Non-hydrocarbon Gases Research Articles

Compositions of non-hydrocarbon and noble gases in natural gas samples from Tarim Basin, China

Compositions of non-hydrocarbon and noble gases in natural gas samples collected from the Kuqa Depression, Tabei Uplift Belt, North Depression, Tazhong Uplift, and Southeast Depression in the Tarim Basin, China were analyzed to investigate the origin of the natural gases. The results show that the largest component of the natural gases is hydrocarbon gas with a concentration of 33.46% to 99.26%. The non-hydrocarbon gases are mainly composed of CO2 and N2 with concentrations of 0.01% to 17.95% and 0.1% to 52.45%, respectively. The helium content varies from 0.005% to 0.30%. The 3He/4He ratio varies from 0.01 Ra to 0.55 Ra (where Ra denotes atmospheric 3He/4He ratio = 1.4 × 10–6), and the 4He/20Ne ratio varies from 8.3 to 7400. Most of the 3He/4He values are below 0.1 Ra. The low 3He/4He ratios indicate crustal radiation to be the main source of the helium. There are no positive correlations between the 3He/4He ratio and helium abundance, non-hydrocarbon abundance, heat flow, and the age of reservoir formations. The ratios of 3He/4He are related to the time or stage of the natural gas accumulation. The ratios of 3He/4He in the reservoirs that were filled in the later stage (Himalayan period) are lower than those in the reservoirs that were filled in the earlier stage (Yanshan period).

Effect of fluid medium in source rock porosity on oil primary migration

Abstract With the self-designed simulation instrument for hydrocarbon generation and expulsion in formation porosity under controlled heating and pressuring conditions, a series of experiments was made with different systems such as nitrogen-water vapor, water vapor-liquid water, liquid water, and anhydrous. Oil discharge efficiency was compared to study the effect of the fluid medium in source rock porosity on oil primary migration. In the oil and gas generation phase, pore space in the source rock was charged by fluids (hydrocarbon gas, non-hydrocarbon gas, oil, formation water) with certain temperature and pressure. Liquid water was an indispensable transport carrier in oil primary migration process. Water might adsorb onto the surface of minerals, preventeding the adsorption of hydrocarbon and was favorable for hydrocarbon migration. CO2 associated with hydrocarbon generation easily dissolved in oil, which reduced the interfacial tension between the oil and water, oil viscosity and oil migration resistance, and promoted oil primary migration.

Geochemical characteristics and origin of Sinian-Lower Paleozoic natural gas in the Sichuan Basin

The composition and isotopic values of natural gas in the Sinian Dengying Fm, Cambrian Qiongzhusi Fm, Longwangmiao Fm and Xixiangchi Fm in the Sichuan Basin exhibit different features in different tectonic position, causing controversy over its origin and sources. The geochemical features of the natural gases in this area were compared based on previous research results and large amounts of drilling data of new exploration wells. The results show: (1) The natural gas is typical dry gas on the whole, with hydrocarbon gas in dominance, and a methane content of 74.85%–97.35%, mostly 83.0%–96.0%; due to different clay contents in source rocks, the difference in non-hydrocarbon gas mainly lies in N2 and He content, with gas in Weiyuan and Ziyang areas having high contents of N2 and He, while gas in Gaoshiti and Moxi areas having low N2 and He. (2) Natural gases in different regions differ greatly in carbon isotope value (δ13C1 and δ13C2). The δ13C1 of natural gas in Cambrian system of Ziyang area is the lightest, from −38.0‰ to −35.5‰, and that in other regions is from −33.9‰ to −32.0‰, indicating different capture stages of natural gases. For example, gas captured in early stage is relatively light in carbon isotope; the carbon isotope value (δ13C2) of gas from Sinian and Cambrian system in Weiyuan is from −36.5‰ to −32.7‰; that from the Longwangmiao Fm in Gaoshiti and Moxi is from −33.6‰ to −31.8‰, but that in the Dengying Fm in Gaoshiti-Moxi area is from −29.1‰ to −26.8‰, quite different from the above natural gases, which mainly shows the differences in kerogen types. (3) Light hydrocarbons of C6–C7 mainly consist of cyclanes and isomerization alkanes, which is the feature of oil cracking gas.

The Research of Origin of Deep Natural Gas of Qianbei Sub-Sag in the South of Songliao Basin

This paper analyses the origins of deep natural gas in Qianbei Subsag using a variety of analytical data such as the natural gas components, the isotope and the light hydrocarbon analysis combining with the development characteristics of hydrocarbon source rocks. The study results show as the following: The abundance of organic matter from hydrocarbon source rocks in Qianbei Subsag is high and dominated by humus type. Part of good hydrocarbon source rocks of Type II1 and Type II2 are developed in Yingcheng Formation and these are the major gas source rocks that is in the stage of postmaturity in evolution degree. The natural gas component is dominated by methane and non-hydrocarbon gas content is low. The isotope values of ethane are lighter and methane and ethane have an obvious phenomenon of carbon isotopic reversal. Parent material types of methane and ethane are from different sources. The sources of methane are biased to humic parent material while the sources of ethane are biased to sapropelic parent material.

Characteristics of Gas Compositions in Giant Gas Fields of China

By the end of 2011, altogether 48 giant gas fields with each proven reserves over 300×108m3had been discovered in China. After studying on the main molecular compositions (methane, heavy hydrocarbon gases, nitrogen, carbon dioxide and hydrogen sulfide) of 1170 gas samples in these gas fields, it is found that: a). Alkane gases dominate the molecular compositions of the natural gases; the extremely low content of them have a tight relationship with the extremely high content of non-hydrocarbon gases; methane accounts for 60.1% of the alkane gases. b). Carbon dioxide has the average content of 4.09%; carbon dioxide with an extremely high content (>50%) is mainly distributed in Dongfang1–1, Changling and Songnan gas fields; highly concentrated CO2in the former one was crustal-derived while that in the latter two was mantle-derived. c). Nitrogen has an average content of 3.56% which is quite low; highly concentrated nitrogen (<20%) is mainly distributed in Hetianhe, Tazhong, Ledong22–1 and Dongfang1–1 gas fields which are organic-originated. d). Hydrogen sulfide has been detected in 12 giant gas fields, with the content of 4.91% in average; the Triassic is the most centralized zone for hydrogen sulfide while the Sichuan Basin has the largest number of sour gas fields and sour gas bearing zones; 7 sour gas fields of high H2S content (2% ∼ 70%) are found which are resulted from the thermochemical sulfate reduction (TSR).

An Experimental Investigation of Sequential CO2 and N2 Gas Injection as a New EOR Method

Typical non-hydrocarbon gases, which have been utilized in miscible and immiscible processes, are carbon dioxide and nitrogen. These gases are usually injected separately and have been rarely utilized together as a tertiary recovery process. In this article, the authors have experimentally focused on sequential carbon dioxide and nitrogen gas injection as a new enhanced oil recovery method. The periodic injections of carbon dioxide and nitrogen have been repeated for six injection pore volumes. Sensitivity analysis of injection pressure, injection volume, and injection rate has also been investigated in core flood experiments. The experimental results have revealed that a sequential miscible carbon dioxide and immiscible nitrogen gases injection have the highest oil recovery percentage than near miscible or immiscible carbon dioxide and nitrogen injections. The experimental results have shown that increasing ratio of miscible carbon dioxide to nitrogen resulted in increasing ultimate oil recovery percentage. This new method has also been compared with typical enhanced oil recovery methods, namely, water, miscible water-alternating-gas, miscible and immiscible carbon dioxide, and immiscible nitrogen injection using a commercial compositional simulator.

Impact of TSR experimental simulation using two crude oils on the formation of sulfur compounds

Two representative crude oils were used in participating in thermochemical sulfate reduction (TSR) and thus to evaluate their pyrolysis behaviors, which is of great relevance to the formation of sulfur compounds. TSR was conducted in autoclave on the system of crude oils with and without magnesium sulfate under high temperature (350–450°C) and pressure (5–14Mpa) conditions. The gaseous products were analyzed by gas chromatography and microcoulometry. The yields of non-hydrocarbon and hydrocarbon gases were measured and compared in order to reveal the distribution of gaseous compounds at different temperatures. Higher total sulfur contents and ratio of methane in gases were obtained with increased temperature. The crystallographic phases of MgO and MgSO4 were detected to coexist in the results of FT-IR and XRD, respectively. The sulfur compounds in oil phase products were reacted by methylation to form methylsulfonium salts and then characterized by positive ion electrospray (ESI) Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). Elemental composition and distribution of sulfur compounds were characterized by their double bond equivalents (DBE) values and carbon numbers. The results showed that types of sulfur compounds from TSR were mainly S1, S2, N1S1, O1S1 and O2S1. Among the identified sulfur compounds, the S1 class species was dominant. The most abundant S1 class species increase associated with the DBE value and carbon number increasing which also indicated the evolution of organic sulfur compounds in TSR is from the labile one to the stable one. In pure blank pyrolysis experiments without TSR, different composition and distribution of organic sulfur compounds in oil phase products were determined using mass spectra in order to evaluate the pyrolysis behaviors of the crude oils.

Statistical thermodynamics model and empirical correlations for predicting mixed hydrate phase equilibria

Natural gas hydrate deposits contain CH4 along with other hydrocarbon gases like C2H6, C3H8 and non-hydrocarbon gases like CO2 and H2S. If CH4 stored in natural gas hydrates can be recovered, the hydrates would potentially become a cleaner energy resource for the future producing less CO2 when combusted than does coal. The production of CH4 from natural gas hydrate reservoirs has been predicted by reservoir simulators that implement phase equilibrium data in order to predict various production scenarios. In this paper two methods are discussed for calculating the phase equilibria of mixed hydrates.In the first method, the phase equilibrium is predicted using a ‘cell potential’ code, which is based on van der Waals and Platteeuw statistical mechanics, along with variable reference parameters to account for lattice distortion, and with temperature-dependent Langmuir constants proposed by Bazant and Trout. The method is validated by reproducing the existing phase equilibrium data of simple and mixed hydrates and the structural transitions that are known to occur, without the use of any fitting parameters. A computationally-simple method is to use empirical correlations of gas hydrate dissociation pressure with respect to temperature and gas-phase composition as they are easy to implement into the simulators. The parameters for the empirical expression were determined for the CH4–C2H6 mixed hydrate system by non-linear regression analysis of available experimental data and data obtained from the first method.

Origin of Marine Sour Natural Gas and Gas-Filling Model in the Puguang Giant Gas Field, Sichuan Basin, China

Taking the geology and tectonic evolution characteristics of the Sichuan Basin into account, the chemical and stable isotopic compositions of natural gas, and biomarker compounds in the reservoir bitumen in the Puguang giant gas field, are investigated to identify the genetic type of marine sour natural gas, take the gas-source correlation, and set up the gas-filling model of the Puguang giant gas field in the Sichuan Basin. The alkane gases in the field are dominated by methane, ranging from 22.06% to 99.64% with an average value of 76.52%, and the low content of heavy hydrocarbon gases are dominantly ethane and little propane. The H2S contents occur among the marine carbonate gas reservoirs, ranging from 0 to 62.17%, wherein the H2S contents in the Upper Permian Changxing Formation and Lower Triassic Feixianguan Formation range from 6.9% to 34.72% (average value=15.27%) and from 0% to 62.17% (average value= 13.4%), respectively, indicating that both are H2S-enriched reservoirs. The chemical and carbon isotopic compositions of marine natural gases show that the alkane gas in the Puguang giant gas field is dominantly oil-cracking gas at high maturity stage, and the biomarker characteristics of reservoir bitumen indicate that the major source rocks are the Upper Permian Longtan Formation sapropelic matters. Moreover, various levels of thermochemical sulfate reduction (TSR) were present in the process of oil-gas transformation, not only increasing the content of non-hydrocarbon gas components (CO2 and H2S) and decreasing the content of heavy hydrocarbon gases, but also causing the reversal of carbon isotope compositions of methane and ethane and the heavier carbon isotope of methane. The recovery of structural configurations over geological time investigates that the gas-filling history of Puguang giant gas field can be divided into three stages: formation of paleo-oil accumulation from the middle-late Indosinian period to the early Yanshanian period, thermal cracking of paleo-oil and TSR alteration from the early to the middle Yanshanian period, and adjustment of gas accumulation from the late Yanshanian to the early Himalayan period. The gypsum of the Lower Triassic Jianglingjiang Formation and the Middle Triassic Leikoupo Formation plays the most important role as effective seal to the gas preservation in different periods.

Operational efficiency improvement by using logging while drilling (LWD) fluid sampling and pressure-testing device

Abstract An operator in Asia Pacific required a large sample volume from a gas reservoir for accurate non-hydrocarbon gas (NHCG) content analysis from two extended reach wells. This extended abstract highlights the use of an LWD fluid sampling and formation pressure-testing device to overcome numerous challenges, including a highly deviated wellbore, stuck pipe, oil-based mud (OBM) gas-sampling issues, and prevention of geo-chemical absorption. Application The choice to use an LWD fluid sampler was based on several factors that reduced significant risks. Due to the well’s deviated nature, the only traditional wireline fluid sampling solution would have required a pipe-conveyed logging mechanism. This would have added rig days to the project and increased the risk of stuck pipe. To prevent geo-chemical absorption, the storage tanks were manufactured with a specialised metallurgic design. This would be tested by applying a customer-requested coating to half the tanks and monitor differences in geo-chemical content. To prevent differential sticking, testing sequences would be limited to 90-minute intervals. Results, observations, and conclusions After two runs in separate wells, a total of 25 samples were acquired containing more than 19 litres of fluid. Due to the reduced invasion profile as a result of LWD technology, fluid stability was reached within the 90-minute threshold. Furthermore, results showed only 8% OBM contamination—half the amount seen in offsets from wireline produced fluid samples. Finally, due to the improved operation efficiency and the quality of the samples, the customer estimates that it saved nearly $10 million in rig costs and millions more in reduced retrofitting costs of the production facility. Significance of subject matter This extended abstract highlights a major step-change in fluid sampling technology. Operators no longer need to consider a well’s deviation in the ability to collect fluid samples. The recap of the two wells will offer additional best practices and risk mitigation techniques for future LWD sampling projects. It also adds yet another LWD technology that provides consistent wireline equivalent data.

Green River Oil Shale Pyrolysis: Semi-Open Conditions

Oil shale is a petroleum source rock that has not undergone the natural processes required to convert its organic matter to oil and gas. However, oil shale kerogen can be converted artificially to liquid and gaseous hydrocarbons by pyrolysis. Heating oil shale in place (in situ) has a number of operational, economic, and environmental advantages over surface retorts, particularly when the shale is too deep to mine. This work describes experiments conducted at temperatures and pressures appropriate to commercially viable in situ pyrolysis. The data are needed to construct models to plan, interpret, and optimize field experiments and commercial operations. The experiments also provide insights into the chemical compositions of the native state shale and all the products of pyrolysis—hydrocarbon and nonhydrocarbon gases, oil, bitumen, remaining pyrolyzable kerogen, residual organic matter, and inorganic matter—as functions of thermal maturation. Numerous studies of Green River oil shale pyrolysis have been published over the years. Most of these have focused on the richest interval, the Mahogany (R-7) zone and have been performed in either open (atmospheric pressure) or closed (bomb) apparatus. The new elements of this work are as follows: (1) samples were taken from the deepest of the kerogen-rich layers of the Green River Formation, the mineralogically distinct R-1 zone; (2) experiments were performed under semi-open (controlled pressure) conditions. The data generated are therefore appropriate input to models used in conjunction with in situ controlled-pressure production tests of R-1 shale. In agreement with previous work, this investigation finds that processing shale at relatively low temperatures, for longer times, and at moderately elevated pressures, reduces yields but improves product quality relative to surface retort methods. The composition of the produced oil is generally uniform over the course of artificial maturation. It has a high H/C ratio and is predominantly composed of saturates and light aromatics, which are desirable for refinery operations. The oil has little sulfur, which is mostly in thiophene-containing moieties. Extracted bitumen has a high polar content, and its H/C ratio decreases as a result of oil and gas generation during maturation. Produced gas is rich in natural gas liquids.

Occurrence of heavy carbon dioxide of organic origin: Evidence from confined dry pyrolysis of coal

Although CO2 is a common non-hydrocarbon gas in sedimentary basins and is significant in studying geofluid evolution, its origin is still a matter of debate. Light δ13CCO2 values have been suggested as a good indicator for discriminating CO2 of organic origin from that of inorganic origin (such as from the mantle or from carbonate mineral dissolution). However, here we present evidence suggesting that large quantities of isotopically heavy CO2 can be liberated from deeply buried source rocks. An immature coal has been pyrolyzed in confined dry gold reactors at temperatures from 250°C to 600°C with different heating rates and under a pressure of 30MPa. The results suggest that isotope fractionation and origin from various oxygenated functional groups with different δ13C compositions make the late generated CO2 (over 40% of potential) enriched in 13C. The 44% of CO2 late-produced from the coal has an average δ13C value of −6.7‰ (VPDB); the latest 20% has an average δ13C value of +1.5‰; and the latest 10% is most enriched in 13C, with a δ13C value of +5.0‰. This paper presents two cases highlighting organic, isotopically heavy CO2 in natural gases occurring at variable concentrations in different sedimentary contexts.

The Study on Hydrous Pyrolysis Experiments of Coal-Measure Source Rocks in Ordos Basin

Through the hydrous pyrolysis experiments of coal-measure source rocks in Taiyuan formation in Ordos Basin with different mediums from 250 °C to 550 °C, with a stepwise heating stage of 50 °C, the characteristics of gas and liquid products are discussed systematically in this paper. The results show that the change rule of hydrocarbon productivity of coal with temperature is similar to mudstone. Total hydrocarbon productivity and gas hydrocarbon productivity increase with temperature rise. Liquid hydrocarbon productivity increases with temperature rise first and then decreases. The peak yield of oil of coal appears at the heating temperature 350 °C, mudstone at 375 °C. The peak yield of mudstone lags behind. The non-hydrocarbon gas productivity increases with temperature rise. The non-hydrocarbon gases are carbon dioxide, nitrogen gas and oxygen mainly. The productivity of carbon dioxide is significantly higher than other non-hydrocarbon gas productivities. The main hydrocarbon gas is methane. The productivity of methane increases when temperature rises. And the productivity increases obviously after 400 °C.

Effect and quantitative evaluation of CO2 derived from organic matter in coal on the formation of tight sandstone reservoirs

Tight reservoirs are widely distributed, especially in coal measure strata. Identification of the densification mechanism of the tight sandstone reservoirs is critical in effectively exploring and exploiting tight gas/oil resources. In this study, the gas formation from type III organic matter in coal was kinetically modeled for the whole diagenetic stage, from the shallow buried biogas generation stage to the deep buried thermal gas generation stage. The results demonstrated that during hydrocarbon formation, quantities of non-hydrocarbon gases, such as CO2, were generated. The proportion of CO2 is about 50%–70% of that of the C1–5, which far exceeds the CO2 content (0–5%) in the natural gas in the sedimentary basins. Geological case study analysis showed that a considerable part of the “lost” gaseous CO2 was converted into carbonate cement under favorable environments. Under the ideal conditions, the volume of the carbonate cement transformed from total CO2 generated by 1 m3 coal (Junggar Basin Jurassic, TOC 67%) can amount to 0.32 m3. Obviously, this process plays a very important role in the formation of tight sandstone reservoirs in the coal measures. Our results also show that the kinetic generation processes of C1–5 and CO2 are asynchronous. There are two main stages of CO2 generation, one at the weak diagenetic stage and the other at the over-mature stage, which are different from large-scale multi-stage hydrocarbon gas generation. Therefore, we can understand the mechanism of tight gas charging by determining the filling time for a tight gas reservoir and the key period of CO2 generation. Further analysis and correlation studies of a specific region are of great significance for determining the mechanism and modeling gas charging in tight reservoirs. It should be noted that the formation of tight sandstone reservoirs is the combined result of complex organic-inorganic and water-rock-hydrocarbon interactions. The details of spatial and temporal distributions of the carbonate cement derived from the organic CO2, which combines with metal ions (Ca/Mg/Fe) in the formation water, should be further investigated.

Geochemical characteristics and identification of thermogenic CBM generated during the low and middle coalification stages

Six woody peat samples were heated to 150, 250, 300, 350, 370, and 400°C to determine their geochemical characteristics and identify whether the coal bed methane (CBM) was thermogenic or secondary biogenic. The experiments were conducted in a closed pyrolysis system, from which the generated pyrolysis gas was collected. The composition of the gas and its carbon and hydrogen isotope concentrations were also determined. The results indicate that methane and carbon dioxide were the main hydrocarbon and non-hydrocarbon gases generated from the samples. The carbon isotopic compositions of the generated methane, ethane, and propane became initially lighter and then heavier with increasing experimental temperature; conversely, the hydrogen isotopic composition of the generated methane and the carbon isotopic composition of the generated carbon dioxide became gradually heavier. Therefore, a strong positive correlation exists between the aforementioned parameters. In addition, relationships have been established between carbon and hydrogen isotopic contents and Ro values, and a model for the identification of the maturity and relative content of thermogenic CBM is proposed. Then, the model was applied in a case study to evaluate the gas source of CBM in the Luling CBM field in Anhui Province, China.

Investigation of hydrocarbon and non-hydrocarbon (CO2, N2) gas injection on enhanced oil recovery in one of the Iranian oil fields

Masjed-I-Suleyman (MIS) field is the first field in the Middle East that has produced oil and has such a long production history (100 years). This field’s production started in 1911. Most of the oil production in the Middle East come from carbonate reservoirs, the majority of which are fractures. These reservoirs tend to produce at high rates in their early production period followed by low rates later on, leading to low overall recovery. The early production rate of this field was 120,000 stb/day, now reaching about 2,000 stb/day. MIS field has produced 1.39 billion stb of oil as of 1 January 2010, which makes it a giant field by world standards. 267 million of this produced oil was re-injected into the reservoir and if the recycled oil re-injected into the reservoir is included, the net total oil produced as of 1 January 2010 would be 1.123 billion stb. Based on original oil-in-place of 6 billion stb, the recovery factor equates to 23.2 % (based on the gross oil production) or 18.7 % (based on the net oil production). So this reservoir is a candidate for an EOR process. It seems the gas injection into oil reservoirs is one of the most effective methods in EOR approaches (Ganji and Haghighi 2006). In this study, the injection technique that was used includes gas injection with different fluids that causes an immiscible process. A compositional reservoir simulator has been used to determine the effect of the gas injection process on reservoir production to optimize the oil recovery for the MIS field. Simulation results show that gas injection is not useful for this field.

Experimental evidence for formation water promoting crude oil cracking to gas

Crude oil cracking to gas is the key to determining the exploration potential and strategy for deep hydrocarbon resources. Identifying the factors that affect the threshold and potential of crude oil cracking to gas as well as other possible influencing factors will provide the scientific basis for deep hydrocarbon exploration. A comparison of pyrolysis simulation experiments of crude oil, hydrous crude oil, and various water media under a constant temperature (350°C) and pressure (50 MPa) shows that water plays a large role in crude oil cracking to gas. (1) When water is added, the gas yields increase significantly, including those of alkane gases and non-hydrocarbon gases: the yield of alkane gases increases 1.8–3 times; the yields of H2 and CO2 also increase significantly. This means that water takes part in the process of crude oil cracking to gas, and supplies hydrogen. Therefore, the presence of water will dramatically enhance the potential of crude oil cracking to gas. (2) Mg2+ ions in the formation water promote the crude oil + water reaction to some extent and increase the total yield of alkane gases and the yields of both H2 and CO2; more interestingly, the i-C4/n-C4 and i-C5/n-C5 ratios increase significantly. This indicates that Mg2+ ions in formation water act as a catalyst, and a disproportionation reaction is involved in the crude oil + water reaction. This study helps us to understand the factors influencing crude oil cracked gas and to evaluate the hydrocarbon resources in deep sedimentary basins.

Tight gas in China and its significance in exploration and exploitation

Abstract Tight gas reservoirs refer to the tight sandstone fields or traps accumulating natural gas of commercial values. According to reservoir characteristics, reserves, and structural height, they can be divided into two types, continuous-type and trap-type: the former are located at the lower part of the structure and have indistinct trap boundaries, inconsistent gas-water boundaries and reversal of gas and water, and their reservoirs are the same as or near the source; the latter are located at the higher part of the structure, with gas above water in traps, low reserves, and relatively high production. Tight gas in China is all coal-derived, dominantly alkane gases (C1–4), in which the amount of methane is greatest and the alkane gases have positive carbon isotopic series. The content of non-hydrocarbon gases (mainly CO2 and N2) is low. At the end of 2010, the reserves and annual production of tight gas in China accounted for 39.2% and 24.6% of the total natural gas, respectively, and the proportions are expected to increase. Compared to the shale gas and coalbed gas, tight gas should be considered in priority in the exploration and exploitation of unconventional gas in China.

Effect of Hydrocarbon and Non‐Hydrocarbon Gas Injection on the Interfacial Tension of a Gas Condensate System

AbstractExperimental results of interfacial tension (IFT) of condensate‐brine‐gas systems over a pressure range of 1000 to 8000 psi and a temperature range of 95 to 160 °C are presented. High‐pressure high‐temperature video‐enhanced pendent drop tensiometry was established to capture drop images for IFT measurements at various reservoir thermodynamic conditions. This paper serves as a building block to the essential practical understanding of the surface effects associated with improved condensate recovery from gas condensate reservoirs by gas injection. This understanding is critical for ascertaining gas injectivity, displacement and trapping in the pore spaces, and potential geological storage of CO2.

Geochemical characteristics and possible origin of natural gas in the Taibei Depression, Turpan-Hami Basin, China

292 chemical composition data and 82 isotopic composition data of gas samples collected from the Taibei Depression of the Turpan-Hami Basin, West China, were used in the study of their origin. Non-hydrocarbon gas is poor in most samples whereas abundant nitrogen in some samples is positively correlated with δ13C1. Although methane is the main constituent, higher molecular gaseous hydrocarbons, from ethane to pentane, are detected in most samples, in accordance with the distribution of oil reservoirs. The stable carbon isotope ratios of methane, ethane and propane are defined as δ13C1: −45.5‰ to −33.5‰, δ13C2: −30.2‰ to −10.5‰, and δ13C3: 27.6‰ to −11 respectively. According to the distribution of carbon isotope ratios, 2 families of gas can be grouped, most showing normal distribution of carbon isotopes, and others having obvious heavier carbon isotopes and being of abnormal distribution. Based on the isotopic composition, the disagreement between the relationship of Δ(δ13C1-δ13C2) and δ13C2 and that of δ(δ13C1-δ13C2) and δ13C2, and the calculated Ro, there are oil-associated gas, coal-derived gas and mixture of them. Other samples with obviously heavier isotopic compositions from the Yanmuxi oilfield of the Taibei Depression have been degraded by organisms.