Bachu S.,Alberta Innovates Technology Futures
Energy Procedia | Year: 2013
One of the most important mechanisms for CO2 storage in deep saline aquifers is CO2 trapping at irreducible saturation, which depends on the relative permeability characteristics of CO2/brine systems. CO2 injectivity, pressure build-up and the evolution and long-term fate of the injected CO2 also depend on the same relative permeability characteristics. Predicting the fate of the injected CO2 using numerical models requires adequate relative permeability relationships for CO2/brine systems (both drainage and imbibition cycles), yet very few experimental data exist in the literature. Considering that CCS will be deployed on a large scale in western Canada, three experimental programs of determining the relative permeability characteristics at in-situ conditions of prospective storage aquifers have been successively run between 2003 and 2011. The first two programs focused on testing rocks from various deep carbonate and sandstone aquifers in central Alberta in the vicinity of several very large CO2 sources. The third testing program focused on measuring the relative permeability for CO2/brine systems at various locations in the sandstone Basal Aquifer that overlies the Precambrian basement in western Canada. The results of the first testing program, comprising 14 measurements, have been published in 2008. The results for relative permeability testing on eight additional carbonate rocks have been published in 2010 and combined with the results for five tests from the first measurement program to obtain generalizations for carbonate rocks. Results of new CO2/brine relative permeability measurements on 16 sandstone rocks from the second and third measurement programs are presented for the first time in this paper. These results are combined with results of testing on six sandstone rocks from the first measurement program, for a total of 22 tests, and are generalized similarly to the generalization for carbonate rocks published previously. The test data cover a very wide range of permeability values, from less than 0.1 mD to more than 500 mD. The generalizations in terms of relative permeability and residual saturation are defined based on rock characteristics that are routinely measured in core analyses, such as pore size and absolute permeability.
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.
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.
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).