A review of physical supply and EROI of fossil fuels in China

This paper reviews China’s future fossil fuel supply from the perspectives of physical output and net energy output. Comprehensive analyses of physical output of fossil fuels suggest that China’s total oil production will likely reach its peak, at about 230 Mt/year (or 9.6 EJ/year), in 2018; its total gas production will peak at around 350 Bcm/year (or 13.6 EJ/year) in 2040, while coal production will peak at about 4400 Mt/year (or 91.9 EJ/year) around 2020 or so. In terms of the forecast production of these fuels, there are significant differences among current studies. These differences can be mainly explained by different ultimately recoverable resources assumptions, the nature of the models used, and differences in the historical production data. Due to the future constraints on fossil fuels production, a large gap is projected to grow between domestic supply and demand, which will need to be met by increasing imports. Net energy analyses show that both coal and oil and gas production show a steady declining trend of EROI (energy return on investment) due to the depletion of shallow-buried coal resources and conventional oil and gas resources, which is generally consistent with the approaching peaks of physical production of fossil fuels. The peaks of fossil fuels production, coupled with the decline in EROI ratios, are likely to challenge the sustainable development of Chinese society unless new abundant energy resources with high EROI values can be found

Modelling India’s coal production with a negatively skewed curve-fitting model

India’s coal demand is forecast to increase at a rapid pace in the future due to the country’s economic and population growth. Analyzing the scope for future production of India’s domestic coal resources, therefore, plays a vital role in the country’s development of sound energy policies. This paper presents a quantitative scenario analysis of India’s potential future coal production by using a negatively skewed curve-fitting model and a range of estimates of the country’s ultimately recoverable resources (URR) of coal. The results show that the resource base is sufficient for India’s coal production to keep increasing over the next few decades, to reach between 2400 and 3200 Mt/y at 2050, depending on the assumed value of URR. A further analysis shows that the high end of this range, which corresponds to our ‘GSI’ scenario, can be considered as the probable upper-bound to India’s domestic coal production. Comparison of production based on the ‘GSI’ scenario with India’s predicted demand shows that the domestic production of coal will be insufficient to meet the country’s rising coal demand, with the gap between demand and production increasing from its current value of about 268 Mt/y to reach 300 Mt/y in 2035, and 700 Mt/y by 2050. This increasing gap will be challenging for the energy security of India

Chemical Compositions in Salinity Waterflooding of Carbonate Reservoirs: Theory

Higher oil recovery after waterflood in carbonate reservoirs is attributed to increasing water wettability of the rock that in turn relies on complicated surface chemistry. In addition, calcite mineral reacts with aqueous solutions and can alter substantially the composition of injected water by mineral dissolution. Carefully designed chemical and/or brine flood compositions in the laboratory may not remain intact while the injected solutions pass through the reactive reservoir rock. This is especially true for a low-salinity waterflood process, where some finely tuned brine compositions can improve flood performances, whereas others cannot. We present a 1D reactive transport numerical model that captures the changes in injected compositions during water flow through porous carbonate rock. We include highly coupled bulk aqueous and surface carbonate-reaction chemistry, detailed reaction and mass transfer kinetics, 2:1 calcium ion exchange, and axial dispersion. At typical calcite reaction rates, local equilibrium is established immediately upon injection. In SI, we validate the reactive transport model against analytic solutions for rock dissolution, ion exchange, and longitudinal dispersion, each considered separately. Accordingly, using an open-source algorithm (Charlton and Parkhurst in Comput Geosci 37(10):1653–1663, 2011. https://doi.org/10.1016/j.cageo.2011.02.005), we outline a design tool to specify chemical/brine flooding formulations that correct for composition alteration by the carbonate rock. Subsequent works compare proposed theory against experiments on core plugs of Indiana limestone and give examples of how injected salinity compositions deviate from those designed in the laboratory for water-wettability improvement

Chemical Compositions in Salinity Waterflooding of Carbonate Reservoirs: Theory

Higher oil recovery after waterflood in carbonate reservoirs is attributed to increasing water wettability of the rock that in turn relies on complicated surface chemistry. In addition, calcite mineral reacts with aqueous solutions and can alter substantially the composition of injected water by mineral dissolution. Carefully designed chemical and/or brine flood compositions in the laboratory may not remain intact while the injected solutions pass through the reactive reservoir rock. This is especially true for a low-salinity waterflood process, where some finely tuned brine compositions can improve flood performances, whereas others cannot. We present a 1D reactive transport numerical model that captures the changes in injected compositions during water flow through porous carbonate rock. We include highly coupled bulk aqueous and surface carbonate-reaction chemistry, detailed reaction and mass transfer kinetics, 2:1 calcium ion exchange, and axial dispersion. At typical calcite reaction rates, local equilibrium is established immediately upon injection. In SI, we validate the reactive transport model against analytic solutions for rock dissolution, ion exchange, and longitudinal dispersion, each considered separately. Accordingly, using an open-source algorithm (Charlton and Parkhurst in Comput Geosci 37(10):1653–1663, 2011. https://doi.org/10.1016/j.cageo.2011.02.005), we outline a design tool to specify chemical/brine flooding formulations that correct for composition alteration by the carbonate rock. Subsequent works compare proposed theory against experiments on core plugs of Indiana limestone and give examples of how injected salinity compositions deviate from those designed in the laboratory for water-wettability improvement

Chemical Compositions in Modified Salinity Waterflooding of Calcium Carbonate Reservoirs: Experiment

Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some of adhered crude oil. Composition design of brine modified to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone, which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity hinders rational design of brines tailored to improve oil recovery. Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion exchange, and dispersion (Yutkin et al. in SPE J 23(01):084–101, 2018. https://doi.org/10.2118/182829-PA). Here, we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at injection rates higher than 3.5 × 10- 3 m s- 1 (1000 ft/day). Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long concentration history tails. Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes

Novel approach to study the impact of asphaltene properties on low salinity flooding

Low salinity water flooding (LSW) has gained significant attention, because of its advantages compared with other enhanced oil recovery (EOR) methods. LSW's positive contribution to recovery factor has been demonstrated in the literature at lab and field scales. However, LSW flooding does not always increment oil recovery. It is a specific combination of properties of an asphaltenic crude oil, chemically equilibrated brine, and rock surface that may explain the success or failure of LSW. In this work, we introduce a novel experimental approach to study asphaltene-like chemical interactions with surfaces rock minerals to evaluate the effectiveness of applying LSW. When studying the impact of asphaltene properties on incremental recovery, one aims to detach some of the immobile oil, which is semi-irreversibly stuck on rock surface. This is a difficult task, because of varying crude oil composition, as well as asphaltene interfacial and chemical properties. To overcome these issues, we split the problem into several parts. We study how mono- and poly-functional chemical compounds mimic asphaltene interactions with mineral surfaces, like silica and calcium carbonate, which are proxies for sandstones and limestones, respectively. For example, amines, quaternary ammonia or carboxylates represent asphaltene functional groups that are mainly responsible for crude oil base and acid numbers, respectively. Adsorption of polymers and oligomers containing such groups mimics the irreversible asphaltene deposition onto rock surface through formation of chemically active polymerlike structures at the oil-brine interface. The silica surface is negatively charged in brines with pH above 2. Silica attracts positively charged ammonia salts, such as cetrimonium chloride (CTAC). However, negatively charged mono-functional carboxylates, i.e. anionic surfactants, like sodium hexanoate (NaHex), hardly adsorb onto silica, even in the presence of a bridging ion, like calcium. In contrast to silica, calcium carbonate surface has both positive and negative charges on its surface. We found that CTAC adsorbs onto calcium carbonate in any brine tested. NaHex shows minimal adsorption onto calcium carbonate only in the presence of calcium ions suggesting a contribution of an ion-bridging mechanism. Adsorption of all studied mono-functional surfactants is fully reversible and, consequently not representative of asphaltenes. Multifunctional compounds, i.e., polymers, demonstrate irreversible, asphaltene-like, adsorption. We studied adsorption of carbohydrates decorated with individual amines and quaternary ammonia functional groups. The carbohydrates with amine functional groups adsorb irreversibly on calcium carbonate and silica in all tested brines with pH up to 10. Therefore, a lower base number (BN) in crude oils indicates a higher potential for LSW. Our findings demonstrate the proof of concept that contribution of different functional groups to asphaltene adsorption/deposition can be studied using functionalized water-soluble polymers. This framework is useful for assessment of adsorption strength vs. number of active groups as well as screening of efficient detachment process of asphaltenic crude oils from rock surface