Solubility Of Natural Gas Research Articles

The generalized method for estimating reserves of shale gas and coalbed methane reservoirs based on material balance equation

As the main unconventional natural gas reservoirs, shale gas reservoirs and coalbed methane (CBM) reservoirs belong to adsorptive gas reservoirs, i.e., gas reservoirs containing adsorbed gas. Shale gas and CBM reservoirs usually have the characteristics of rich adsorbed gas and obvious dynamic changes of porosity and permeability. A generalized material balance equation and the corresponding reserve evaluation method considering all the mechanisms for both shale gas reservoirs and CBM reservoirs are necessary. In this work, a generalized material balance equation (GMBE) considering the effects of critical desorption pressure, stress sensitivity, matrix shrinkage, water production, water influx, and solubility of natural gas in water is established. Then, by converting the GMBE to a linear relationship between two parameter groups related with known formation/fluid properties and dynamic performance data, the straight-line reserve evaluation method is proposed. By using the slope and the y -intercept of this straight line, the original adsorbed gas in place (OAGIP), original free gas in place (OFGIP), original dissolved gas in place (ODGIP), and the original gas in place (OGIP) can be quickly calculated. Third, two validation cases for shale gas reservoir and CBM reservoir are conducted using commercial reservoir simulator and the coalbed methane dynamic performance analysis software, respectively. Finally, two field studies in the Fuling shale gas field and the Baode CBM field are presented. Results show that the GMBE and the corresponding straight-line reserve evaluation method are rational, accurate, and effective for both shale gas reservoirs and CBM reservoirs. More detailed information about reserves of shale gas and CBM reservoirs can be clarified, and only the straight-line fitting approach is used to determine all kinds of reserves without iteration, proving that the proposed method has great advantages compared with other current methods.

Study on flow characteristics of natural gas containing CO2 invading wellbore during drilling

The dissolution of invaded gas in the drilling fluid during drilling results in an increase in the gas invasion concealment. This is of great significance for the development of acid gas reservoirs to determine the solubility change and multiphase flow law in an annulus after invasion by natural gas with high CO 2 content. In this study, control equations of gas–liquid flow during drilling gas invasion are established considering the influence of gas solubility. For the prediction of gas solubility, the interaction parameters of CH 4 and water in the Peng–Robinson equation of state are optimised to establish a gas solubility prediction model. The solubility of natural gas with high CO 2 content in water and brine solution is measured through phase-equilibrium experiments. The results indicate that the newly optimised solubility model can accurately predict the solubility of CH 4 and CO 2 in water, and the prediction error is within 5%. Moreover, the prediction error for the solubility of CH 4 and CO 2 mixed gas is within 15%. The analysis of gas invasion in example engineering drilling applications reveals that an increase in the CO 2 content in the invaded gas leads to a slow change in the mud-pit increment, and the concealment strengthens as the distance between the gas-migration front and the wellhead increases. Gas solubility has a significant impact on the monitoring of gas invasion in low permeability reservoirs.

Solubility of Natural Gas in Diesel Fuel

AbstractThe solubility of commercially available natural gas in commercially available diesel fuel at room temperature and defined pressure is investigated experimentally. The gas phase is considered to be pure methane. The use of Henry's law to model the solubility is discussed. Solubility is given in terms of the mole fraction and the volumetric mass concentration of dissolved gas and the corresponding Henry's coefficients. The solubility is compared to that of pure methane in pure hexadecane, which is similar to diesel fuel with respect to the mean carbon number.

Variation of Crude Oil Physical Properties and Oil Recovery of Natural Gas Flood Under Different Pressures

ABSTRACTFor the gas flood process, crude oil physical properties including oil volume and viscosity would be greatly changed resulting from gas solution and extraction. First, solubility of natural gas in oil and brine was measured and compared. Meanwhile, the resulting oil expansion and viscosity reduction were experimentally tested. Second, oil viscosity increase due to extraction was studied by extraction experiments. Finally, oil recovery of natural gas and propane-enriched natural gas flood was studied under different pressures. Results show that solubility of natural gas in oil is dozens of times of that in brine. Variation of crude oil physical properties during natural gas injection mainly includes the remarkable volume expansion and viscosity reduction caused by gas dissolution into oil, and the oil volume shrinkage and viscosity increase caused by extraction are not so significant. The oil recovery of natural gas flood grows linearly with increased injection pressure and gas solubility in oil, but is still less than 90% even at 55 MPa, which indicates immiscible flood at 55 MPa. Addition of propane to natural gas is proved to be helpful for enhancing oil recovery and achieving miscibility.

Characteristics and accumulation mechanisms of the Dongfang 13-1 high temperature and overpressured gas field in the Yinggehai Basin, the South China Sea

The Dongfang 13-1 is located in the diapiric structure belt of the Yinggehai Basin. The formation pressure of its main gas reservoir in the Miocene Huangliu Formation is up to 54.6 MPa (pressure coefficient=1.91) and the temperature is as high as 143°C (geothermal gradient 4.36°C/100 m), indicating that it is a typical high-temperature and overpressured gas reservoir. The natural gas is interpreted to be coal-type gas derived from the Miocene mature source rocks containing type II2–III kerogens as evidenced by high dryness index of up to 0.98 and heavy carbon isotopes, i.e., the δ13C1 ranging from −30.76‰ to −37.52‰ and δ13C2 ranging from −25.02‰ to −25.62‰. The high temperature and overpressured Miocene petroleum system is related mainly to diapir in the Yinggehai Basin and contains more pore water in the overpressured reservoirs due to undercompaction process. The experimental and calculated results show that the solubility of natural gas in formation water is as high as 10.5 m3/m3 under the temperature and pressure conditions of the Sanya Formation, indicating that at least part of the gas may migrate in the form of water-soluble phase. Meanwhile, the abundant gas source in the Basin makes it possible for the rapid saturation of natural gas in formation water and exsolution of soluble gas. Therefore, the main elements controlling formation of the Dongfang 13-1 gas pool include that (1) the diapir activities and accompanying changes in temperature and pressure accelerate the water-soluble gas exsolution and release a lot of free gas; (2) submarine fan fine sandstone in the Huangliu Formation provides good gas-water segregation and accumulation space; and (3) the overlying overpressured mud rocks act as effective caps. The accumulation mechanism reveals that the high temperatural and high pressure structure belt near the diapir structures has a good potential for large and medium-sized gas field exploration.

Hydrate Formation/Dissociation in (Natural Gas + Water + Diesel Oil) Emulsion Systems

Hydrate formation/dissociation of natural gas in (diesel oil + water) emulsion systems containing 3 wt% anti-agglomerant were performed for five water cuts: 5, 10, 15, 20, and 25 vol%. The natural gas solubilities in the emulsion systems were also examined. The experimental results showed that the solubility of natural gas in emulsion systems increases almost linearly with the increase of pressure, and decreases with the increase of water cut. There exists an initial slow hydrate formation stage for systems with lower water cut, while rapid hydrate formation takes place and the process of the gas-liquid dissolution equilibrium at higher water cut does not appear in the pressure curve. The gas consumption amount due to hydrate formation at high water cut is significantly higher than that at low water cut. Fractional distillation for natural gas components also exists during the hydrate formation process. The experiments on hydrate dissociation showed that the dissociation rate and the amount of dissociated gas increase with the increase of water cut. The variations of temperature in the process of natural gas hydrate formation and dissociation in emulsion systems were also examined.

Gas Solubility Measurement for Waxy Crude Oil Saturated with Nitrogen and Natural Gas

With self-developed solubility determining unit, gas volume solubility of Daqing waxy crude oil saturated with nitrogen and natural gas was measured respectively at temperatures of 50°C, 55°C, 60°C and 65°C and under pressures from 2 to 20 MPa. The gas volume solubility in the crude oil is increased with the increasing of pressure for both nitrogen and natural gas at every temperature tested, which the increased extent of gas solubility of natural gas is much higher than that of nitrogen. Solubility of natural gas increases with the decreasing of temperature, but that of nitrogen increases with the increasing of temperature. Pressure has a main effect on gas volume solubility.

Study of different factors affecting the electrical properties of natural gas reservoir rocks based on digital cores

The effects of the wettability and solubility of natural gas in formation water on the electrical properties of natural gas reservoir rocks are studied using the finite element method based on digital cores. The results show that the resistivity index of gas-wet reservoir rocks is significantly higher than that of water-wet reservoir rocks in the entire range of water saturation. The difference between them increases with decreasing water saturation. The resistivity index of natural gas reservoir rocks decreases with increasing additional conduction of water film. The solubility of natural gas in formation water has a dramatic effect on the electrical properties of reservoir rocks. The resistivity index of reservoir rocks increases as the solubility of natural gas increases. The effect of the solubility of natural gas on the resistivity index is very obvious under conditions of low water saturation, and it becomes weaker with increasing water saturation. Therefore, the reservoir wettability and the solubility of natural gas in formation water should be considered in defining the saturation exponent.

Solubility Measurement of Natural Gas in Reservoir Formation Water under (333.2 to 393.2) K and (15.0 to 43.6) MPa

The solubility of five groups of natural gas in reservoir formation water was measured under (333.2 to 393.2) K and (15.0 to 43.6) MPa. The formation water and corresponding natural gas were sampled in situ from a China oilfield. The range of total dissolved solids (TDS) of the reservoir formation water samples is from (8744 to 80634) mg·kg−1. The mole fraction of methane in natural gas ranges from 0.7575 to 0.9449. The experimental results show that, with the increase of temperature and pressure, the solubility of natural gas in formation water goes through a minimum value under the experimental conditions. The solubility of natural gas in formation water was also influenced by a composition of gas phase and TDS of liquid phase. The salt effect becomes more significant in the high-pressure region.

Prediction of Stability Zones and Occurrence Zones of Multiple Composition Natural Gas Hydrate in Marine Sediment

We study the features of multiple composition natural gas in stability zones and occurrence zones of hydrate in seafloor. First, the stability surface of hydrate formation with multiple composition natural gas including methane and propane is set up by regression fitting. The effect of salinity in liquid on stability curved surface is considered by interpolation. Based on the model of hydrate prediction, the ranges of stability zones and occurrence zones are computed for only methane or different fractions of methane and propane with different salinity. Comparing these results, we find that the effect of little propane on stability zones and occurrence zones is stronger than that of single methane gas. Apparently, it is because propane has larger effect on the stability temperature and the solubility of natural gas. The effects of other compositions such as CO2, C2H6 and H2S are briefly discussed in the paper.

An EOS for High-Pressure Aqueous Electrolyte Systems—Predicting the Solubility of Natural Gas in Formation Water

Summary A new Helmholtz energy equation is developed for high-pressure aqueous electrolyte systems, and a corresponding equation of state (EOS) is derived. The model parameters are determined from ionic activity coefficient and vapor/liquid equilibrium data of binary and ternary mixtures. The new EOS predictions of the solubilities of pure gas and natural gas mixtures in brines show satisfactory agreement with measured experimental data.

Multiple Condensed Phases in the Methane-Decane-Tetralin-Bitumen System

Abstract As a part of a general investigation of the separation of bitumen fromhydrocarbon mixtures a study was made of a restricted quaternary systemcomposed of methane, decane, tetralin, and bitumen. The work was limited to apressure of 8000 psi, a temperature of 220'F, and to a fixed relativeproportion of decane, tetralin, and bitumen. The measurements permitted thedetermination of the distribution of these components in each of the fluidphases. It was not possible to distinguish a second liquid phase in the courseof these measurements. Gas-liquid equilibrium "constants" of each ofthe components were found to vary markedly with the composition of the systemwhile temperature and pressure remained fixed. Introduction The separation of bitumen from naturally occurring hydrocarbon mixtures hasbeen of importance for a number of years in the production of petroleum, especially in the California area. The deposition of this material from crudeoils was noted in earlier studies of the solubility of natural gas in crudeoil. Studies of the separation of bitumen from crude oils from the Greeley andSanta Fe Springs fields were carried out. The behavior of these systemsappeared complex and studies of two restricted ternary systems involvingmixtures of n-pentane, tetralin, and bitumen, and of decane, tetralin, andbitumen, confirmed this belief. Reviews of the literature pertaining to theseparation of bitumen from naturally occurring and refined hydrocarbons areavailable. The important effect of methane in the separation of bitumen from naturallyoccurring hydrocarbon mixtures was apparent from the earlier studies, and forthat reason it appeared desirable to investigate a restricted quarternarysystem involving mixtures of methane, decane, tetralin, and bitumen; dataconcerning the behavior of mixtures of decane, tetralin, and bitumen havingalready been obtained. This study was restricted to a pressure of 8000 psi, atemperatue of 220'F, and fixed relative proportions of bitumen, decane, andtetralin. This composite constituent, hereinafter designated as the lessvolatile constituent, was made up of 0.0455 weight fraction bitumen, 0.0909weight fraction decane, and 0.8636 weight fraction tetralin. The experimental method involved bringing together mixtures of methane and theless volatile constituent in varying proportions in a constant volume containerat the pressure and temperature indicated above. The composition of each of thephases was determined and from this the extent of the separation of bitumen wasestablished. T.P. 2718

Preliminary Report on an Investigation of the Bureau of Mines Regarding the Solubility of Natural Gas in Crude Oil

Petroleum engineers generally are familiar with the investigations of Dowand Reistle, Beecher and Parkhurst, and Dow and Calkin, relative to thesolubility of natural gas in crude oil. Since the publication of the results ofthose investigations and the work of Mills and Heithecker little additionalknowledge on this interesting and important subject has appeared in thepetroleum engineering literature. The reports of Beecher and Parkhurst and Dow and Calkin agree substantially.The data from both investigations showed that, under the conditions of thetests, the solubility of natural gas in crude oil increased in directproportion to the pressure at which the gas was put into solution, and thesolubility decreased to a considerable extent with increased temperature. Thesefacts, and others relating to the changes in viscosity, surface tension andspecific gravity of the crude caused by the solution of gas in the oil, havebeen given due consideration in the petroleum industry, and the recognition ofthese facts has resulted in a great improvement in the technique of producingoil. However, in these first experiments, various grades and types of weatheredcrude oil were contacted at various pressures up to 500 lb. per sq. in. gagewith gases deficient to a considerable degree in the heavier hydrocarbons, ascompared with the gas that was originally in solution in the oil in its naturalunderground reservoir. The amount of dissolved gas that was liberated uponreducing the pressure to 1 atm. was measured. For these reasons, the completesignificance of the effect of dissolved gases in crude oil, as it occurs innature, cannot be determined directly from the data obtained under theconditions of the tests as described.