Evaluation of CO2 enhanced oil recovery and sequestration potential in low permeability reservoirs,Yanchang Oilfield,China

Sequestrating CO₂ in reservoirs can substantially enhance oil recovery and effectively reduce greenhouse gas emission. To evaluate the potential of CO₂ enhanced oil recovery (EOR) and sequestration for Yanchang Oilfield in China, a screening standard which was suitable for CO₂-EOR and sequestration in Yanchang Oilfield was proposed based on its characteristics of strong heterogeneity, high water content and severe fluid channeling after water flooding. In addition, an efficient calculation method – stream tube simulation method was presented to figure out CO₂ sequestration coefficient and oil recovery factor. After screening and evaluating, it turned out that 148 out of 176 blocks in 22 oilfields were suitable for CO₂-EOR and sequestration. CO₂ flooding after water flooding can produce 180.21 × 10⁶ t more crude oil and sequestrate 223.38 × 10⁶ t CO₂. The average incremental oil recovery rate of miscible reservoirs was 12.49% and the average CO₂ sequestration coefficient was 0.27 t/t while the two values were 6.83% and 0.18 t/t for immiscible reservoirs. There are comparatively more reservoirs that are suitable for CO₂-EOR and sequestration in Yanchang Oilfield than normal, which can obviously enhance oil recovery and means a great potential for CO₂ sequestration. CO₂-EOR and sequestration in Yanchang Oilfield has a bright application prospect.     

Immiscible CO2 Flooding through Horizontal Wells

Abstract

The CO₂ immiscible process is a potentially viable method of enhanced oil recovery (EOR) for heavy oil reservoirs. In an immiscible CO₂ process, part of the injected CO₂ is absorbed into the reservoir fluids and part forms a free-gas phase in the reservoir. Three groups of well configurations were mainly used: (1) vertical injection and vertical production wells, (2) vertical injection and horizontal production wells, and (3) horizontal injection and horizontal production wells. In immiscible CO₂ injection, highest recovery was obtained by vertical injection-horizontal production (VI-HP), followed by vertical injection-vertical production (VI-VP), and the least by horizontal injection-horizontal production (HI-HP). In VI-HP well configuration, the best recovery was obtained as 15.1% OOIP. In continuous CO₂ injection experiments, oil recovery for the VI-HP well configuration was higher than that of the other well configurations. The lowest ultimate recovery was obtained from HI-HP well configuration. The distance between the horizontal injector and horizontal producer was another important factor for the displacement of oil. In all runs, CO₂ breakthrough occurred very early, showing the dominance of viscous forces and relatively small effect of mass transfer between CO₂ and oil. The total oil recovery varied considerably because of the differences in injection rates and because of the unstable displacement. As a whole, oil recovery increased with an increase in the injection rate of CO₂. The cumulative gas-oil ratio (GOR) appeared to be sensitive to the gas injection rate for all well configurations. An increase in oil recovery with injection rate during initial stages of the runs was affected by the cumulative GOR.     

Geologic storage of carbon dioxide and enhanced oil recovery. I. Uncertainty quantification employing a streamline based proxy for reservoir flow simulation

Carbon dioxide (CO₂) is already injected into a limited class of reservoirs for oil recovery purposes; however, the engineering design question for simultaneous oil recovery and storage of anthropogenic CO₂ is significantly different from that of oil recovery alone. Currently, the volumes of CO₂ injected solely for oil recovery are minimized due to the purchase cost of CO₂. If and when CO₂ emissions to the atmosphere are managed, it will be necessary to maximize simultaneously both economic oil recovery and the volumes of CO₂ emplaced in oil reservoirs. This process is coined “cooptimization”.This paper proposes a work flow for cooptimization of oil recovery and geologic CO₂ storage. An important component of the work flow is the assessment of uncertainty in predictions of performance. Typical methods for quantifying uncertainty employ exhaustive flow simulation of multiple stochastic realizations of the geologic architecture of a reservoir. Such approaches are computationally intensive and thereby time consuming. An analytic streamline based proxy for full reservoir simulation is proposed and tested. Streamline trajectories represent the three-dimensional velocity field during multiphase flow in porous media and so are useful for quantifying the similarity and differences among various reservoir models. The proxy allows rational selection of a representative subset of equi-probable reservoir models that encompass uncertainty with respect to true reservoir geology. The streamline approach is demonstrated to be thorough and rapid.     

Numerical simulation of density-driven natural convection in porous media with application for CO2 injection projects

In this paper we investigate the mass transfer of CO₂ injected into a homogenous (sub)-surface porous formation saturated with a liquid. In almost all cases of practical interest CO₂ is present on top of the liquid. Therefore, we perform our analysis to a porous medium that is impermeable from sides and that is exposed to CO₂ at the top. For this configuration density-driven natural convection enhances the mass transfer rate of CO₂ into the initially stagnant liquid. The analysis is done numerically using mass and momentum conservation laws and diffusion of CO₂ into the liquid. The effects of aspect ratio and the Rayleigh number, which is dependent on the characteristics of the porous medium and fluid properties, are studied. This configuration leads to an unstable flow process. Numerical computations do not show natural convection effects for homogeneous initial conditions. Therefore a sinusoidal perturbation is added for the initial top boundary condition. It is found that the mass transfer increases and concentration front moves faster with increasing Rayleigh number. The results of this paper have implications in enhanced oil recovery and CO₂ sequestration in aquifers.     

Identification of early opportunities for CO2 sequestration—worldwide screening for CO2-EOR and CO2-ECBM projects

A study has been performed to identify potential worldwide opportunities for early application of CO₂ sequestration. An early opportunity is defined as a high-purity CO₂ point source, which can provide CO₂ at low costs to oil or coal fields, where the CO₂ is sequestered, and simultaneously enhance oil production (CO₂-EOR) or coal bed methane production (CO₂-ECBM). A Geographical Information System (GIS) was used to combine worldwide CO₂ point sources and oil and coal fields. This resulted in 429 potential source–oil field and 79 source–coal field combinations. A multi-criteria analysis (MCA), in which technical and socio-economic criteria are taken into account, was applied to rank the source–reservoir combinations generated by the GIS exercise. Some of the most promising cases were considered in more detail to select four illustrative cases for further study: two potential enhanced oil recovery (EOR) projects and two potential enhanced coal bed methane recovery (ECBM) projects. Case 1 consists of a hydrogen plant in Saudi Arabia, which could sequester 0.26 Mt/year CO₂ in a depleted oil reservoir at a net saving of approximately 3 €/t CO₂. EOR case 2 is a hydrogen plant in California, USA, which has to be retrofitted in order to generate a pure CO₂ stream. Approximately 0.28 Mt CO₂ could be stored annually. Mitigation costs have been estimated at 9–19 €/t CO₂, depending on the availability of steam for CO₂ regeneration. In cases 3 and 4, circa 0.68 and 0.29 Mt CO₂ from ammonia plants in China and Canada could be sequestered annually in coal fields for ECBM production at approximately 5 and 6 €/t CO₂, respectively.     

The CO2 storage capacity evaluation: Methodology and determination of key factors

It is a win–win technology to inject CO₂ into the oil or gas reservoirs. Because it can reduce the greenhouse gas emission and enhance oil recovery. In some oil or gas reservoirs, the reservoir water and the strong heterogeneity make the CO₂ storage capacity difficult to be determined. In this research, the CO₂ storage evaluation method is introduced. This method considers the CO₂ displacement efficiency, the CO₂ sweep efficiency, the CO₂ dissolution in oil and gas and the CO₂ displacement mechanism. The key factors in this evaluation method are determined by the reservoir simulation method, the thermodynamic theories and the statistical analysis methods separately. At last, the CO₂ storage capacity evaluation system is built. This system can be used to evaluate the CO₂ storage capacity fast and reliably and it worth to be promoted in the area of CO₂ storage.     

A comparative study of the carbon dioxide and nitrogen minimum miscibility pressure determinations for an Iranian light oil sample

Miscible gas injection is an approved profitable process that could significantly enhance oil recovery from different types of reservoirs while the major factor affecting its efficiency would be the minimum miscibility pressure (MMP) value. A recent experimental technique, known as vanishing interfacial tension (VIT), can estimate the MMP for gas–oil mixtures by measuring interfacial tension values and extrapolating them to zero at a sequence of pressures. Compositional simulation models are also useful in MMP determination by tuning an equation of state to compute the realistic phase behavior of reservoir fluid. In this paper, the capability and quality of MMP prediction via different methods such as laboratory slim tube tests, VIT technique, compositional simulation, and various empirical correlations were examined using a light oil sample taken from an Iranian carbonate reservoir, employing two pure gases of CO₂ and N₂ as the injectants. The accuracy and validation of the mentioned methods were then confirmed successfully by obtaining negligible overall absolute deviation percentages (AD%) compared with the conducted slim tube tests results.     

Understanding the significance of in situ coal properties for CO2 sequestration: An experimental and numerical study

Over the years, there has been a rapid increase in atmospheric CO₂ concentrations, from 280 ppm in 1850 to 360 ppm in 1998. Therefore, mitigation methods such as carbon sequestration in subsurface reservoirs have been suggested. CO₂ sequestration is attractive, especially in relation to coal, with the additional potential benefit of CH₄ recovery. However, the potential of CO₂ sequestration is not well understood for various types of coals due to important in situ properties of coal. In this study, data from previous studies for coal permeability, density, moisture content, mineral content, vitrinite reflectance, compressive strength and temperature are compared with the CO₂ adsorption results to understand the significance of these in situ coal properties on CO₂ sequestration. To verify the findings, a custom‐designed advanced core flooding apparatus is used to simulate the effects of various in situ properties on CO₂ sequestration. This apparatus can test samples of 203 mm in diameter and up to 1000 mm in length. Hence, heterogeneity effects can be understood, as previous CO₂ sequestration‐related formulae have been based on coal samples of sizes ranging up to only about 100 mm. However, initially, a reconstituted coal core sample has been used to simplify the heterogeneity effects. Flow rates are estimated by analysing the lag of downstream pressures over time. With the use of a 203‐mm‐diameter and 816‐mm‐long reconstituted Victorian brown coal sample, flow rate reductions of 70% and 98% are observed for injection pressures of 2 and 4 MPa, respectively, due to CO₂ injection. This study highlights the appropriateness of a candidate coal reservoir for CO₂ storage in terms of in situ properties. Copyright © 2013 John Wiley & Sons, Ltd.     

Combination of double and single cyclic pressure alternation technique to increase CO2 sequestration with heat mining in enhanced geothermal reservoirs by thermo-hydro-mechanical coupling method

The rise in global temperature due to an unceasingly increase in non-condensable gases (NCG) prompts more development of safe and economical CCUS (Carbon Capture Utilization and Storage) technologies. Carbon dioxide (CO₂) sequestration with heat mining in deep enhanced geothermal systems (EGSs) is one of the promising methods to reduce CO₂ emitted to the atmosphere. In this study, a cyclic alternation of pressures at the injection and production wells is applied in an EGS for heat mining together with CO₂ deposit. Simultaneous alternation of the injection and production pressures can significantly increase the amount of CO₂ sequestrated compared to applying a fixed pumping or withdrawing pressures at the injector and producer respectively. At the injection well, alternation in pumping pressures at high frequency (small interval of days) increased CO₂ sequestration rate. Reducing the pumping frequency resulted in the lowering of the total amount of CO₂ sequestrated, lesser than using a fixed pumping pressure. The alternation in pumping frequency has a direct relationship to the CO₂ sequestration rate. The frequency of the injection and production pressures refers to the interval in days of the interchange in pressure between high to a low value and vice-versa. Furthermore, simultaneous alternation of pressures at the injection and production wells respectively (double cyclic method) improved geothermal heat extraction efficiency, thus higher performance for both geothermal and CO₂ sequestration projects.     

Large CO2 Sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective

Significant reduction of CO₂ emissions on a global scale may be achieved by reduction of energy intensity, by reduction of carbon intensity or by capture and storage of CO₂. A portfolio of these methods is required to achieve the large reductions required; of which utilization of carbon sinks (i.e. material, geosphere and biosphere) will be an important player. Material sinks will probably only play a minor role as compared to biosphere and geosphere sinks in storage of CO₂. Biosphere sinks are attractive because they can sequester CO₂ from a diffuse source whereas geosphere sinks require a pure waste stream of CO₂ (obtained by using expensive separation methods). On the other hand, environmental factors and storage time favor geosphere sinks. It is expected that a combination of the two will be used in order to meet emission reduction targets over the next 100 yr.A critical look is taken at capacities, retention/residence times, rates of uptake and relative cost of utilization of biosphere and geosphere sinks at three scales – global, national (Canada) and provincial (Alberta). Biosphere sinks considered are oceans, forests and soils. Geosphere sinks considered are enhanced oil recovery, coal beds, depleted oil and gas reservoirs and deep aquifers. The largest sinks are oceans and deep aquifers. The other biosphere and geosphere sinks have total capacities approximately of an order of lower magnitude. The sinks that will probably be used first are those that are economically viable such as enhanced oil-recovery, agriculture, forestry and possibly enhanced coalbed methane-recovery. The other sinks will be used when these options have been exhausted or are not available or a penalty (e.g. carbon tax) exists. Although the data tabulated for these sinks is only regarded as preliminary, it provides a starting point for assessment of the role of large sinks in meeting greenhouse gas emission reduction targets.     

Optimizing a CO2 value chain for the Norwegian Continental Shelf

This paper presents a mathematical model for designing a carbon dioxide (CO₂) value chain. Storage of CO₂ in geological formations is recognized as an important alternative for carbon abatement. When CO₂ is deposited in oil reservoirs it can sometimes be used to achieve additional oil production, enhanced oil recovery (EOR). The model determines an optimal CO₂ value chain from a fixed set of CO₂ emission points and a set of potential injection sites. It designs a transport network and chooses the best suited oil fields with EOR potential or other geological formations for storage. A net present value criterion is used. The model is illustrated by an example of a Norwegian case with 14 oil fields, two aquifers and five CO₂ sources. A sensitivity analysis is performed on the most important parameters.     

Effects of relative permeability change resulting from interfacial tension reduction on vertical sweep efficiency during the CO2-LPG hybrid EOR process

The addition of liquefied petroleum gas (LPG) to the CO₂ stream reduces interfacial tension (IFT) between the injected gas and the reservoir oil, and it changes the gas-liquid relative permeability by making it more water-wet, which affects not only the oil mobility, but also the vertical sweep efficiency. The reduction of the IFT decreases vertical sweep efficiency because it enhances the relative permeability of the solvent, resulting in an increase in the viscous gravity number. For CO₂-LPG enhanced oil recovery (EOR), oil recovery is enhanced by up to 47%, as compared to CO₂ flooding, when the relative permeability change caused by the IFT is not considered. By taking the vertical sweep-out caused by IFT and relative permeability change into consideration, this increase is reduced to 40%. These results indicate the importance of considering the relative permeability and IFT change when predicting the performance of the CO₂-LPG EOR process.     

Application of different EOR techniques for the energy and recovery of Ashal’cha oil field

In this research, utilizing the reservoir and produced oil data, different enhanced oil recovery (EOR) techniques known as in-situ combustion, CO₂ flooding, and steam flooding were applied for Ashal’cha oil field in Republic of Tatarstan, Russia. For this purpose, In-Situ Combustion Predictive Model (ICPM), CO₂ Miscible Flood Predictive Model (CO₂PM) and Steam-flood Predictive Model (SFPM) are used. In addition to oil recovery, economic analysis of the discussed EOR applications was also conducted. By using the oil price forecast for 10 years, each EOR method is analyzed using their expenses and outcomes separately. Comparison among the EOR applications regarding the oil production, and economic feasibility was also given. Taking the reservoir and produced oil characteristics, oil production rate and economical payout time into account, it was observed that in-situ combustion is the most feasible and practical EOR method for Ashal’cha oil field.     

Chemical looping gasification for hydrogen production: A comparison of two unique processes simulated using ASPEN Plus

The research compares the simulations of two chemical looping gasification (CLG) types using the ASPEN Plus simulation software for the production of H₂. The simulated biomass type was poultry litter (PL). The first CLG type used in situ CO₂ capture utilizing a CaO sorbent, coupled with steam utilization for tar reforming, allowing for the production of a CO₂-rich stream for sequestration. Near-total sorbent recovery and recycle was achieved via the CO₂ desorption process. The second type utilized iron-based oxygen carriers in reduction–oxidation cycles to achieve 99.8% Fe₃O₄ carrier recovery and higher syngas yields. Temperature and pressure sensitivity analyses were conducted on the main reactors to determine optimal operating conditions. The optimal temperatures ranged from 500 to 1250 °C depending on the simulation and reactor type. Atmospheric pressure proved optimal in all cases except for the reducer and oxidizer in the iron-based CLG type, which operated at high pressure. This CLG simulation generated the most syngas in absolute terms (2.54 versus 0.79 kmol/kmol PL), while the CO₂ capture simulation generated much more H₂-rich syngas (92.45 mol-% compared to 62.94 mol-% H₂).     

Study of Parameters Affecting Enhanced Coal Bed Methane Recovery

Abstract

Laboratory and field scale trials conducted so far indicate that injection of CO₂ and N₂ into deep coalbeds has the potential to enhance coalbed methane (ECBM) recovery while simultaneously sequestering CO₂. The work has identified that the fundamental processes involved in CO₂ sequestration/CBM recovery in deep coalbeds are not fully understood and further research is needed to advance this technology. ECBM is affected by several parameters; prominent among them are coal characteristics, in-situ conditions prevailing in deep coalbeds, and changes arising from the interaction of coal with various fluids. These parameters do not act independently, thereby making it difficult to isolate their impacts separately. An attempt has been made in this article to classify these parameters and understand their role in ECBM. Past work in this area is reviewed and the future work that is critical for an improved understanding of ECBM recovery is discussed.     

Hydrogen amplification from coke oven gas using a CO2 adsorption enhanced hydrogen amplification reactor

To improve coke oven gas (COG) energy conversion, alternative configurations for amplifying hydrogen from COG are proposed in this paper. In these new configurations, a CO₂ adsorption enhanced hydrogen amplification reactor is combined with a pressure swing adsorption separation unit (PSA) to produce pure hydrogen. Hydrogen production was integrated with desorption gas utilization, in situ CO₂ capture and waste heat recovery to improve COG energy conversion efficiency and decrease CO₂ emissions. To analyze the advantages of the flowsheet modifications, technical and economic performance indicators were used to evaluate and compare the performances of the various system configurations. Simulation results show that the alternative configurations proposed in this paper have higher energy conversion efficiencies, higher hydrogen yields and shorter dynamic payback periods. The variation of technical performance with reaction temperature, pressure, sorbent to carbon ratio and steam to carbon ratio were also analyzed using a sensitivity study. Optimal operating conditions for the CO₂ adsorption enhanced hydrogen amplification reactor were obtained based on the simulation results.     

Biomass co-firing options on the emission reduction and electricity generation costs in coal-fired power plants

Co-firing offers a near-term solution for reducing CO₂ emissions from conventional fossil fuel power plants. Viable alternatives to long-term CO₂ reduction technologies such as CO₂ sequestration, oxy-firing and carbon loop combustion are being discussed, but all of them remain in the early to mid stages of development. Co-firing, on the other hand, is a well-proven technology and is in regular use though does not eliminate CO₂ emissions entirely. An incremental gain in CO₂ reduction can be achieved by immediate implementation of biomass co-firing in nearly all coal-fired power plants with minimum modifications and moderate investment, making co-firing a near-term solution for the greenhouse gas emission problem. If a majority of coal-fired boilers operating around the world adopt co-firing systems, the total reduction in CO₂ emissions would be substantial. It is the most efficient means of power generation from biomass, and it thus offers CO₂ avoidance cost lower than that for CO₂ sequestration from existing power plants. The present analysis examines several co-firing options including a novel option external (indirect) firing using combustion or gasification in an existing coal or oil fired plant. Capital and operating costs of such external units are calculated to determine the return on investment. Two of these indirect co-firing options are analyzed along with the option of direct co-firing of biomass in pulverizing mills to compare their operational merits and cost advantages with the gasification option.     

CO2 enhanced coalbed methane production in the Netherlands

The technical and economical feasibility of CO₂ sequestration in deep coal layers combined with enhanced coalbed methane (ECBM) production in the Netherlands has been explored. Annually, 3.4 Mtonne CO₂ from chemical installations can be delivered to sequestration locations at 15 €/tonne and another 55 Mtonne from power generating facilities at 40–80 €/tonne. Four potential ECBM areas have been assessed, of which Zuid Limburg is the best location for a test site, while the Achterhoek is more suitable for future large-scale CO₂ sequestration. Between 54 Mtonne and 9 Gtonne CO₂ can be sequestered in the four areas together, heavily depending on available technology for accessing the coal seams. At the same time, between 0.3 and 60 EJ of coalbed methane can be produced. The optimal configuration may have 1000 m spacing between production wells, and extreme inseam drilling. The price of coalbed methane may become competitive with natural gas when a bonus for CO₂ sequestration is applied of about 25 €/tonne. For the long term, on-site hydrogen or power (SOFC) production with direct injection of produced CO₂ seems most attractive. Further study is required, most notably more accurate geological surveys, assessment of drilling costs in Dutch context, and environmental impacts of ECBM.