Natural Gas CO2 Research Articles

Origin and source of CO2 in natural gas from the eastern Sichuan Basin

The CO2 contents of natural gas from the eastern Sichuan Basin were mainly less than 2%, and they were generally large when the H2S contents were over 5%. The natural gas in the eastern Sichuan Basin showed high δ 13C1 values uncorrelated with H2S contents, and the oil-associated gas generally displayed carbon isotopic reversal between methane and ethane, whereas the coal-derived gas samples displayed positive series. The δ 13C values of CO2 in the natural gas could be divided into two types, one with low values (−24‰–−12‰) and the other with high values (−8‰–4‰). The natural gas had low R/Ra values and broad CO2/3He values distinct from the mantle-derived gas, and the CO2 was typical of crustal origin. Natural gas with high δ 13CCO2 values is distributed in the north region of the eastern Sichuan Basin, and CO2 in H2S-poor and H2S-free reservoirs was mainly derived from the thermal decomposition of carbonate rocks under Permian magmatism and high heat flow, whereas CO2 in the gas reservoirs with high TSR extent was derived mainly from the dedolomitization of carbonate reservoirs under acidic formation water, and the CO2 of TSR origin generally entered into the secondary calcite. The CO2 in natural gas in the south-central region of the eastern Sichuan Basin, which had been rarely affected by the Emeishan mantle plume, displayed low δ 13C values and was of organic origin. Though the natural gas in Wolonghe gas field had experienced TSR, the low reaction extent and weak acidity of formation water could hardly have resulted in the dedolomitization, and therefore CO2 in the natural gas was mainly of TSR origin with low δ 13C values.

Carbon dioxide removal from methane by using polysulfone/SAPO-44 mixed matrix membranes

Removal of CO2 in natural gas refining has currently been the only membrane based process practiced on a large scale operation. Despite the predominance of polymeric membranes in the CO2/CH4 separation, the tradeoff limitation in between membrane selectivity and permeability hinders a good separation performance of these membranes. Mixed matrix membranes can offer dramatic improvement to overcome this shortcoming. In this study, polysulfone mixed matrix membranes incorporated with small pore zeolite were proposed for CO2 separation. SAPO-44 zeolite was used as inorganic fillers to enhance gas selectivity. The asymmetric membrane structure was prepared using the phase inversion method in order to improve permeance. The effects of zeolite loading (5–20wt.%) on the membranes characteristic were studied using SEM and FTIR, while the gas transport properties were investigated using pure gas permeation tests of N2, CO2 and CH4 for each membrane. The most optimum sample is the membrane with 5wt.% of SAPO-44 loading, which exhibited improved CO2/N2 and CO2/CH4 selectivities of 22 and 25, respectively, compared to other samples. Devoid of any modification of filler phase, the addition of SAPO-44 inside polysulfone mixed matrix membranes has significantly enhanced CO2 separation performance.

Identifying and quantifying natural CO2 sequestration processes over geological timescales: The Jackson Dome CO2 Deposit, USA

CO2 sources, sinks and migration mechanisms in natural CO2 gas fields provide critical analogues for developing the safe application of anthropogenic CO2 sequestration technologies. Here we use noble gas and carbon isotopes, together with other gases, to identify and quantify the origin, transport and trapping mechanisms of CO2 in the Late Cretaceous Jackson Dome CO2 gas deposit (98.75% to 99.38% CO2). Located in central Mississippi, USA, and producing from >5000m, it is one of the deepest commercial CO2 gas fields in the world. 10 gas samples from producing wells were determined for their noble gas, chemical and stable carbon isotope composition. 3He/4He ratios range between 4.27Ra and 5.01Ra (where Ra is the atmospheric value of 1.4×10−6), indicating a strong mantle signature. Similar to CO2 deposits worldwide, CO2/3He decreases with increasing groundwater-derived 20Ne (and 4He). We model several different processes that could account for the Jackson Dome data, and conclude that, similar to other CO2 dominated deposits, a Groundwater Gas Stripping and Re-dissolution (GGS-R) process best accounts for observed 20Ne/36Ar, 84Kr/36Ar, CO2/3He, δ13C(CO2), 4He, 20Ne and 36Ar. In this context, crustal and magmatic CO2 components contribute 57% and 43%, respectively. Changes in CO2/3He across the field show that groundwater contact is responsible for up to 75% loss of original emplaced CO2. δ13C(CO2) variance limits the degree of precipitation to be less than 27%, with the remaining CO2 loss being accounted for by dissolution only. A higher degree of dissolution gas loss and evidence for water contact at the reservoir crest compared to the reservoir flanks is used to argue that CO2 in this system has not undergone subsequent loss to either dissolution or precipitation since shortly after reservoir filling at over 60Ma.

Leakage risk assessment of the In Salah CO2 storage project: Applying the certification framework in a dynamic context

Abstract The Certification Framework (CF) is a simple risk assessment approach for evaluating CO2 and brine leakage risk at geologic carbon sequestration (GCS) sites. In the In Salah CO2 storage project assessed here, five wells at Krechba produce natural gas from the Carboniferous C10.2 reservoir with 1.7–2% CO2 that is delivered to the Krechba gas processing plant, which also receives high- CO2 natural gas (∼10% by mole fraction) from additional deeper gas reservoirs and fields to the south. The gas processing plant strips CO2 from the natural gas that is then injected through three long horizontal wells into the water leg of the Carboniferous gas reservoir at a depth of approximately 1,800 m. This injection process has been going on successfully since 2004. The stored CO2 has been monitored over the last five years by a Joint Industry Project (JIP)–a collaboration of BP, Sonatrach, and Statoil with co-funding from US DOE and EU DG Research. Over the years the JIP has carried out extensive analyses of the Krechba system including two risk assessment efforts, one before injection started, and one carried out by URS Corporation in September 2008. The long history of injection at Krechba, and the accompanying characterization, modeling, and performance data provide a unique opportunity to test and evaluate risk assessment approaches. We apply the CF to the In Salah CO2 storage project at two different stages in the state of knowledge of the project: (1) at the pre-injection stage, using data available just prior to injection around mid-2004; and (2) after four years of injection (September 2008) to be comparable to the other risk assessments. The main risk drivers for the project are CO2 leakage into potable groundwater and into the natural gas cap. Both well leakage and fault/fracture leakage are likely under some conditions, but overall the risk is low due to ongoing mitigation and monitoring activities. Results of the application of the CF during these different state-of-knowledge periods show that the assessment of likelihood of various leakage scenarios increased as more information became available, while assessment of impact stayed the same. Ongoing mitigation, modeling, and monitoring of the injection process is recommended.

Origin of CO2 in natural gas from the Triassic Feixianguan Formation of Northeast Sichuan Basin

The natural gas from the Triassic Feixianguan Formation of Northeast Sichuan Basin contains high H2S whereas relatively low CO2 concentrations and the CO2 display high δ13C values (ranging from −5.81‰ to 3.3‰ (PDB)). This seems to contradict the conventional wisdom that TSR should be a primary source of CO2 in natural gas from the Feixianguan Formation. In contrast, many authigenic calcite samples from these sites display very low δ13C values (ranging from −18.4‰ to −10.3‰ (PDB)). This suggests that the carbon from TSR source dominated the formation of calcite whereas the carbon from inorganic source came into CO2 in natural gas. In order to assess the origin of CO2 from these H2S-rich sites, we have calculated the relative contributions of organic and inorganic carbon sources to the CO2 and authigenic calcite. The organic carbon source possibly originated from TSR, whereas the inorganic one might be generated from marine carbonates dissolution. This calculation is based on the carbon isotopic compositions of CO2 and authigenic calcite as well as an isotopic mass balance. The results show that the contribution of organic carbon source to the CO2 is only 2%, whereas that to authigenic calcite is as high as 43% on average. Such results combined with thermodynamic evidence indicate that the isotopically light CO2 produced by TSR process may contribute to authigenic calcite precipitation during burial diagenesis. Distinguishable from Ordovician reservoir of Tarim Basin, Feixianguan reservoir of Northeast Sichuan Basin experienced rapid tectonic uplift due to Yanshanian movement after TSR occurred. Such tectonic event could induce temperature decrease and further promote carbonates dissolution. During these processes, secondary porosity has developed in Feixianguan carbonate reservoirs. Therefore, much attention should be paid to the structural highs in search of high quality carbonate reservoirs.

Thermochemical Sulfate Reduction in the Tazhong District, Tarim Basin, Northeast China: Evidence from Formation Water and Natural Gas Geochemistry

Abstract:Systematic analyses of the formation water and natural gas geochemistry in the Central Uplift of the Tarim Basin (CUTB) show that gas invasion at the late stage is accompanied by an increase of the contents of H2S and CO2 in natural gas, by the forming of the high total dissolved solids formation water, by an increase of the content of HCO−3, relative to Cl−, by an increase of the 2nd family ions (Ca2+, Mg2+, Sr2+ and Ba2+) and by a decrease of the content of SO2−4, relative to Cl−. The above phenomena can be explained only by way of thermochemical sulfate reduction (TSR). TSR often occurs in the transition zone of oil and water and is often described in the following reaction formula: σCH+CaSO4+H‐2O→H2S+CO2+CaCO3. (1) Dissolved SO2−4 in the formation water is consumed in the above reaction, when H2S and CO2 are generated, resulting in a decrease of SO2−4 in the formation water and an increase of both H2S and CO2 in the natural gas. If formation water exists, the generated CO2 will go on reacting with the carbonate to form bicarbonate, which can be dissolved in the formation water, thus resulting in the enrichment of Ca2+ and HCO−3. The above reaction can be described by the following equation: CO2+H2O+CaCO3→Ca2++2HCO−3. The stratigraphic temperatures of the Cambrian and lower Ordovician in CUTB exceeded 120°C, which is the minimum for TSR to occur. At the same time, dolomitization, which might be a direct result of TSR, has been found in both the Cambrian and the lower Ordovician. The above evidence indicates that TSR is in an active reaction, providing a novel way to reevaluate the exploration potentials of natural gas in this district.

Clinical and microcirculatory effects of transcutaneous CO2 therapy in intermittent claudication. Randomized double-blind clinical trial with a parallel design

This randomized, double blind trial determined the short and long-term clinical and hemodynamic vasodilator effects induced by percutaneous applications of natural CO2 gas in patients with moderate Fontaine stage II. 62 patients with intermittent claudication (100-500 meters) were randomized to 18 consecutive days of CO2 treatment or placebo (air). The gas fluids were applied at a constant temperature of 30 degrees C on pre-humidified skin. The effects of the treatment were evaluated by total distance walked (primary criterion) and hemodynamic and microcirculatory findings. Patients also answered a quality of life questionnaire. The Strandness test showed a significant increase in total distance walked (+ 131 meters, 66%; p = 0.001) and pain-free distance (+ 81 meters, 73%; p = 0.02) after 18 days of CO2 treatment. The improvement was maintained 3 and 12 months later. The systolic pressure index (ABI) increased by 37% (p = 0.001) 1 minute after treadmill walking and ABI recovery time decreased significantly by 38% (p = 0.002). Microcirculatory findings showed an increase in systolic pressure of the great toe (13%; p < 0.0001), in baseline pO2 (20%; p = 0.01) and in vasomotion (78%; p = 0.001) in the treatment group. The improvement in total walking distance was correlated with the increase in ABI and peripheral cutaneous oxygenation. Patients' subjective assessments corroborated the benefits. No significant change was observed in the placebo group. This study demonstrates that 18 consecutive days of percutaneous CO2 treatment significantly increases walking distance in patients with moderate intermittent claudication. This effect, which was associated with an increase in peripheral systolic pressure and pO2, is evidence of a better ability to withstand effort.

Cryogenic CO2 capture in natural gas

Abstract Increasing world energy demand and pricing trends have encouraged oil and gas companies to look at developing contaminated natural gas fields previously deemed uneconomic. At the same time, world wide perceptions on climate change are pressuring energy companies to adopt global best practices to reduce carbon emissions. Developing currently unviable contaminated natural gas fields requires developing new technologies for high CO2 gas treatment. Current technologies available in the market for natural gas treating may not be ideally suitable for treating highly contaminated natural gas where CO2 geo-sequestration is required. Use of physical and chemical absorption solvents have been the most popular method for treating natural gas with high CO2, and to a lesser extent, membranes and adsorption methods. These technologies remove CO2 at near ambient pressures thus requiring substantial amount of compression to levels needed for geo-sequestration. Cryogenic CO2 removal methods can capture CO2 in a liquid form thus making it relatively easy to pump underground for storage or send for enhanced oil recovery. This new cryogenic CO2 removal method has been researched and tested in a demonstration plant and is soon to be implemented in commercial field applications. This paper intends to share recent field experience and test results from Cool Energy’s CryoCell® demonstration plant in Western Australia. The CryoCell® process was developed by Cool Energy Ltd and tested in collaboration with other industrial partners including Shell Global Solutions. This presentation will also discuss and compare existing CO2 treatment technologies for developing high CO2 natural gas fields requiring CO2 geo-sequestration with the CryoCell® CO2 capture process. Basic economic comparisons between the CryoCell® process and an amine based process including CO2 geo-sequestration will be presented.

Seawater subduction controls the heavy noble gas composition of the mantle

The relationship between solar volatiles and those now in the Earth's atmosphere and mantle reservoirs provides insight into the processes controlling the acquisition of volatiles during planetary accretion and their subsequent evolution. Whereas the light noble gases (helium and neon) in the Earth's mantle preserve a solar-like isotopic composition, heavy noble gases (argon, krypton and xenon) have an isotopic composition very similar to that of the modern atmosphere, with radiogenic and (in the case of xenon) solar contributions. Mantle noble gases in a magmatic CO2 natural gas field have been previously corrected for shallow atmosphere/groundwater and crustal additions. Here we analyse new data from this field and show that the elemental composition of non-radiogenic heavy noble gases in the mantle is remarkably similar to that of sea water. We challenge the popular concept of a noble gas 'subduction barrier'--the convecting mantle noble gas isotopic and elemental composition is explained by subduction of sediment and seawater-dominated pore fluids. This accounts for approximately 100% of the non-radiogenic argon and krypton and 80% of the xenon. Approximately 50% of the convecting mantle water concentration can then be explained by this mechanism. Enhanced recycling of subducted material to the mantle plume source region then accounts for the lower ratio of radiogenic to non-radiogenic heavy noble gas isotopes and higher water content of plume-derived basalts.

Seawater subduction controls the heavy noble gas composition of the mantle

The relationship between solar volatiles and those now in the Earth's atmosphere and mantle reservoirs provides insight into the processes controlling the acquisition of volatiles during planetary accretion and their subsequent evolution. Whereas the light noble gases (helium and neon) in the Earth's mantle preserve a solar-like isotopic composition, heavy noble gases (argon, krypton and xenon) have an isotopic composition very similar to that of the modern atmosphere, with radiogenic and (in the case of xenon) solar contributions. Mantle noble gases in a magmatic CO2 natural gas field have been previously corrected for shallow atmosphere/groundwater and crustal additions. Here we analyse new data from this field and show that the elemental composition of non-radiogenic heavy noble gases in the mantle is remarkably similar to that of sea water. We challenge the popular concept of a noble gas 'subduction barrier'--the convecting mantle noble gas isotopic and elemental composition is explained by subduction of sediment and seawater-dominated pore fluids. This accounts for approximately 100% of the non-radiogenic argon and krypton and 80% of the xenon. Approximately 50% of the convecting mantle water concentration can then be explained by this mechanism. Enhanced recycling of subducted material to the mantle plume source region then accounts for the lower ratio of radiogenic to non-radiogenic heavy noble gas isotopes and higher water content of plume-derived basalts.

Microcirculatory and clinical effects of serial percutaneous application of carbon dioxide in primary and secondary Raynaud’s phenomenon

A randomized double-blind monocentric trial was conducted at the spa of Royat, France, in patients with mild Raynaud's phenomenon (one or two attacks a day during the autumn and winter months). Hemodynamic changes were quantified by laser Doppler flow (LDF) and computerized chronothermometric test (CT) during local application of CO2 and compared with the usual clinical parameters. Patients were randomized to 18 days of CO2 (group 1) or 9 days of air + 9 days of CO2 (group 2). The gas was applied at a constant temperature to previously humidified skin on the forearm. Effects of the active treatment were measured by LDF and continuing benefits by computerized chronothermometric test (CT test). Clinical assessment was made on four occasions (before, in the middle and at the end of treatment, and three months afterwards) on the basis of the number of daily attacks and the duration and severity of the attacks. LDF showed a significant increase in digital blood flow (+ 41%) and in vasomotion (+ 42%) during CO2 treatment but no change on placebo treatment. CT test showed a comparable response to cold in the two groups during treatment. Three months later, however, warming time was significantly decreased (by 7 minutes: 25%) and warming rate increased (+ 22.4%) in group 1 (intergroup difference: p = 0.02). There was no difference between groups in the weekly number of attacks during treatment periods. In contrast there was a moderate increase in both groups in the winter months. There was no increase in the severity of the attacks nor in their duration. In this clinical trial, LDF evidenced positive effects of percutaneous application of natural CO2 gas on vasomotricity and vasomotion while CT test showed that patients who had received 18 days of CO2 adapted more easily to exposure to cold. Clinical improvement seems to be masked by winter weather conditions.

Geochemistry, origin, and accumulation of CO2 in natural gases of the Yinggehai Basin, offshore South China Sea

Geochemical and isotopic data indicate the presence of CO2 of both organic and inorganic origin in the natural gas reservoirs of the Yinggehai Basin. The natural gases with inorganic CO2 commonly show a high content of CO2, ranging from 15 to 85%; a heavier carbon isotope value of CO2, from 0.56 to 8.16; and a lower 3He/4He ratio, ranging from 0.20 to 6.79 107, indicating a crustal origin. These gases occur locally, commonly related to diapir structures. Natural gases rich in hydrocarbons occur widely and are characterized by a low CO2 content, from 0.1 to 5.0%, and a lighter C1 carbon isotope value from 10.59 to 20.7, indicating an organic origin. Geological background and geochemical data indicate that the Sanya and Meishan formations are the main source of hydrocarbon gases and the organic CO2. Pyrolysis experiments on Tertiary calcareous shales and thermal history modeling both suggest that the calcareous shales occurring in the lower Miocene strata are the main source of the inorganic CO2 gas, whereas thermal contact metamorphism of the Paleozoic carbonates and/or magmatic CO2 may have made only a small contribution. Abnormally high paleogeothermal gradients (4.25–4.56C/100 m; 12.09–12.26F/100 ft) and a rapid heating rate caused the lower Miocene calcareous shales to reach the threshold temperature (about 300C [570F]) of their thermal decomposition at the burial depth of about 6500 m (21,300 ft) and to generate great volumes of inorganic CO2 gas. Diapir faults acted as the main pathways for the upward migration of deep inorganic CO2 gases into reservoirs connected with shale diapirism along the central Yinggehai Basin. The heavier carbon isotope values of associated methanes and a strong thermal anomaly in the CO2-rich gas reservoirs provide evidence that the inorganic CO2 gas migrated into the reservoirs later than their associated hydrocarbon-rich gases. This suggests that the earlier formed traps and sandstone reservoirs distant from shale diapir structures may have greater potential in the exploration for hydrocarbon-rich gases.

Lean-Burn Cogeneration Biogas Engine with Unscavenged Combustion Prechamber: Comparison with Natural Gas

Gaseous fuels produced, for example, by waste or agricultural by-products fermentation (biogas) can be burned in-situ by cogeneration systems like spark-ignition internal combustion engines. However, the more and more stringent legislation for exhaust gas emissions requires improvement of the combustion process particularly when catalytic after treatment is not reliable as in the case of sewage or landfill biogas. The system proposed in this paper is the use of an unscavenged combustion prechamber instead of direct ignition on a turbocharged 6 cylinder 150 kW gas engine. This prechamber is used for operation with a simulated biogas (40% CO2 in natural gas). The results show that, compared to natural gas operation for the same rated power output of 150 kW and the same NOx emissions, the CO emissions are reduced by 15% and the HC emissions at least by 8%. Efficiencies higher than 36% are achieved which is very promising and the lower CO emissions give a margin to consider an increase of compression ratio.

Magmatic CO2 in natural gases in the Permian Basin, West Texas: identifying the regional source and filling history

The origin of regional CO2 occurrences within basinal fluids cannot be resolved with stable isotopes alone because magmatic and crustal δC13(CO2) ranges are non-unique. 3He/CO2 from magmatic systems such as mid-ocean ridges fall within a tight range (109–1010) compared with values found in crustal fluids (105–1013). Although crustal fluids with 3He/CO2 within the magmatic range clearly have a significant magmatic component, the possibility of crustal CO2 addition or reactive loss of CO2 makes a quantitative assessment of the magmatic contribution non-trivial. In this paper we present a combination of high-precision δC13(CO2) and 3He/CO2 from the CO2-rich (20–55%) JM-Brown Basset gas field, West Texas. In this field 3He/CO2 is in the magmatic range and varies between 4.1 and 6.2×109. This variation is directly correlated with %CO2. We use the very small range in δC13(CO2) (−2.70 to −3.06‰) to rule out either precipitation or crustal addition of CO2 being the cause of the 3He/CO2 variation. 3He has no significant crustal sources or sinks. A model of variable magmatic outgassing (up to 20%) is consistent with the range in observed 3He/CO2 and δC13(CO2). Within the context of this model, all of the CO2 in this gas field is magmatic. Furthermore samples preserving the highest 3He/CO2 represent the earliest phase of magmatic degassing and provide a temporal and spatial filling history for the gas field. In the regional context we show that our results are consistent with a regional magmatic CO2 source to the North of the Marathon Thrust Fault system. This CO2 must have been in place before significant generation of CH4 and other hydrocarbons filled these reservoirs from the same direction, overprinting the magmatic CO2.

Implication to mantle-derived CO2 in natural gases of huanghua depression using helium and argon isotope tracer

Implication to mantle-derived CO2 in natural gases of huanghua depression using helium and argon isotope tracer

CO2 in Natural Gases of Brazilian Sedimentary Basins: ABSTRACT

CO2 in Natural Gases of Brazilian Sedimentary Basins: ABSTRACT

Relationships Among Carbon Dioxide, Pore-Fluid Chemistry, and Secondary Porosity, Texas Gulf Coast: ABSTRACT

Sequences of diagenetic minerals associated with secondary porosity show striking similarities. The formation of quartz overgrowths on detrital quartz grains is followed generally by carbonate cementation. The dissolution of this carbonate is the main secondary porosity-forming event, which commonly precedes kaolinite precipitation and iron-rich carbonate cementation. In the Texas Gulf Coast, oxygen isotopic analyses provide temperature estimates of authigenic phases that predate and postdate secondary porosity development: quartz, >= 80°C (176°F); kaolinite, >= 70°C (158°F); albite, 100°-150°C (212°-302°F); late carbonate, > 100°C (212°F). These data suggest that secondary porosity in the Tertiary Gulf Coast form at temperatures of about 100° ± 25°C (212° ± 45°F). Correlations among calcite saturation indices in pore fluids, abnormally high permeabilities, and mole % CO2 in natural gases of the Eocene Wilcox Group imply a strong interrelationship between CO2 and secondary porosity development in clastic reservoirs. The CO2 content of gases varies systematically with both the reservoir age and temperature, which suggests a kinetic control on generation. The amount of CO2 in natural gases increases rapidly at approximately 100°C (212°F); this coincides with a rapid increase in the ratio of secondary to primary porosity in associated sandstones. Stable isotopic analyses of carbonate cements indicate a strong component of organically derived carbon and therefore cycling of carbon between inorgan c and organic systems. The type, amount and distribution of organic matter, and early carbonate in both shales and sandstones control the quantity of CO2 available for generating secondary porosity. End_of_Article - Last_Page 478------------

Compressibility Factors for CO2-Methane Mixtures

Compressibility factors from a high-ratio CO2-natural gas mixture are compared with other experimental data and values calculated using two correlations. Discussion includes the use of these factors in monitoring reservoir performance for the SACROC Unit CO2 injection project. Introduction The SACROC Unit CO2 injection project in Scurry County, Tex., required transporting 200 Mcf/D of CO2 for 200 miles. A feasibility study of the mode of transportation resulted in selection of a "supercritical-pressure-state" pipeline system. A study was made of available data on compressibility (z) factors for CO2-natural gas at supercritical pressures, as well as of two engineering calculation methods. This study indicated that the z factors should be measured rather than taken from published information. This paper compares our measured compressibility factors with calculated and published compressibility data, and describes applications of z factors to the various phases of the SACROC Unit CO2 injection project. phases of the SACROC Unit CO2 injection project. Experimental PVT Data There were two reasons for measuring z factors rather than relying on published information:Reamer et al.'s data for the CO2-methane system did not include C2+, which is contained in the pipeline gas.For engineering purposes, corresponding-state and equation-of-state calculation methods are not accurate enough near the critical point. CO2 pipeline design conditions include the critical point. Our measurements were made in a visual PVT cell using the CO2-natural gas mixture described in Table 1. Conditions ranged from 680 to 3,001 psia and 49 to 120 degrees F. Tables 2 and 3 and Fig. 1 show the experimental results along with the calculated values and Reamer et al.'s data. Experimental Method The gas used for the compressibility-factor measurements was prepared from pure compounds. It was analyzed by determining the CO2 in an Orsat apparatus (thus removing the CO2) and chromatographing the re-reminder of the gas. The liquid-vapor, two-phase boundary of the gas was estimated, and the gas pressure was kept above the cricondenbar to insure single-phase transfer from a storage vessel to the visual PVT cell. In the visual cell, the pressure was decreased in steps and the volume was measured at each step. This pressure-volume relation was determined at 49, 70, 90, and pressure-volume relation was determined at 49, 70, 90, and 120 degrees F. At 49 and 70 degrees F we observed bubble points and a dew point. Compressibility factors were points and a dew point. Compressibility factors were calculated from the pressure, volume, and temperature values (z = pV/RT). Experimental Results Table 1 shows the analysis of the gas used, along with the measured specific gravity and volumetric expansion values. Table 2 shows the measured z factors for the four temperatures. These data are plotted in Fig. 2 with the observed bubble and dew points. JPT P. 81

Generalized Correlations for Predicting Solubility, Swelling and Viscosity Behavior of CO2 -Crude Oil Systems

Abstract This paper presents correlations for predicting the solubility, swelling and viscosity behavior of CO2-crude oil systems. The correlations were developed from experimental data obtained by the authors. These data are also presented. The data were determined by measuring the properties of mixtures of CO2 and nine different oils. Experimental conditions covered a range of 100 to 250 degrees F and pressures up to 2,300 psia. Properties predicted by the correlations have average deviations, expressed as per cent of experimental value, of 2 per cent for solubility, 0.5 per cent for swelling and 12 per cent for viscosity. Introduction Interest in CO2 injection as an oil recovery process has led to the development of performance prediction methods which can be applied to specific reservoirs. To use these performance prediction methods, it is necessary to know the solubility, swelling, and viscosity properties of CO2-crude oil mixtures at reservoir conditions. Some information on these properties has appeared in the literature; however, this information did not cover the range of different oils and conditions needed to prepare generalized correlations for reservoir engineering purposes. Consequently, an experimental program was undertaken to collect the data needed. The data obtained and the correlations developed from the data are described in the following sections of this paper. SOLUBILITY OF CO2 IN CRUDE OILS CO2 solubility data in the literature come from six principal sources. The solubility prediction method of Welker and Dunlop is limited to 80F.The information in Ref. 4 is of two types: the first includes binary and ternary mixtures of CO2 and light hydrocarbons (C1 to C6), and the second gives data for CO2 and heavy hydrocarbons for a temperature range of 40 to 90F.Ref. 5 contains a KCO2 chart for systems whose convergence pressure is 4,000 psia. The KCO2's are based mainly on CO2-natural gas mixtures. Poettmann's work covered CO2 solubility in one condensate and one crude oil. Jacoby and Rzasa measured CO2 solubilities as a function of pressure and temperature for two natural gas-absorber oil mixtures and two natural gas-crude oil mixtures. CO2 concentration in these four systems was fixed at 5 mol per cent. The work reported in this paper extends CO2 solubility data to a variety of different crude oil types in a temperature range from 110 to 250F and pressures up to 2,300 psia. The experimental procedure used by the authors to obtain the solubility data consisted of combining known amounts of pure CO2 and crude oil in a visual cell at a fixed temperature and measuring the bubble point of the mixture. Measurements were made for a total of 40 different CO2-oil mixtures and the results are shown in Table 2. The mixtures included nine different oils (seven crude oils and two refined oils) whose properties are listed in Table 1. All nine oils had vapor pressures less than 1 atm at the experimental temperatures. Consequently, analysis of the bubble-point vapor showed a CO2 concentration over 99 mol per cent. At no time during these experiments was a second, more dense, liquid phase observed. The solubility correlation which was developed from the data in Table 2 is presented in Figs. 1, 2 and 3. In these figures, solubility is expressed as xCO2, the mol fraction of CO2 in the CO2-Oil mixture. Fig. 1 shows solubility as a function of CO2 fugacity and temperature. Fig. 2 shows the same solubility data expressed as a function of saturation pressure and temperature. The solubility shown in Figs. 1 and 2 is for an oil whose UOP characterization factor is 11.7. UOP characterization factors of crude oils can be determined from Ref. 10 if the viscosity and API gravity of the oil are known. Fig. 3 gives the solubility correction factor for oils whose UOP characterization factors differ from 11.7. JPT P. 102ˆ