We propose a new framework for energy policy on a national and global scale for exploring further advances of CO2-EOR that promotes a “triple-e” approach: (1) energy security, (2) environmental quality, and (3) economic viability. Increasing the use of CO2-EOR can reduce U.S. dependence on foreign oil, decrease greenhouse gas (GHG) emissions, create jobs, and help generate electricity to meet domestic demand. Understanding CO2-EOR and the opportunities and challenges it brings is therefore essential for both policymakers and consumers.
There are always two sides to a story, and carbon dioxide (CO2) is no exception. On one side, CO2 is presented as a greenhouse gas (GHG), and preventing its release drives the policy of some government agencies. On the other side, CO2 is an essential nutrient necessary for plant growth and, more recently, has been recognized in the energy sector as a valuable commodity to enhance recovery in utilization operations, such as CO2 enhanced oil recovery (CO2-EOR), enhanced gas recovery (CO2-EGR), and enhanced coal bed methane recovery (CO2-ECBMR).
CO2-EOR is a mature technology and currently generates around 300,000 barrels of oil each day in the United States. It is a contributing factor to the recent boom in U.S. oil, which has resulted in lower gasoline prices. However, CO2-EOR’s potential for energy security is largely untapped. Exploring new opportunities and technological improvements for increased CO2 storage in EOR operations can significantly increase the volume of its generated oil and improve applicability of technology as a revenue generator for CO2 capture and a large-scale CO2 storage option.
Energy security calls for comprehensive use of all of our nation’s energy sources, including fossil fuels. But fossil fuels, especially coal, have become controversial because of their high level of CO2 emissions. Many power plants have replaced coal with natural gas to mitigate CO2 emissions. The United States and the world have also pushed for renewable energy as an effort to control CO2 emissions under the overall banner of slowing down global warming.
The knowledge of how CO2 interacts with reservoir fluids and rock is essential for effective and reliable CO2 storage. This work investigates CO2 storage in unconventional oil reservoirs with high asphaltene content and explains the CO2 storage mechanism in pore-scale. Considering that asphaltenes are insoluble in CO2, asphaltene precipitation is induced during CO2 injection, controlling CO2 solubility and capillary trapping mechanisms. In this study, CO2-oil interaction is examined through core flooding experiments in a high asphaltene content (34.3 wt%) Canadian bitumen sample with 8.8º API. To study how irreversible clay-asphaltene interaction affects CO2 capillary trapping, the reservoir rock is prepared with and without clay addition. The role of CO2 injection rate on solubility trapping with experiments at varying injection flow rates. Displaced fluids and postmortem samples are subjected to several analyses to observe the CO2 storage mechanisms in pore scale due to CO2-asphaltene and CO2-clay-asphaltene interactions. It was found that CO2-clay-asphaltene interaction may favor CO2 capillary trapping into high asphaltene content reservoirs. Reservoir clays play important roles in porosity and permeability reduction due to clay interactions with asphaltenes. The low CO2 flow rate was found to favor solubility trapping. Therefore, our results suggest that the presence of clays and the CO2 injection rate are critical parameters controlling the effectiveness of CO2 storage in high asphaltene content reservoirs.
Underground carbon dioxide (CO2) storage projects usually target the depleted light oil and natural gas fields due to operational expertise, favorable geological features, and existence of infrastructure [1; 2]. However, as CO2 emissions are projected to increase in the next 35 years , other storage alternatives are required to mitigate environmental impacts. In this context, CO2 storage in unconventional oil reservoirs with low API gravity may be an attractive candidate on the short to medium term [4; 5].These low API gravity oils usually have high asphaltene content, which can represent up to 45.3 wt% of the crude oil . CO2 injection can cause asphaltenes precipitate in the pore space as CO2 is insoluble in asphaltenes [7; 8]. Therefore, the effectiveness of CO2 microscopic storage mechanisms will be affected, particularly for capillary (or residual) and solubility trapping.
Fluids are injected in subsurface permeable formations for various purposes including waste disposal, gas storage, CO2 sequestration, and enhanced oil/gas recovery. Containment of the injected fluids is needed to meet the regulatory requirements and/or to ensure efficiency of the intended processes. The injected fluids can leak to overlying formations in presence of leakage pathways. Improperly plugged and abandoned (P&A) wells are considered as the main potential leakage pathways. In a previous work, we introduced a vertical pressure transient interference test and presented an analysis methodology to detect and characterize leaking wells. The analysis methodology was based on an inverse modeling algorithm that can be highly instable and computationally expensive. Here, we propose an easy-to-use fully graphical methodology to characterize leaking wells. The pressure measurements are graphed in three different forms. The slopes and intercepts of the line-fitted graphs are used to determine the leak location and transmissibility as well as the transmissivity ratio of the connected zones. The graphical method is applied to an example problem to illustrate its application procedure and effectiveness.
The Leakage through abandoned wells and improperly plugged boreholes can create vertical communication between otherwise hydrologically isolated permeable zones. The driving mechanism behind the leakage can be the hydraulic gradients created by injection into one of the zones. Zeidouni and Pooladi-Darvish (2012a, 2012b) introduced a vertical interference test to detect and characterize a leaking well connecting the operating zone to an overlying non-operating zone which is otherwise separated by a sealing caprock. The test involves injection (production) into (from) the operating zone (OZ) and observing the pressure at a distance both in the OZ and the monitoring zone (MZ). We use injection throughout this paper for consistency. Several researchers attempted to analyze the pressure observations through inverse modelling approach and data assimilation (Wang and Small 2014, Jung, Zhou, and Birkholzer 2013, Sun et al. 2013, Zeidouni and Pooladi-Darvish 2012a, b, Chabora and Benson 2009, Jung, Zhou, and Birkholzer 2015, Keating et al. 2014). While inverse modeling can be very useful, it requires robust and computationally expensive inversion techniques that may not be easy to implement in practice. Also, inverse models can be very instable if the unknown parameters are not fully independent. It would be useful to develop graphical approaches such as those used in conventional pressure transient analysis that can be conveniently used in analyzing the pressured data for leaking well characterization.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice. This paper presents a novel formulation that consistently evaluates capillary force with respect to pore size distribution (PSD) directly from Bakken core measurements. We also demonstrate how permeability would change as reservoir depletes, and more importantly CO2 huff-and-puff, and incorporate the new model to a 3D dynamic simulator. We further developed adsorption models using a local density optimization algorithm, to better address the incapability of Langmuir model for wet and liquid-rich formations. Our advances were also designed for multi-component interactions at adsorption sites for a full spectrum of reservoir pressures of interests. This new adsorption model, based on exactly the same physical chemistry principles at different pressures, revolved from monolayer at low pressure to more complex multilayer model spontaneously and consistently, imperative to CO2 cycling. With our advances in understanding key production mechanisms of capillarity and adsorption, we are able to differentiate production driving mechanisms in unconventional reservoirs vs. conventional ones. A new compositional simulator was developed that captures those differentiations and results show that should capillarity be consistently formulated with PSD, significant difference in production profile is observed. As shown for CO2 huff-and-puff process in unconventional reservoirs, a smaller amount of soaking time and a 30% higher in ultimate recovery was achieved, as compared with the case not considering capillarity and adsorption properly. This paper implements a novel formulation that captures capillarity pressure under pore confinement using a full spectrum of PSD characterization for shale oil core analysis. The new model consistently evaluates capillary adsorption effects for reservoir fluid density evolution using industrial accepted equation-of-state model and reservoir pressure depletion and CO2-IOR process. A substantial increase in oil production is illustrated when PSD, an important unconventional reservoir characteristics, is properly modeled. The new method may bring additional insight to greatly mitigate uncertainties for IOR potential evaluation, productivity and EUR assessment for unconventional reservoirs.
Carbon dioxide (CO2) is injected into subsurface rocks either to improve hydrocarbon recovery or for permanent storage in geologic formations. At storage sites, CO2 injection wells are drilled and completed with multiple-string casings, which are cemented to the host rock. Cement is the primary means of protecting these casings from corrosive fluids and isolating storage zones from overlying fresh water aquifers by effectively sealing the casing-rock annulus. Over the life of the well, dissolved CO2 interacts with the casing-cement-rock system thereby degrading the hardened cement and resulting in loss of zonal isolation and structural integrity required to support the casing and to ensure long-term integrity of the well. Cement performance is often assessed through laboratory measurement of compressive strength, porosity and permeability. These parameters are indicators of mechanical integrity. Although compressive strength in the range of 0.7 to 5 MPa is generally sufficient to continue drilling after the casing is cemented, further hydration and chemical degradation occur throughout the operational life of the well. In CO2 injection wells, environmental conditions (i.e. CO2 concentration, pressure and temperature) around the cement result in further alteration in mechanical properties. This hostile environment causes severe mechanical damage and ultimate failure of cement sheath, potentially leading to micro-channelling and formation of micro-annuli. In this study, experiments were conducted to investigate the effect of CO2 concentration on mechanical integrity of well cements (Classes G and H) after exposure to carbonic acid environment. Cement cores were prepared and aged for 14 days in autoclave filled with 2% NaCl solution saturated with methane gas containing carbon dioxide. Aging tests were performed at 38°C and 42 MPa, varying CO2 concentration. To assess the level of degradation and describe the process of acid attack, compressive strengths of unexposed and exposed specimens were measured and compared. In addition, other properties of cement cores including porosity, permeability, stiffness/elasticity and Fourier Transform Infrared Spectroscopy (FTIR) measurements were obtained and used in the assessment. After 14 days of exposure, increase in CO2 concentration leads to insignificant changes in compressive strength due to combined effect of carbonation of cement hydrates (calcium silicate hydrates and calcium hydroxide) and subsequent leaching, with each process compensating for the other. Porosity, permeability and FTIR measurements are consistent with this observation. Under the experimental conditions adopted in this study, durability of Classes G and H cement are comparable. However, Class H cement becomes more elastic (i.e. less stiff) than Class G cement as CO2 concentration increases. FTIR mineralogy provides evidence that the mechanical behaviour of well cement after exposure to CO2-saturated brine is a direct consequence of interconnected chemical processes. Under carbon sequestration conditions, these processes counterbalance one another to ensure long-term integrity of the well for CO2 storage and containment.
Zhang, Liang (China University of Petroleum (Huadong)) | Li, X. (China University of Petroleum (Huadong)) | Ren, B. (University of Texas at Austin) | Cui, G. D. (China University of Petroleum (Huadong)) | Ren, S. R. (China University of Petroleum (Huadong)) | Chen, G. L. (PetroChina)
The block H-59 in the Daqingzijing region was selected as a pilot site for the first stage of the CCS project in Jilin oilfield after an extensive assessment. This block is a light oil reservoir with a low permeability. The performance of water flooding after the primary oil recovery was very poor. Therefore, CO2 injection has been started since April 2008 for EOR associated with CO2 storage for environmental benefits. This paper is aimed at assessing the current CO2 storage capacity and distribution at different states in the oil reservoir after 6-year injection until April 2014. Based on various CO2 trapping mechanisms, an evaluation method of CO2 storage potential is established to calculate the theoretical and effective CO2 storage capacities in target oil reservoir. the current amount of CO2 buried in the H-59 block was calculated according to the field data. The reservoir numerical simulation was used to analyze the distribution and existing state of CO2 underground. The assessment results show that the theoretical capacity of CO2 storage in the H-59 block is 72.32×104 t, and the effective capacity of CO2 storage is 26.37×104 t. The calculation of effective CO2 storage capacity in oil reservoir considers the engineering practice of field operation during project life. The coverage factor of well pattern (k1) and the sweep coefficient of CO2 within the well pattern (k2) have been introduced in the method. Meanwhile, the mineral trapping was neglected for short-term storage of CO2 based on a preliminary geochemical simulation analysis. There are 17.45×104 t CO2 which has been buried in the block until April 2014. The distribution of buried CO2 between the injection and production wells is mainly determined by the reservoir physical properties and the total amount of CO2 injected in each well. Reservoir simulations indicate that 61.0% of CO2 buried in the oil reservoir has been trapped at supercritical state, and the amounts of CO2 dissolved in oil and water account for 24.4% and 14.6% respectively. These proportions of CO2 at different states are very close to the calculation results of effective CO2 storage capacity. In comparison to the effective CO2 storage capacity, it is thought that the block H-59 still has a certain storage potential of 8.92×104 t at present. For the assessment methods, the parameters k1 and k2 for calculation of effective CO2 storage capacity deserve for further discussion. It should be also noted that the accuracy of CO2 distribution predicted by reservoir simulation greatly depends on the accuracy of geological model. It needs more efforts to improve the understanding of the target reservoir properties.
Climate change, resulting from combustion of fossil fuels, have become of major concern to the Global community, especially in the last two decades. Fossil fuels no doubt, are indispensable to the economic development of most countries and facilitate better living conditions for teeming populations. Improved efficiencies of combustion engines (internal and external) also present realistic and cost effective opportunities to reduce emissions and complement global efforts that is currently largely focused on the adoption of renewable energy. This paper examines CO2 reductions in combustion engines by the process of Carbonation through the application of the law of Constant composition. We evaluate the mechanical and chemical processes involved in chemosequestration using aqueous solution of Magnesium Silicate (naturally occurring Serpentinite) while defining clearly the conditions for reaction. An initial design and the method of operation for the carsequestor (the sequestration device) are presented after a proper volumetric analysis of a variable case performed under specified conditions. Cost analysis, global emissions reduction estimation and limitations are also discussed. This paper shows that the entire process is feasible and will reduce CO2emissions significantly while maintaining fuel diversity for sustainable growth. Keywords: Carbonation, Chemosequestration, Serpentinite, emissions reduction.
The European Federation of Foundation Contractors (EFFC) and Deep Foundations Institute (DFI) developed a sector-specific carbon accounting methodology and associated “carbon calculator” for foundations and geotechnical works. The EFFC-DFI Carbon Calculator is believed to be one of the construction industry’s first collaboratively produced carbon calculator tools for European and international countries based on verifiable and standardized data. It is intended that the tool be adopted internationally and become the open-source industry standard for ground works. A detailed methodological guide is provided with the calculator (Lemaignan and Wilmotte, 2013). This guide explains the background of the standards, accounting methodologies, emission sources and factors that were used as the bases for the tool development and includes detailed guidance on use of the calculator.
Temperature can be used as a tracer to detect leakage of fluids from a CO2 storage zone. Brine leakage from the injection zone to an above-zone interval will induce a temperature increase as a result of geothermal gradient. Leakage of CO2 can induce a temperature decrease owing to the Joule-Thompson effect associated with pressure drop toward shallow zones. A larger pressure drop at shallower depths is associated with more CO2 expansion upon leakage and could induce more cooling and, hence, a stronger temperature signal. We investigate the strength of the temperature signal as a function of depth for two scenarios in which either a well or a fault acts as leakage pathway. The hydraulic properties of the leakage pathway, modeled as a fractured medium or as a porous medium, also impact the results. Using dual-porosity and dual-permeability models for which CO2 relative permeability and average absolute permeability are modeled higher than in the simple porous medium case, we study the effect of fractures on the temperature signal. The leakage rate increases significantly for dual medium models. However, the temperature change in above-zone interval does not change much as it depends on the pressure gradient which is reduced compared to the single-porosity medium case.
The value of CO2 geological storage sites may be limited when defective wells and faults create pathways allowing migration out of the CO2 injection zone (IZ). Various monitoring techniques are available to assure storage quality and to detect and characterize leakage pathways. Leakage of CO2, brine, or their mixture can induce pressure and temperature changes in an above-zone monitoring interval (AZMI) that is separated from the IZ by a sealing confining layer. Monitoring of the pressure signal in the AZMI has provided information about leakage pathways (Zeidouni and Pooladi-Darvish 2012a, b, Sun et al. 2013, Jung, Zhou, and Birkholzer 2013, Haghighat et al. 2013). More recent work by Zeidouni et al. (Zeidouni, Nicot, and Hovorka 2014) investigated the potential for leakage detection on the basis of the AZMI’s temperature signal. Results showed that the thermal signal is controlled by several processes, including Joule-Thompson (JT) effect, heat of dissolution/vaporization of CO2/water, temperature discrepancy between the injected and native fluids, geothermal gradient, and heat exchange with the surrounding rock-fluid system.
The capillary pressure heterogeneity or local capillary trapping (LCT) determines the final distribution of CO2 in a saline aquifer during geological carbon sequestration. This locally trapped CO2 would not escape from the storage formation even if caprock integrity is compromised. It is, therefore, essential to predict the extent and storage capacity of LCT during the design of GCS projects.
This work employs a fast method based on the geologic criteria to estimate the structures of local capillary traps. The method assumes a critical capillary entry pressure (CCEP) and a geostatistical realization of the reservoir entry pressure field as inputs. It then finds the capillary barriers inside the domain and identifies the grid blocks beneath clusters of barriers. These grid blocks are the local capillary traps. The criterion for choosing the CCEP is important, and we suggest a criterion in this work.
We verify this algorithm by full-physics simulations in small 2D and 3D domains. We employ a large CO2 injection rate (Ngr~0.1) to fully sweep the storage domain, followed by a long period of buoyant flow to allow for complete charging of those local capillary traps. We test several CCEPs to determine the most physically representative value by comparing the LCT predicted from both methods. We find that a single value of CCEP enables the geologic algorithm to give a very good approximation of LCT distribution as well as LCT volume in uncorrelated and weakly correlated porous media. This means that the concept of CCEP is a reasonable approximation to the physical process by which traps are filled.
LCT can be described in terms of percolation theory. The percolation threshold arises from the competition between connected clusters of barriers and connected clusters of local traps. We show that both the percolated CCEP (corresponding to the percolation of LCT) and optimal CCEP (corresponding to the best match between geologic criteria and full-physics simulation) change with each other in a predictable linear way for the uncorrelated capillary entry pressure field.