Migration Of Natural Gas Research Articles

Impacts of the tectonic stress field on natural gas migration and accumulation: A case study of the Kuqa Depression in the Tarim Basin, China

Stress, fluid and temperature are three of the major factors that impact natural gas migration and accumulation. In order to study the influences of tectonic stress field on natural gas migration and accumulation in low-permeability rocks, we take the Kuqa Depression as an example and analyze the evolution of the structure and tectonic stress field at first. Then we study the influences of tectonic stress field at different tectonic episodes on fractures and fluid potentials through the numerical simulation method on the section across the KL2 gas field. We summarize two aspects of the impact of the tectonic stress field on natural gas migration and accumulation. Firstly, under the effects of the tectonic stress field, the rock dilation increases with the added stress and strain, and when the shear stress of rock exceeds its shear strength, the shear fractures are well developed. On one hand, the faults which communicate with the hydrocarbon source rocks become the main pathways for natural gas migration. On the other hand, these positions where fractures are well developed near faults can become good reservoirs for natural gas accumulation. Secondly, because fluid potentials decrease in these places near the faults where fractures are well developed, natural gas can migrate rapidly along the faults and accumulates. The impact of tectonic stress fields on natural gas migration and accumulation allows for hydrocarbon migration and accumulation in the low-permeability rocks in an active tectonic compressive setting.

Formation of gas hydrate deposits in the Siberian Arctic shelf

Natural gas hydrate deposits have been estimated to store about 10% of gas in hydrate form (even with regard to a higher concentration of gas in hydrates), proceeding from the known ratio of dissolved-to-deposited gas. This high percentage is largely due to the fact that the buffer factor in natural gas hydrate deposits is lower than that for free gas because of less diverse structural conditions for gas accumulation. Therefore, the available appraisal of world resources of hydrated gas needs a revision. Hydrates in rocks are either syngenetic or epigenetic. Syngenetic hydrates originate from free or dissolved gas which was present in rocks in situ at the time when PT-conditions became favorable for gas hydrate formation. Epigenetic hydrates are derived from gas which came by migration into rocks with their PT-conditions corresponding to formation of gas hydrates. In addition to the optimum PT-conditions and water salinity, economic gas hydrate accumulation requires sustained supply of natural gas into a specific zone of gas hydrate formation. This condition is feasible only in the case of vertical migration of natural gas along faults, fractured zones, and lithologic windows, or, less often, as a result of lateral migration. Of practical importance are only the gas hydrate deposits produced by vertical or lateral gas migration.

Migration, filling history and geochemical characteristics of Ordovician natural gases in the Tahe Oilfield, Tarim Basin, Northwest China

Ordovician natural gases in the Tahe Oilfield are composed predominantly of hydrocarbon gases dominated by methane with a significant amount of heavy hydrocarbon gas component. The non-hydrocarbon gases include N2, CO2 and minor H2S. The Ordovician natural gases are believed to have originated from the same source rocks, and are composite of gases differing in thermal maturity. Carbon dioxide was derived from thermal metamorphism of Ordovician carbonate rocks. The generation of natural gases involves multiple stages from mature normal oil and condensate-associated gas to thermally cracked gas at the maturity to over-maturity stages. In the main part of the Tahe Oilfield, the Ordovician natural gases appear to be filled in two major phases with a typical petroleum-associated gas from southeast to northwest and from east to west in the early stage; and a thermally cracked gas from east to west in the late stage. At the same time, the oil/gas filling boundary has been primarily established between the two stages.

Geochemical Evidences of Natural Gas Migration and Releasing in the Ordos Basin, China

Natural gas, in its migration from source rocks to release zones may travel a long distance and change the geochemical characteristics of the rocks which it flowed through. In order to study the geochemical evidence of the natural gas migration, 24 samples were taken from different natural gas migration zones in the Ordos Basin, China. Five samples of them are from natural gas release zones (dark sandstone samples), 17 samples are from bleaching zones (bleaching sandstone samples), and two samples are from non-release zones (background samples). These samples were analyzed by organic and inorganic geochemical methods. The results of GC traces and ICP-MASS indicate that three zones show different organic and inorganic geochemical characteristics. Natural gas migration and releasing may be recognized by the geochemical evidences.

Characterization of natural gases in Japan based on molecular and carbon isotope compositions

AbstractIn this paper, the origin, maturity, migration, biodegradation and mixing of natural hydrocarbon gases in Japan have been interpreted using molecular and carbon isotope compositions. No indications of abiogenic gases have been found, the gases being classified as microbial, thermogenic or mixed microbial/thermogenic. However, secondary alteration (mixing, biodegradation, fractionation in migration processes) has had a major but variable impact on the composition of natural gases. Biodegradation, especially, has altered both molecular and isotopic signatures. Thus, the prime control of isotopic and molecular characteristics in gases is due to genetic phenomena, but secondary effects must be taken into account when attempting to understand the origin and distribution of gas. Where the extent of secondary alteration is small, carbon isotope compositions of thermogenic hydrocarbons are controlled largely by maturity. An isotope model developed by Berner and Faber was applied successfully to natural gases in northeast Japan. Besides maturity estimation, the application of the model enables detection of biodegradation, mixing between microbial and thermogenic gases, and mixing among gases with different maturities. The carbon isotope compositions of carbon dioxide also provide information for their genetic origins.

A Study of the Migration and Accumulation Efficiency and the Genesis of Hydrocarbon Natural Gas in the Xujiaweizi Fault Depression

Abstract: In order to investigate the migration and accumulation efficiency of hydrocarbon natural gas in the Xujiaweizi fault depression, and to provide new evidence for the classification of its genesis, a source rock pyrolysis experiment in a closed system was designed and carried out. Based on this, kinetic models for describing gas generation from organic matter and carbon isotope fractionation during this process were established, calibrated and then extrapolated to geologic conditions by combining the thermal history data of the Xushen‐1 Well. The results indicate that the coal measures in the Xujiaweizi fault depression are typical “high‐efficiency gas sources”, the natural gas generated from them has a high migration and accumulation efficiency, and consequently a large‐scale natural gas accumulation occurred in the area. The highly/over matured coal measures in the Xujiaweizi fault depression generate coaliferous gas with a high δ13C1 value (> −20%) at the late stage, making the carbon isotope composition of organic alkane gases abnormally heavy. In addition, the mixing and dissipation through the caprock of natural gas can result in the negative carbon isotope sequence (δ13C1 >δ13C2 >δ13C3 >δ13C4) of organic alkane gases, and the dissipation can also lead to the abnormally heavy carbon isotope composition of organic alkane gases. As for the discovery of inorganic nonhydrocarbon gas reservoirs, it can only serve as an accessorial evidence rather than a direct evidence that the hydrocarbon gas is inorganic. As a result, it needs stronger evidence to classify the hydrocarbon natural gas in the Xujiaweizi fault depression as inorganic gas.

Spatial distribution and geochemistry of the nearshore gas seepages and their implications to natural gas migration in the Yinggehai Basin, offshore South China Sea

About 120 gas seepage vents were documented along the west and southwest coast of the Hainan Island, South China Sea, in water depths usually less than 50 m. The principal seepage areas include the Lingtou Promontory, the Yinggehai Rivulet Mouth, Yazhou Bay, the Nanshan Promontory and the Tianya Promontory. They occur along three major zones, reflecting the control by faults and lateral conduits within the basement. It is estimated that the total gas emission from these seepage vents is 294–956 m 3/year. The seepage gases are characterized by a high CH 4 content (76%), heavy δ 13C 1 values (−38 to −33‰) and high C 1/C 1–5 ratios (0.95–1.0), resembling the thermogenic gases from the diapiric gas fields of the Yinggehai Basin. Hydrocarbon–source correlation shows that the hydrocarbons in the sediments from seepage areas can be correlated with the deeply buried Miocene source rocks and sandstone reservoirs in the central depression. The 2D basin modeling results based on a section from the source rock center to the gas seepage sites indicate that the gas-bearing fluids migrated from the source rocks upward through faults or weak zones encompassed by shale diapirism or in up-dip direction along the sandstone-rich strata of Huangliu Formation to arrive to seabed and form the nearshore gas seepages. It is suggested that the seepage gases are sourced from the Miocene source rocks in the central depression of the Yinggehai Basin. This migration model implies that the eastern slope zone between the gas source area of the central depression and the seepage zone is also favorable place for gas accumulation.

Ternary geochemical-tracing system in natural gas accumulation

The establishment of geochemical-tracing system of gas generation and accumulation is helpful to re-elucidating the gas migration and accumulation in time and space. To deduce the complex process of gas accumulation, a ternary geochemical-tracing system is set up, according to stable isotope inheritance of source rocks, kinetic fractionation of stable isotopes, time-accumulating effect of noble gas isotopes, mantle-derived volatile inheritance, and organic molecule inheritance of light hydrocarbons and thermally kinetic fractionation in their generation, in combination with the previous achievements of gas geochemistry and geochemical parameters of gas-source correlation. There are tight interactions for the geochemical parameters with much information about parent inheritance and special biomarkers, in which they are confirmed each other, reciprocally associated and preferentially used for the requirement so that we can use these geochemical parameters to effectively demonstrate the sources of natural gas, sedimentary environments and thermal evolution of source rocks, migration and accumulation of natural gas, and rearrangement of natural gas reservoirs. It is necessary for the ternary geochemical-tracing system to predict the formation of high efficient gas reservoir and their distribution in time and space.

Applications of Natural Radiation-Induced Paramagnetic Defects in Quartz to Exploration in Sedimentary Basins

ABSTRACT Quartz grains in contact with uranium-bearing minerals or fluids are characterized by natural radiation-induced paramagnetic defects (e.g., oxygen vacancy centers, silicon vacancy centers, and peroxy radicals), which are amenable to study by electron paramagnetic resonance (EPR) spectroscopy. These natural radiation-induced paramagnetic defects, except for the oxygen vacancy centers, in quartz are concentrated in narrow bands penetrated by α particles: (1) in halos around U- and Th-bearing mineral inclusions and (2) in outer rims or along fractures. The second type of occurrence provides information about uranium mineralization or remobilization (i.e., sources of uranium, timing of mineralization or remobilization, pathways of uranium-bearing fluids). It can also be used to evaluate sedimentary basins for potential of uranium mineralization. In particular, the peroxy radicals are stable up to 800 °C and, therefore, are useful for evaluating metasedimentary rocks (e.g., Paleoproterozolc metasedimentary sequences in the central zone of the North China craton). EPR study of the Changcheng Series can focus on quartz from the sediment-basement unconformity and faults to determine the presence and types of natural radiation-induced paramagnetic defects, with which to identify and prioritize uranium anomalies. Other potential applications of natural radiation-induced paramagnetic defects in quartz include uranium-bearing hydrocarbon deposits in sedimentary basins. For example, the Junggar, Ordos, and Tarim basins in northwestern China all contain important oil and natural gas fields and are well known for elevated uranium concentrations, including economic sandstone-hosted uranium deposits. Therefore, systematic studies on the distribution of natural radiation-induced paramagnetic defects in quartz from host sedimentary sequences are expected to provide information about the migration of oil and natural gas in those basins.

Natural gas sources, migration and accumulation in the shallow water area of the Panyu lower uplift: An insight into the deep water prospects of the Pearl River Mouth Basin, South China Sea

Although no drilling has been carried out in the deep water area of the Baiyun sag in the Pearl River Mouth Basin, South China Sea, the successful exploration for natural gas in the shallow water area of the Panyu lower uplift allows an insight into the prospectivity of the adjacent deep water fan system of the Baiyun sag. The Paleogene gas kitchen in the Baiyun sag provided both oil-derived gas and coal-derived gas. Fluid inclusion measurements and 2D numeric modelling of formation pressure indicate four episodes of hydrocarbon charge since the third release of the overpressure system. Seismic wipeout zones manifest several types of gas chimney which could play a role in vertical migration conduits to feed the natural gases into the deep water fan system. There would be, therefore, a low risk for hydrocarbon exploration in the deep water fan system.

Geothermometry and geobarometry of overpressured environments in Qiongdongnan Basin, South China Sea*

AbstractWe demonstrate the use of PVT fluid inclusion modelling in the calculation of palaeofluid formation pressures, using samples from the YC21‐1‐1 and YC21‐1‐4 wells in the YC21‐1 structural closure, Qiongdongnan Basin, South China Sea. Homogenisation temperatures and gas/liquid ratios were measured in aqueous fluid inclusions, and associated light hydrocarbon/CO2‐bearing inclusions, and their compositions were determined using a crushing technique. The vtflinc software was used to construct P–T phase diagrams that enabled derivation of the minimum trapping pressure for each order of fluid inclusion. Through the projection of average homogenisation temperatures (155, 185.5 and 204.5°C) for three orders of fluid inclusion on the thermal‐burial history diagram of the Oligocene Yacheng and Lingshui formations, their trapping times were constrained at 4.3, 2.1 and 1.8 Ma, respectively. The formation pressure coefficient, the ratio of fluid pressure/hydrostatic pressure established by PVT modelling coupled with DST data, demonstrates that one and a half cycles of pressure increase–discharge developed in the Yacheng and Lingshui formations for about 4.3 Ma. In comparison, the residual formation pressure determined by 2D numerical modelling in the centre of LeDong depression shows two and a half pressure increase–discharge cycles for about 28 Ma. The two different methods suggest that a high fluid potential in the Oligocene reservoir of the YC21‐1 structure developed at two critical stages for regional oil and natural gas migration and accumulation (5.8 and 2.0 Ma, respectively). Natural gas exploration in this area is therefore not advisable.

Multiphase natural gas migration and accumulation and its relationship to diapir structures in the DF1-1 gas field, South China Sea : Huang, B. J. et al. Marine and Petroleum Geology, 2002, 19, (7), 861–872

Multiphase natural gas migration and accumulation and its relationship to diapir structures in the DF1-1 gas field, South China Sea : Huang, B. J. et al. Marine and Petroleum Geology, 2002, 19, (7), 861–872

Migration and accumulation of natural gas in Kela-2 gas field

With the guidance of petroleum system theory, the dynamic filling history of natural gas in the Kela-2 gas field is analyzed by using a large suite of oil and gas geochemistry evidence in combination with the tectonic evolution history and reservoir evolution history. It concludes that the Kela-2 gas field was formed by capturing the gas generated during the main gas generation period, while the late kerogen cracking gas contributed a little to the gas field. It suggests that the gas generated during the main gas generation accumulated in the earlyformed widegentle anticline, which is the necessary condition for natural gas to remigrate and enrich late to form the largescale gas reservoir. The newest research shows that the filling history of gas in the Dabei-1, Yinan-2, Tuziluoke and Dina-2 gas fields was related with the natural gas accumulation in the early widegentle anticline as well as late remigration and enrichment of natural gas.

Multiphase natural gas migration and accumulation and its relationship to diapir structures in the DF1-1 gas field, South China Sea

The Dongfang1-1(DF1-1) gas field is the largest commercial gas field yet discovered in the Yinggehai Basin, South China Sea. The gas reservoirs in the field are normally pressured Pliocene shallow marine facies fine-grained sandstones, and the main source rocks are highly over-pressured Miocene mudstones and shales. The natural gases in the reservoirs consist mainly of hydrocarbon gas, CO 2 and N 2. Geochemical data for the natural gases show that the hydrocarbon-rich gases (except for a small amount of biogas) were derived from these source rocks distributed within over-pressured zones, but gases rich in CO 2 mainly originate from the thermal decomposition of Miocene calcareous shales and pre-Tertiary carbonates at higher temperature. Fluid inclusion data for the reservoirs were used together with the regional geology, distribution of different types of reservoirs and the evolution of diapir structures to determine the episodes of gas migration and accumulation in the DF1-1 gas field. We believe that the field was formed by four episodes of gas migration and accumulation. Fluid paleopressure simulation software, designed and developed by CNOOC China Limited, was used to simulate the paleopressure history of the strata at the top of the present-day high pressure zone (a depth of 2800 m) in the DF1-1 gas field. It predicts that the first episode occurred before about 2 Ma, the second and the third episodes between 2 and 0.5 Ma, and that the CO 2-rich gases migrated into the reservoirs after 0.5 Ma. The formation and evolution of diapir structures in the Yinggehai Basin had an important influence on the migration and accumulation of natural gases in the DF1-1 gas field. Rapid deposition, gas generation in the source rocks and thermal expansion of pore-fluids caused over-pressuring in the Miocene shales in the center of the depression. This over-pressuring together with active faulting, formed diapir structures during 5–0.5 Ma. The faults and fractures related to the diapir structures provided a pathway for gas vertical migration from the deep source rocks into the DF1-1 reservoirs, and controlled the geological distribution of different types of natural gases. On this basis, a model for gas migration and accumulation is suggested for the DF1-1 gas field.

Interaction of fluid dynamic factors in the migration and accumulation of natural gas

The migration of fluid petroleum gas, described as fluid potential, depends only on gravity, fluid pressure controlled by depression and capillary force during tectonically stable period; but on tectonic stress during the tectonically active period with severe compression. This method is applied in the Junggar Basin, showing that the migration of Jurassic gas during Cretaceous and Eocene and the migration of Permian gas from Jurassic till the present are determined by capillary force and fluid pressure (including overpressure) which is controlled by depression; the migration of Jurassic gas from Eocene till the present and the migration of Permian gas during Triassic are controlled by tectonic stress.

Interaction of fluid dynamic factors in the migration and accumulation of natural gas

Interaction of fluid dynamic factors in the migration and accumulation of natural gas

Assessment of gas hydrate and free gas distribution on the South Shetland margin (Antarctica) based on multichannel seismic reflection data

Processing and interpretation of a grid of intermediate-resolution multichannel seismic reflection profiles collected on the NE sector of the South Shetland continental margin, allowed us to map the lateral extent of a Bottom Simulating Reflector (BSR). The margin, an accretionary wedge located off the northern tip of the Antarctic Peninsula, consists of two distinct and superimposed tectonic regimes: an older regime is related to Mesozoic-Middle Cenozoic subduction-related tectonism; a younger one is associated with a mainly extensional tectonic phase, and related to the Oligocene development of the western Scotia Sea. The occurrence of the BSR appears to be controlled by the geological structure of the margin. The BSR lacks continuity near basement structures, main geological discontinuities and faults. On the other hand, the amplitude and continuity of the BSR are not affected by the presence of folded structures and undeformed sedimentary layering. We found that the BSR is mostly confined to the NE sector of the South Shetland Margin, where propagation of faulting associated with the Shackleton Fracture Zone may have driven migration of natural gas towards the surface and created the conditions for a BSR to appear. The application of reflection tomography techniques allowed us to reconstruct the averaged seismic velocity field between the seafloor and BSR in order to map the depth of BSR. By averaging the observed velocity structure above and below the BSR, and applying a theoretical model of elastic wave propagation in porous media, we attempted as rigorous a quantitative assessment as possible of the natural gas present as gas hydrate above the BSR and as free gas between the BSR and the Base of Gas Reflector (BGR).

Basin scale natural gas source, migration and trapping traced by noble gases and major elements: the Pakistan Indus basin

He, Ne and Ar concentrations, He and Ar isotopic ratios, carbon isotopic ratios and chemical compositions of hydrocarbon gases were measured in natural gas samples from gas-producing wells in the Indus basin, Pakistan, where no oil has ever been found. 3He/ 4He ratios are in the range 0.01–0.06 Ra (Ra is the atmospheric value of 1.38×10 −6) indicating the absence of mantle-derived helium despite the Trias extension. 40Ar/ 36Ar ratios range from 296 to 800, consistent with variable additions of radiogenic argon to atmospheric, groundwater-derived argon. Rare gas concentrations show large variations, from 6×10 −5 to 1×10 −3 mol/mol for 4He and from 3×10 −7 to 3×10 −5 mol/mol for 36Ar. In general, 36Ar concentrations are high compared to literature data for natural gas. CO 2 and N 2 concentrations are variable, ranging up to 70 and 20%, respectively. Mantle-derived He is not observed, therefore CO 2 and N 2 are not mantle-derived either. Hydrocarbon gas maturity is high, but accumulation efficiency is small, suggesting that early-produced hydrocarbons, including oil, were lost as well as mantle helium. This is consistent with the generally late, Pliocene, trap formation, and explains the high N 2 concentrations, since N 2 is the final species generated at the end of organic matter maturation. Based on δ 13C data, CO 2 originates from carbonate decomposition. Very elevated 20Ne/ 36Ar ratios are found, reaching a maximum of 1.3 (compared to 0.1–0.2 for air-saturated water and 0.5 for air), and these high values are related to the lowest rare gas concentrations. We suggest that this highly fractionated signature is the trace of the past presence of oil in the basin and appeared in groundwater. We propose a model where oil–water contact is followed by gas–water contact, both with Rayleigh distillation for rare gas abundance ratios, thereby generating the fractionated 20Ne/ 36Ar signature in groundwater first and transferring it to gas later. Assuming the gas–water contact occurred shallower than present reservoir depths, this model explains the generally high 36Ar concentrations and low CH 4/ 36Ar ratios compared to other studies on younger basins. It thus provides a historical perspective on fluid transfer in a sedimentary basin, where a gas accumulation may have been buried to greater depth since formation. Rare gas and major element data point to mixing between two gas pulses produced successively. The very CO 2–N 2-rich gases are terminal products of organic matter maturation which have been trapped after important migration. This gas was followed by a more typical thermogenic gas which mixed with it.

Abstract: Fluid Diapir Causing Natural Gas Migration and Accumulation 

Abstract: Fluid Diapir Causing Natural Gas Migration and Accumulation 

Aspects of Natural Gas Generation and Migration in Sedimentary Systems

The present state of natural gas research could be described as comprising a substantial amount of empirical wisdom with certain more or less isolated conceptual chemical and physical models on gas generation, migration and concurrent fractionation processes. The apparent lack of a comprehensive framework for quantitative description and prediction of natural gas generation and accumulation processes must be attributed to the complexity of this issue and the limited control on starting and boundary conditions of the pertaining processes in geological systems. Some basic issues of gas generation and migration that have been addressed in our recent research from an experimental and theoretical point of view will be presented and discussed in the following sections.