• Energy Research

Abstract Accurate predictions and precise control of the allowable water content in CO2-rich fluids are required in large-scale pipeline operations. Especially during transient shut-in and re-start operations, the pressure decrease associated with cooling may cause the CO2-rich mixture to pass through its dew point, producing an aqueous liquid phase. The pH of this liquid aqueous phase will rapidly decrease as carbonic acid is formed, greatly accelerating the corrosion rate of the carbon steel pipeline. The phase behaviour of CO2-rich fluid mixtures is qualitatively different to that of hydrocarbons, and standard oil and gas property packages in process simulation software may be inadequate for predicting dew points and other key properties. An extensive literature survey reveals 34 data sets where water contents of CO2-rich fluids have been measured near conditions relevant to CO2 pipelines. Following consistency tests, 23 data sets were found to be of good quality and 11 data sets were found to be of poor quality. The good-quality data were compared with predictions from 6 equations of state. Overall, Multiflash’s RKS (Advanced) model was found to provide the best agreement with the aqueous dew point data of CO2-rich fluid phases. A case study is presented wherein it is demonstrated that the formation of a corrosive aqueous phase can be avoided during shut-in via introduction of a relatively small volume of ethanol.

A 130 ft single-pass, gas-dominant flowloop has been constructed to study hydrate formation in an annular flow regime by exposing warm process fluids to a cold pipe wall. Hydrate was formed in six experiments from a natural gas mixture, with 6–18 °F subcooling from hydrate equilibrium. At lower subcooling values a stenosis-type hydrate film growth model without adjustable parameters was used to estimate the resulting pressure drop and yielded an average deviation of 15.8 psi from the experimental value. The accuracy of this model decreases appreciably with increasing subcooling, suggesting the occurrence of a transition after which the pressure drop becomes dominated by additional hydrate phenomena such as particle deposition or wall sloughing. For experiments with 18 °F subcooling, the pressure drop signal contained periodic peak-and-trough behavior and the primary hydrate restriction was observed to migrate downstream at a rate of 3 ft/min over the course of the experiment. Average hydrate growth rates ...

Recovering methane (CH4) via the injection of carbon dioxide (CO2) into a CH4-hydrate-bearing reservoir is a highly attractive mechanism for meeting the world's future energy demand, since it offers the prospect of carbon-neutral energy production.

Hydrate risk management is critically important for an energy industry that continues to see increasing demand. Hydrate formation in production lines is a potential threat under low temperature and high-pressure conditions where water and light gas molecules are present. Here, we introduce a 1-inch OD single-pass flow loop and demonstrate the Joule-Thomson (JT) expansion of a methane-ethane mixture. Initially, dry gas flowed through the apparatus at a variable pressure-differential. Larger pressure differentials resulted in more cooling, as predicted by standard thermodynamic models. A systematic deviation noted at higher pressure differentials was partially rectified through corrections incorporating heat transfer, thermal mass and kinetic energy effects. A wet gas system was then investigated with varying degrees of water injection. At the lowest rate, hydrate plugging occurred close to the expansion point and faster than for higher injection rates. This immediate and severe hydrate plugging has important implications for the design of safety relief systems in particular. Furthermore, this rate of plugging could not be predicted by existing software tools, suggesting that the atomization of liquids over an expansion valve is a critical missing component that must be incorporated for accurate predictions of hydrate plug formation severity.

Abstract Measurements of the thermodynamic properties for a series of more environmentally-friendly refrigerant mixtures containing hydrofluorocarbons (HFCs), hydrofluoroolefins (HFOs), and carbon dioxide (CO2) were conducted. These new property data help increase confidence in the design and simulation of refrigeration processes that use CO2 + HFO + HFC refrigerant mixtures. The HFCs of interest were R32, R125, and R134a and the HFO tested was R1234yf. The measurements collected were prioritised to fill gaps in the available literature data. Vapour-liquid equilibrium plus liquid-phase density and heat capacity data were collected for different binary mixtures containing HFCs, HFOs and CO2, with the liquid phase measurements spanning (223 to 323) K and (1 to 5) MPa. The measured data, as well as data from the literature, were then used to tune the mixture parameters in the models used by NIST's REFPROP 10 software package to improve the prediction of thermodynamic properties for these fluids. To test the predictive capabilities of the models tuned to the binary mixtures, thermodynamic property data were also measured for four ternary mixtures and a five-component mixture of HFCs, HFOs and CO2. The new models developed in this work significantly improved the root mean square deviations of the predicted properties for these multi-component mixtures: the most significant reductions were about a factor of two in density.

Abstract We report a dual-reflux pressure swing adsorption (DR-PSA) apparatus and cycle configuration to recover an enriched methane product from mixtures of methane and nitrogen containing between (2.4 and 49.6) mol% methane. This range of feed gas compositions is representative of some significant greenhouse gas emissions streams containing methane, including vent streams from liquefied natural gas production facilities and ventilation air from coal mining operations. The DR-PSA apparatus was demonstrated with activated carbon Norit RB3 as the adsorbent, operating with a low pressure step of 1.4 bar and a high pressure step of 5 bar. The effect of light reflux flowrate and heavy product draw on methane recovery and nitrogen vent purity were investigated. The DR-PSA experiment with 2.4 mol% methane in the feed produced a methane product containing 35.7 mol% methane, which is approximately a 15 times enrichment, and a clean nitrogen vent containing just 3000 ppmv methane. In another experiment an enrichment ratio of 21 was achieved for a feed containing 2.4 mol% CH 4 , which is significantly higher than the pressure ratio of 3.6 considered to be the theoretical enrichment limit of conventional PSA cycles. The capture of dilute methane with this DR-PSA process is energetically self-sustainable.

The formation and the blockage of plant equipment such as heat exchangers by heavy hydrocarbon (HHC) solids is an inherent risk in cryogenic natural gas processing. The accuracy of the gas mixture’s compositional characterization significantly impacts the reliability of solid formaiton temperature predictions. Recently, we showed that complete characterization of the mixture is necessary to obtain accurate predictions of the melting temperature, as current methods based on pseudocomponent characterizations of HHCs are inadequate. Here, we present an improved method of characterizing HHCs that represents each pseudocomponent up to C14+ by a paraffinic, isoparaffinic, naphthenic and aromatic (PINA) composition and allocates an associated defined component to represent these sub-fractions. This new, extended PINA-based characterization of HHC pseudocomponents is derived from 46 different pipeline natural gas samples, and the method is validated against three representative gas samples that were fully characterized. The melting temperatures of the three gas samples based on their full characterizations are 263.2 K (14.1 °F), 260.1 K (8.5 °F) and 248.3 K (−12.8 °F), respectively. Predictions made with the new method match these within (1 to 2) K, while previous correlation methods under-predict them by (10 to 20) K. The improved performance arises from (1) the selection of suitable discrete components to represent each PINA fraction within a pseudocomponent, (2) the more representative distribution of PINA fractions as a function of carbon number, and (3) the use of discrete components to represent the pseudocomponent’s thermodynamic properties in both the fluid and solid phases. These results show how the new characterization method can reliably predict HHC freeze-out conditions, particularly when a full compositional analysis is unavailable. Future research should aim to test the new method on natural gas samples from regions other than the US Gulf Coast.

Hydrogen is emerging as one of the most promising energy carriers for a decarbonised global energy system.