOPS). CSI is currently the most active post-CHOPS process. In CSI, a solvent mixture (e.g., methane/propane) is injected and allowed to soak into the reservoir before production begins (Fig. 1). CSI has been focused on heavy-oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by Nexen and Husky and was a fundamental part of the CDN40 million joint implementation of vapour extraction (JIVE) solvent pilot program that ran from 2006 through 2010. This paper describes field-scale simulations of CSI performed with a comprehensive numerical model that uses "mass-transfer" rate equations to represent nonequilibrium solvent-solubility behaviour (i.e., there is a delay before the solvent reaches its equilibrium solubility in oil). The model contains mechanisms to consider foaming or to ignore it, depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results. The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high-permeability zone, (2) a dual-permeability zone, (3) a dilated zone around the well, (4) wormholes (20-cm-diameter spokes) extending from the well without branching, and (5) wormholes extending from the well with branching from the main wormholes. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance. The impacts of grid size, upscaling, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared with when a delay in solvent dissolution and exsolution was allowed for. Increasing the gridblock size by a factor of nine reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%. © 2013 Society of Petroleum Engineers.


Bachu S.,Alberta Innovates Technology Futures
International Journal of Greenhouse Gas Control | Year: 2016

Carbon capture and storage (CCS) is a key technology which could be utilized to stabilize CO2 concentrations in the atmosphere. While all the components of integrated CCS systems exist and are in use today in the fossil-fuel extraction and refining industries, very few large-scale integrated CCS projects are currently in operation, due mainly to the high cost of implementation. For this reason, in the last few years the concept of CO2 capture, utilization and storage (CCUS) has been advanced, based on the premise that utilizing CO2 captured from anthropogenic sources, particularly in CO2 enhanced oil recovery (EOR) operations, would provide revenue that will, accordingly, reduce costs and facilitate deployment. When a large number of oil reservoirs are found in a particular region or jurisdiction, it is very difficult to ascertain which oil reservoirs are suitable for CO2-EOR by using detailed reservoir analysis and numerical simulations. In such cases, reserves databases may contain sufficient information to allow a region- or jurisdiction-wide identification (screening) of oil reservoirs suitable for CO2-EOR. Based on industry's experience to date with CO2-EOR, a set of 14 criteria has been developed to screen oil reservoirs in terms of their suitability for CO2-EOR, including operational and reservoir characteristics, and reservoir size. Using the published statistical analysis of the performance of 31 CO2-EOR operations in Texas, it is possible to estimate the incremental oil recovery factor and the net CO2 utilization factor for a given oil reservoir suitable for CO2-EOR, hence the incremental oil recovery and associated CO2 storage for that reservoir. In terms of CCUS, two additional screening criteria are introduced, which relate the size and location of large CO2 sources with respect to the location and potential CO2 storage capacity of a given oil reservoir suitable for CO2-EOR. If more than one oil reservoir meets these conditions for a particular large CO2 source, the reservoirs could be ranked using a weighted normalized parametric procedure that takes into account reservoir storage capacity in relation to the size of CO2 emissions from that particular source, the distance between the source and the reservoirs, and the depth of the reservoirs.The screening and ranking procedures for identifying oil reservoirs suitable for CO2-EOR and CO2 storage has been applied to Alberta, Canada, where there are close to 13,000 oil reservoirs recorded in the reserves database of the oil and gas regulatory agency. Application of the screening criteria identified 136 oil reservoirs in 85 oil fields that are suitable for CO2-EOR. The criteria that have the greatest impact on screening are oil gravity, minimum miscibility pressure and reservoir size. Second-order criteria in terms of impact are reservoir temperature and oil viscosity. Porosity and initial oil saturation have almost no effect, mostly because most reservoirs would normally satisfy these criteria. The cumulative incremental oil production at 2 HCPV injected CO2 in these 136 oil reservoirs is estimated to be 759, 1742 and 2858 MMSTB at P10, P50 and P90, respectively, with corresponding cumulative CO2 storage capacity of 213, 868 and 1742Mt CO2. Considering a maximum straight distance of 300km between any of the 38 large CO2 sources in Alberta and oil fields with reservoirs suitable for CO2-EOR, and a minimum storage capacity equivalent to 5 years of emissions leads to the identification of 29 oil fields that are suitable for both CO2-EOR and CO2 storage (i.e., CCUS).The methodology presented herein for screening oil reservoirs for CO2-EOR and CO2 storage can be applied to any region or jurisdiction in the world, possibly with some adjustments regarding some threshold values and weighting coefficients for reservoir ranking. © 2015.


Patent
Alberta Innovates Technology Futures | Date: 2016-04-06

Described herein is combination of flocculants for flocculating fines solids in a suspension thereof. The combination includes: (a) an anionic polymer flocculant, and (b) a charged particle-polymer hybrid flocculant that includes charged core particles having an average size between about 150 nm and about 800 nm and each having a polymer polymerized thereon. The anionic polymer flocculant is to be added before, or at substantially the same time as, the charged particle-polymer hybrid flocculant.


Patent
Alberta Innovates Technology Futures | Date: 2012-12-21

The present invention relates to polyamine-containing polymers and methods of their synthesis and use. The polymer may be hydroxyethylcellulose, dextran, poly(vinyl alcohol) or poly(methyl acrylate).


Patent
Alberta Innovates Technology Futures | Date: 2012-12-21

The present invention relates to polyamine-containing polymers and methods of their synthesis and use. The polymer may be hydroxyethylcellulose, dextran, poly(vinyl alcohol) or poly(methyl acrylate).


Patent
Alberta Innovates Technology Futures | Date: 2015-03-19

Described herein is a charged particle-polymer hybrid flocculant that includes charged particles having an average size between about 150 nm and about 800 nm and each having a polymer polymerized thereon. Charged particle-polymer hybrid flocculants are made by forming charged particles having an average size between about 150 nm and about 800 nm; and polymerizing a monomer on the charged particles to form the polymer. Fine solids are separated from a suspension thereof by adding the charged particle polymer hybrid to the suspension to produce floccules and a supernatant, and separating the produced floccules from the supernatant.


Patent
Alberta Innovates Technology Futures | Date: 2011-09-16

A system for recovering a fluid from a subterranean formation, including a production wellbore having a substantially horizontal production length extending through the formation, and a trench extending through the formation. A method of constructing a trench section in a subterranean formation, including providing within the formation an access wellbore having a substantially horizontal access wellbore length, introducing a trench cutting tool into the access wellbore, and advancing and retracting the trench cutting tool through the access wellbore in order to cut slots in the formation in a trench direction away from the access wellbore, repeatedly until a number of slots required to complete the trench section has been cut.


Patent
Alberta Innovates Technology Futures | Date: 2011-06-02

A charged particle polymer hybrid (CPPH) flocculant is taught, comprising sub-micron size charged particles and a polymer which has been polymerized in the presence of the charged particles wherein the intrinsic viscosity of the hybrid polymer flocculant is less than 930 ml/g. A method is provided for producing freely draining flocculated sediment from a suspension comprising finely divided solids in water. The method comprises dispersing, at increasing concentrations, a charged particle polymer hybrid (CPPH) flocculant into the suspension to determine a starting plateau concentration of CPPH flocculant above which concentration no further increase in the solids loading of the produced floccules is observed. Then, the concentration of dispersed CPPH flocculant in the suspension is maintained at or above the starting plateau concentration. A method is further provided for separating fine solids and water from a suspension comprising finely divided solids in water. The method involves dispersing, at increasing concentrations, a charged particle polymer hybrid (CPPH) flocculant into the suspension to determine a starting plateau concentration of CPPH flocculant above which concentration no further increase in the solids loading of the produced floccules is observed. Then, the concentration of dispersed CPPH flocculant in the suspension is maintained at or above the starting plateau concentration. The dispersion of CPPH flocculant in the suspension is agitated and the solid floccules are then separated from the supernatant liquid.

Loading Alberta Innovates Technology Futures collaborators
Loading Alberta Innovates Technology Futures collaborators