Secondary Hydrocarbon Migration Research Articles

A new method of the hydrocarbon secondary migration research: Numerical simulation

A three-dimensional invasion percolation simulation model is introduced and integrated into a novel three-dimensional geological modeling framework based on the “unit element” theory to study secondary hydrocarbon migration. Leveraging the computational efficiency inherent in the invasion percolation theory, the simulation method is effectively applied to basin-scale hydrocarbon migration using finely discretized grids. Sensitivity analysis demonstrates the substantial influence of geological parameters including structural configuration, sedimentary facies, and pressure, on simulation results. Noteworthy observations from this study encompass: (1) The intricate influence of sedimentary facies and petrophysical properties characteristics on hydrocarbon migration and accumulation patterns within structural and lithological traps. Favorable petrophysical attributes in the carrier beds enhance the likelihood of accumulation in the structural traps, while lithological traps are prevalent in less conducive carrier beds. (2) The significant impact of sand bodies exhibiting favorable petrophysical attributes, such as channels, on migration and accumulation profiles. This underscores the necessity of incorporating sedimentary facies and rock attributes into oil and gas resource exploration. (3) The pronounced effects of overpressure magnitude and direction on hydrocarbon migration and accumulation dynamics. (4) Optimal strategies for oil and gas resource exploration necessitate a comprehensive assessment of rock attributes, overpressure considerations, and sedimentary facies. The practical implementation of this methodology is demonstrated in an actual exploration project within China's Junggar Basin. The simulation results closely align with established oil recovery data and facilitate predictive identification of promising exploration areas. This indicates the methodology is applicable to all petroleum systems similar to Junggar Basin. Through practical applications, the development of a scientifically rigorous three-dimensional geological model for the study area, coupled with numerical simulations of oil and gas migration, facilitates the elucidation of accumulation patterns. This approach aids in identifying pivotal factors such as sand body distribution, internal structural composition, permeability attributes, and fracture behavior, which collectively influence oil and gas migration. Furthermore, by correlating insights obtained from oil and gas discoveries in wells, a deeper understanding of carrier bed properties and their geological evolution is attained.

Hydrocarbon dominant migration direction and accumulation mode in Qijiang area, Sichuan Basin, China

The high‐quality hydrocarbon source rocks developed in the Longtan Formation of the Qijiang area and the good reservoir capacity of the overlying dolomite of the Jialingjiang Formation indicate that the area has great exploration potential. To clarify the hydrocarbon migration and accumulation characteristics of the area, the fluid potential of the Longtan Formation in the Qijiang area in the Early Jurassic was determined. The direction of the maximum negative gradient of the fluid potential indicates the direction of the primary migration of hydrocarbons, and the structural ridge theory is used to analyse the direction of the secondary migration of hydrocarbons. The results show that the fluid potential of the hydrocarbon source rocks of the Longtan Formation in the Early Jurassic is characterized by the alternate distribution of high potential zones and low‐potential zones. The central syncline, eastern syncline and western syncline are drainage zones and high potential zones, while the Shiyougou structural belt and Fo'er Ya structural belt are supply zones and low‐potential zones. The oil and gas fluids migrate from the east–west direction to the anticlinal zone for the primary migration; the structural ridge controls the secondary migration of oil and gas in the low‐potential area along the north–south direction, resulting in a zonal distribution of oil and gas traps along the structural ridge. By combining fluid potential and structural ridge characteristics to determine the dominant direction of primary and secondary hydrocarbon migration, a model of hydrocarbon migration and accumulation in the Qijiang area is developed, which provides an important basis for finding hydrocarbon reservoirs.

Can Agents Model Hydrocarbon Migration for Petroleum System Analysis? A Fast Screening Tool to De-Risk Hydrocarbon Prospects

Understanding subsurface hydrocarbon migration is a crucial task for petroleum geoscientists. Hydrocarbons are released from deeply buried and heated source rocks, such as shales with a high organic content. They then migrate upwards through the overlying lithologies. Some hydrocarbon becomes trapped in suitable geological structures that, over a geological timescale, produce viable hydrocarbon reservoirs. This work investigates how intelligent agent models can mimic these complex natural subsurface processes and account for geological uncertainty. Physics-based approaches are commonly used in petroleum system modelling and flow simulation software to identify migration pathways from source rocks to traps. However, the problem with these simulations is that they are computationally demanding, making them infeasible for extensive uncertainty quantification. In this work, we present a novel dynamic screening tool for secondary hydrocarbon migration that relies on agent-based modelling. It is fast and is therefore suitable for uncertainty quantification, before using petroleum system modelling software for a more accurate evaluation of migration scenarios. We first illustrate how interacting but independent agents can mimic the movement of hydrocarbon molecules using a few simple rules by focusing on the main drivers of migration: buoyancy and capillary forces. Then, using a synthetic case study, we validate the usefulness of the agent modelling approach to quantify the impact of geological parameter uncertainty (e.g., fault transmissibility, source rock location, expulsion rate) on potential hydrocarbon accumulations and migrations pathways, an essential task to enable quick de-risking of a likely prospect.

Evolution of abnormal pressure in the Paleogene Es3 formation of the Huimin Depression, Bohai Bay Basin, China

The evolution of abnormal pressure is of importance for the analysis of hydrocarbon migration and accumulation processes. However, paleo-pressure reconstruction is still a challenge with great uncertainty. In this study, the PVT simulation method and homogenization temperature-salinity method were used for abnormal pressure evolution analysis in the Huimin Depression, which is characterized by a complex distribution of abnormal pressure, including overpressure, normal pressure and underpressure. The origins of the abnormal pressure conditions were also analyzed to examine the rationality and reliability of paleo-pressure reconstruction by basin modeling and quantitative calculation. The results revealed different evolutionary processes for the paleo-pressure in the Central Deep-Sag Zone (CDSZ) and the Northern Tectonic Uplift Belt (NTUB). In the CDSZ, the abnormal paleo-pressure exhibited a rising stage during the late Oligocene owing to disequilibrium compaction. From the early to middle Miocene, the paleo-pressure decreased to hydrostatic pressure because of the elastic rebound of rocks and temperature reduction. From the late Miocene to middle Pliocene, the paleo-pressure rose again because of the deposition and hydrocarbon generation. From the late Pliocene to the present, the paleo-pressure decreased again owing to the termination of hydrocarbon generation and secondary migration of hydrocarbons. In the NTUB, the paleo-pressure remained hydrostatic without disequilibrium compaction during the late Oligocene, followed by an intense reduction process due to rock elastic rebound and temperature reduction owing to strong tectonic uplift from the early to middle Miocene. From the late Miocene to middle Pliocene, the paleo-pressure rose because of the deposition and hydrocarbon injection from the CDSZ. From the late Pliocene to the present, the termination of hydrocarbon generation, weakening of hydrocarbon injection from the CDSZ, and the gas diffusion led to the decrease of pressure again in the NTUB. This study reveals that the paleo-pressure experienced two rising and two falling stages in the CDSZ and finally is characterized from normal pressure to overpressure. The paleo-pressure in the NTUB experienced one rising and two falling stages and is currently characterized by underpressure. This study provides a new approach for assessing the paleo-pressure evolution based on multiple analytical methods and further contributes to research on hydrocarbon-accumulating dynamics and hydrocarbon-migrating processes.

Tectono-thermal evolution of Cambrian–Ordovician source rocks and implications for hydrocarbon generation in the eastern Tarim Basin, NW China

The tectono-thermal evolution is an important control on petroliferous basin development; however, this evolution is difficult to reconstruct in sedimentary basins subjected to multiple tectono-thermal events. The Tarim Basin is the largest petroliferous basin in northwestern China and hosts a complex oil–gas system comprising several sets of source, reservoir, and cap rocks that have experienced multiple tectonic, thermal, and sedimentary events. Large oil and gas reserves have been discovered in the central and northern Tarim Basin during the last 30 years, but none in the eastern part of the basin. This is generally attributed to the high thermal maturity reached by source rocks during the Late Ordovician, and subsequent hydrocarbon loss. Therefore, reconstructing the Cambrian–Ordovician tectono-thermal evolution is critical in facilitating successful oil and gas exploration in this region. We compiled equivalent vitrinite reflectance data (n = 178) of source rocks from seven wells in the Tarim Basin, which for Cambrian–Ordovician source rocks are >1.3%, beyond the hydrocarbon generation threshold and in the main gas and dry gas generation stages. The Cambrian–Ordovician source rocks experienced rapid burial and heating during the Caledonian period, entered the hydrocarbon generation stage during the Middle–Late Ordovician, and reached peak hydrocarbon generation at the end-Caledonian period. They might have experienced secondary hydrocarbon generation after the Jurassic. Homogenization temperatures of fluid inclusions (n = 616) from wells GC4, LX1, MD1, and YD2 as well as the modeled thermal evolution reveal a main hydrocarbon generation event during the Caledonian period and a secondary event in the Yanshanian and Himalayan period in other wells (LX1, MD1, and YD2). Hercynian and Indosinian uplift and exhumation in the eastern Tarim Basin controlled the main structures, and faulting created favorable conditions for secondary hydrocarbon generation and migration at this time. Since the Yanshanian and Himalayan, the Tarim Basin has experienced further sedimentation and heating, and the tectono-thermal evolution might have been related to the formation of the Tibetan Plateau. In summary, our reconstruction of the tectono-thermal evolution of Cambrian–Ordovician strata and the hydrocarbon generation history of the Tarim Basin suggests that the eastern Tarim Basin may also have hydrocarbon generation potential and can guide future oil and gas exploration.

Secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin

The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically.

Composition changes of hydrocarbons during secondary petroleum migration

We investigate secondary migration of hydrocarbons with significant composition difference between the source and oil pools in the Cooper-Eromanga Basin, Australia. The secondary migration period is significantly shorter than the time of the hydrocarbon pulse generation, so neither adsorption nor dispersion of components can explain the concentration difference. The filtration coefficients, obtained from oil compositions in source rock (Patchawarra Formation) and in the reservoir (Poolowanna Formation and Hutton Sandstone), monotonically increase as carbon number increases. The monotonicity takes place for heavy hydrocarbons (n > 10). Loss of monotonicity for light and intermediate hydrocarbons can be explained by their evaporation into the gas phase. The evaporation of light and intermediate hydrocarbons into the gas phase is supported by their concentrations in oil, which are higher in source rock than in trapped reservoir oil. The paper proposes deep bed filtration of hydrocarbons with component kinetic retention by the rock. Introduction of the component capture rate into the mass balance transport equation allows matching the concentration difference, and the tuned filtration coefficients are in the common range. The results suggest that deep bed filtration controls the final reservoir oil composition during secondary migration in the Cooper-Eromanga Basin petroleum system, which was not previously considered.

Secondary migration of hydrocarbons in the Zhujiang Formation in the Huixi half-graben, Pearl River Mouth Basin, South China Sea

The process and mechanisms of secondary hydrocarbon migration in the Huixi half-graben, Pearl River Mouth Basin, were investigated on the basis of geological analysis of the strata and study of the porosity and permeability of the reservoir rocks, fluid potential, oil properties, and geochemistry of oil–source correlation. The results suggest that the hydrocarbons of the Zhujiang Formation in the Huixi half-graben were derived from source rocks of the Eocene Wenchang Formation and the Eocene–Oligocene Enping Formation in the Huizhou Sag. The hydrocarbons migrated laterally from northeast to southwest. The sandstone in the upper member of the Zhujiang Formation exhibited superior physical properties (porosity and permeability) and connectivity than the lower member. Thin sandstone beds with good physical properties and stable distribution in the upper member of the Zhujiang Formation were the main carrier beds for lateral hydrocarbon migration.

The evolution of Devonian hydrocarbon gases in shallow aquifers of the northern Appalachian Basin: Insights from integrating noble gas and hydrocarbon geochemistry

The last decade has seen a dramatic increase in domestic energy production from unconventional reservoirs. This energy boom has generated marked economic benefits, but simultaneously evoked significant concerns regarding the potential for drinking-water contamination in shallow aquifers. Presently, efforts to evaluate the environmental impacts of shale gas development in the northern Appalachian Basin (NAB), located in the northeastern US, are limited by: (1) a lack of comprehensive “pre-drill” data for groundwater composition (water and gas); (2) uncertainty in the hydrogeological factors that control the occurrence of naturally present CH4 and brines in shallow Upper Devonian (UD) aquifers; and (3) limited geochemical techniques to quantify the sources and migration of crustal fluids (specifically methane) at various time scales. To address these questions, we analyzed the noble gas, dissolved ion, and hydrocarbon gas geochemistry of 72 drinking-water wells and one natural methane seep all located ≫1km from shale gas drill sites in the NAB. In the present study, we consciously avoided groundwater wells from areas near active or recent drilling to ensure shale gas development would not bias the results. We also intentionally targeted areas with naturally occurring CH4 to characterize the geochemical signature and geological context of gas-phase hydrocarbons in shallow aquifers of the NAB. Our data display a positive relationship between elevated [CH4], [C2H6], [Cl], and [Ba] that co-occur with high [4He]. Although four groundwater samples show mantle contributions ranging from 1.2% to 11.6%, the majority of samples have [He] ranging from solubility levels (∼45×10−6cm3 STP/L) with below-detectable [CH4] and minor amounts of tritiogenic 3He in low [Cl] and [Ba] waters, up to high [4He]=0.4cm3 STP/L with a purely crustal helium isotopic end-member (3He/4He=∼0.02 times the atmospheric ratio (R/Ra)) in samples with CH4 near saturation for shallow groundwater (P(CH4)=∼1 atmosphere) and elevated [Cl] and [Ba]. These data suggest that 4He is dominated by an exogenous (i.e., migrated) crustal source for these hydrocarbon gas- and salt-rich fluids. In combination with published inorganic geochemistry (e.g., 87Sr/86Sr, Sr/Ba, Br−/Cl−), new noble gas and hydrocarbon isotopic data (e.g., 20Ne/36Ar, C2+/C1, δ13C-CH4) suggest that a hydrocarbon-rich brine likely migrated from the Marcellus Formation (via primary hydrocarbon migration) as a dual-phase fluid (gas+liquid) and was fractionated by solubility partitioning during fluid migration and emplacement into conventional UD traps (via secondary hydrocarbon migration). Based on the highly fractionated 4He/CH4 data relative to Marcellus and UD production gases, we propose an additional phase of hydrocarbon gas migration where natural gas previously emplaced in UD hydrocarbon traps actively diffuses out into and equilibrates with modern shallow groundwater (via tertiary hydrocarbon migration) following uplift, denudation, and neotectonic fracturing. These data suggest that by integrating noble gas geochemistry with hydrocarbon and dissolved ion chemistry, one can better determine the source and migration processes of natural gas in the Earth’s crust, which are two critical factors for understanding the presence of hydrocarbon gases in shallow aquifers.

Seismic characteristics of fluid escape pipes in sedimentary basins: Implications for pipe genesis

Fluid escape pipes were first documented from 3D seismic data over a decade ago, and have subsequently been identified in many petroliferous basins worldwide. They are characterized on seismic data by vertical to sub-vertical zones of reduced reflection continuity that have a columnar geometry in three-dimensions. The upper terminations of these pipes commonly coincide with pockmarks or palaeo-pockmarks, signifying a close connection of pipe formation with a high flux fluid expulsion process. Dimensions range from tens to hundreds of metres in diameter, and hundreds to over a thousand metres in height, and the slenderness ratio, defined as height/diameter (Ω), ranges from 0.8 to over 20. Pipes are frequently associated with sub-vertical clustering of amplitude anomalies on seismic data, related either to the presence of free gas, or to cementation linked to the passage of hydrocarbons.Three mechanisms have been suggested to explain pipe genesis: (1) hydraulic fracturing, (2) erosional fluidisation, and (3) capillary invasion. We suggest a further two possible mechanisms in the form of localised collapse by volume loss and synsedimentary flow localisation. We review all five mechanisms and conclude that it is unlikely that a single mechanism applies but that combinations of these processes may all occur in particular contexts. Fluid escape pipes may be far more widespread that currently appreciated, and they may play a critical role in secondary hydrocarbon migration and in providing leakage pathways for trapped hydrocarbons through overlying seals.

Multi-stage primary and secondary hydrocarbon migration and accumulation in lacustrine Jurassic petroleum systems in the northern Qaidam Basin, NW China

To improve the understanding on lacustrine Jurassic petroleum migration and accumulation in the northern Qaidam Basin (NW China), we conduct an integrated analysis of the petrography and geochemistry of oil-bearing fluid inclusion, including inclusion petrography, homogenization temperature combined with reservoir burial and thermal history, and reservoir sequential extraction. Results show that during the first stage of late Oligocene to early Miocene, the deep Paleogene reservoir was first charged by oils sourced from Middle Jurassic rocks (petroleum inclusion). This charge was accompanied by some oil alteration. During the second stage of early to middle Miocene, the deep Paleogene reservoir was charged by Lower-Jurassic-sourced oils (intergranular free oil) and this charging event is different from the first one in that it witnessed little hydrocarbon alteration. During the third stage in the Pliocene, widespread gas sourced from Lower and Middle Jurassic rocks occurred in both the deep Paleogene and shallow Neogene reservoirs and primary oil accumulations in deep Paleogene reservoirs migrated vertically to shallow Neogene reservoirs along faults, and formed secondary accumulations. Little alteration took place, favorable for the remigration. Thus, the lacustrine Lower and Middle Jurassic petroleum systems in the northern Qaidam Basin represent multi-stage primary and secondary hydrocarbon accumulations and mixing of hydrocarbons was very common.

Hydrocarbon migration and accumulation in the Upper Cretaceous Qingshankou Formation, Changling Sag, southern Songliao Basin: Insights from integrated analyses of fluid inclusion, oil source correlation and basin modelling

The Upper Cretaceous Qingshankou Formation acts as both the source and reservoir sequence in the Changling Sag, situated in the southern end of the Songliao Basin, northeast China. An integrated approach involving determination of hydrocarbon charging history, oil source correlation and hydrocarbon generation dynamic modeling was used to investigate hydrocarbon migration processes and further predict the favorable targets of hydrocarbon accumulations in the Qingshankou Formation. The hydrocarbon generation and charge history was investigated using fluid inclusion analysis, in combination with stratigraphic burial and thermal modeling. The source rocks began to generate hydrocarbons at around 82Ma and the hydrocarbon charge event occurred from approximately 78Ma to the end of Cretaceous (65.5Ma) when a large tectonic uplift took place. Correlation of stable carbon isotopes of oils and extracts of source rocks indicates that oil was generated mainly from the first member of Qingshankou Formation (K2qn1), suggesting that hydrocarbon may have migrated vertically. Three dimensional (3D) petroleum system modeling was used to evaluate the processes of secondary hydrocarbon migration in the Qingshankou Formation since the latest Cretaceous. During the Late Cretaceous, hydrocarbon, mainly originated from the Qianan depression, migrated laterally to adjacent structural highs. Subsequent tectonic inversion, defined as the late Yanshan Orogeny, significantly changed hydrocarbon migration patterns, probably causing redistribution of primary hydrocarbon reservoirs. In the Tertiary, the Heidimiao depression was buried much deeper than the Qianan depression and became the main source kitchen. Hydrocarbon migration was primarily controlled by fluid potential and generally migrated from relatively high potential areas to low potential areas. Structural highs and lithologic transitions are potential traps for current oil and gas exploration. Finally, several preferred hydrocarbon accumulation sites have been identified by this work, like Western Slope, Southern uplift, and Eastern Slope, helping reduce the risk on targeting hydrocarbon potential reservoirs in Changling Sag.

Analysis of secondary migration of hydrocarbons in the Ordovician carbonate reservoirs in the Tazhong uplift, Tarim Basin, China

The process and mechanisms of secondary hydrocarbon migration in the Tazhong uplift, Tarim Basin, were investigated based on the analysis of the regional structure and by integrating geologic, hydrodynamic, and geochemical parameters. Parameters successfully analyzed included the fluid potential, fluid properties, production outputs, and diamantane index. The results indicated that hydrocarbons migrated into the Tazhong uplift from the northern part of the Manjiaer depression through a series of injection points (IPs) during four orogenies, that is, the early Caledonian (510 Ma), the late Caledonian (439 Ma), the late Hercynian–Indosinian (290 Ma), and the Yanshanian–Himalayan (208 Ma). A total of six IPs were identified at the intersections of the northeast-trending faults and the northwest-trending flower strike faults. The hydrocarbons migrated from the IPs into traps along regional trends from northwest to southeast and from northeast to southwest. The hydrocarbon migration process and patterns determined the distribution of hydrocarbon properties and production rates in the Tazhong uplift. With increasing distance from the IPs, daily hydrocarbon production decreases, and the hydrocarbons become progressively heavier and display lower gas:oil ratios.

Use of outcrop observations, geostatistical analysis, and flow simulation to investigate structural controls on secondary hydrocarbon migration in the Anacacho Limestone, Uvalde, Texas

We undertake a multidisciplinary investigation into the distribution of asphalt in the Anacacho Limestone in an effort to decipher the potential roles of fractures and faults on secondary hydrocarbon migration. Field relationships between fractures, faults, and asphalt are evaluated at an asphaltic limestone mine near Uvalde, Texas. Based on their distributions, geometries, and structural relationships, we infer that normal faults provided vertical flow paths through the Anacacho Limestone, whereas strata-bound fractures enhanced lateral permeability. Variograms calculated from 75 subsurface measurements indicate that the asphalt concentration is anisotropically correlated and that the longest correlation length points in the mean strike direction of fractures and faults. A globally positioned laser rangefinder is used to measure faults and stratigraphic contacts within the mine. That data are then combined with lithologic descriptions from surrounding subsurface wells to construct a three-dimensional (3-D) model of the Anacacho Limestone. When an ordinary block-kriging algorithm populates the model with asphalt concentration estimates, the high values align along a trend that connects the two largest normal fault zones at the mine. The 3-D model provides a framework to numerically simulate secondary hydrocarbon migration. We test numerous hydrocarbon migration scenarios by adjusting simulation parameters within physically realistic ranges until producing an oil saturation field that agrees with asphalt concentration estimates. Our best match simulation indicates that oil entered the Anacacho Limestone through normal faults, that regional aquifer flow impacted oil flow, and that fractures increased the horizontal permeability of the formation by an order of magnitude along their strike direction.

Simulation and characterization of pathway heterogeneity of secondary hydrocarbon migration

Carriers are important links between sources and traps for hydrocarbon migration and accumulation in a petroleum system. Oil and gas commonly migrate along narrow and irregular pathways in porous media, even in macroscopically homogeneous media. A migration simulator based on the invasion-percolation theory, which couples the buoyancy of a hydrocarbon column as the driving force with capillary pressure as the resisting force, satisfactorily explains migration processes in heterogeneous media. In macroscopically homogeneous carriers, migration pathways are generally perpendicular to equipotential lines, but locally, the pathways can be irregular because of the influence of microscopic heterogeneity. The degree of irregularity of these pathways depends on the difference between competing driving and resisting forces. When numerous pathways form in a migration-accumulation system, the flux of migrating hydrocarbons may vary among these pathways. In macroscopically heterogeneous carriers, the irregularity of migration pathways is exacerbated. When the driving force is relatively weak, hydrocarbons tend to migrate in carriers where the hydraulic conductivity is relatively large. These pathways differ from those predicted only on the basis of flow potential. Simulation of the migration process in the Middle Jurassic carrier beds of the Paris Basin demonstrates the characteristics of the migration simulator in the analysis of migration pathway heterogeneity. Results are comparable to or superior to those achieved with previous simulation approaches.

A Model of Buoyancy-Driven Two-Phase Countercurrent Fluid Flow

We seek simple analytical solutions in a model of gas flow driven by a combination of buoyancy, viscous, and capillary forces. Traveling-wave solutions describe propagation of the top and bottom of the gas plume. The top of the plume has low gas saturation, but propagates much faster than the bottom. The theoretical maximum of the velocity of propagation of the top of the plume provides a simple conservative estimate of the time until plume evolution will dramatically slow down. A sequence of rarefaction and traveling-wave solutions characterizes the transition zones between the top and bottom stable regions. The analytical results are applied to studying carbon dioxide flow caused by leaks from deep geological formations used for CO2 storage. The results are also applicable for modeling flow of natural gas leaking from seasonal gas storage, or for modeling of secondary hydrocarbon migration.

GIS-based modeling of secondary hydrocarbon migration pathways and its application in the northern Songliao Basin, northeast China

Hydrocarbon migration pathways are the linkage between hydrocarbon source areas and accumulation sites. Modeling accurately the pathways of hydrocarbon migration is of important significance in determining the location of favorable petroleum exploration targets. In this paper, GIS-based modeling algorithms are presented for searching the pathways of secondary hydrocarbon migration by considering the geologic mechanisms. These algorithms are constructed on a raster digital elevation model (DEM) of the top boundary of a carrier bed, in which secondary migration occurred. On the DEM, a 3×3 pixel sized window is used for searching. The center of the search window is initially assumed at a point on the boundary of a hydrocarbon source area, from which the secondary hydrocarbon migration starts. The altitude values in the eight adjoining pixels enclosing the central pixel of the search window are compared, and the pixel with an altitude value not only larger than the central pixel but also the largest of the eight surrounding pixels is the next target pixel where the search window will move to. Each searched path will terminate at either a convex point, which indicates the existence of a trap for hydrocarbon accumulation, or a point on the boundary of the DEM, which suggests that the pathway of hydrocarbon migration extends outside the DEM. In addition, a concourse point of two paths is also considered as a termination point of either path. The algorithms were successfully applied in the modeling of the secondary migration pathways in the northern Songliao Basin, northeast China. The modeled results matched well with drilling data, suggesting the robustness of the algorithms.

Hydrocarbon migration characteristics of the Lower Cretaceous in the Erlian Basin

The paper systematically analyzes the hydrocarbon migration characteristics of the Lower Cretaceous in the Erlian Basin, based on the geochemical data of mudstone and sandstone in the main hydrocarbon-generating sags. (1) The source rocks in K1ba and K1bt1 are estimated to be the mature ones, their hydrocarbon expulsion ratio can reach 32%–72%. The Type-I sags in oil windows possess good hydrocarbon generation and expulsion conditions, where commercial reservoirs can be formed. (2) According to the curves of the mudstone compaction and evolution of clay minerals, the rapid compaction stage of mudstones is the right time of hydrocarbon expulsion, i.e., primary migration. (3) The timing between hydrocarbon generation and expulsion is mainly related to the accordance of the oil window and the rapid compaction stage of mudstones in the hydrocarbon generation sags of Type-I. That forms the most matching relation between hydrocarbon generation and migration. (4) The faults and unconformities are the important paths for the secondary hydrocarbon migration. Especially, the unconformity between K1ba and K1bt1 has a favorable condition for oil accumulation, where the traps of all types are the main exploration targets. (5) Hydrocarbon migration effect, in the Uliastai sag, is most significant; that in the Saihan Tal and Anan sags comes next, and that in the Bayandanan and Jargalangt sags is worst.

Influence of fault map resolution on pore pressure distribution and secondary hydrocarbon migration; Tune area, North Sea

AbstractPressure and hydrocarbon migration modelling was carried out in the Tune Field area, Viking Graben, offshore Norway. The pressures are considered to be controlled by compartments bounded by mapped faults. Two different interpreted fault maps at the top reservoir level (Brent Group) are used as input to the modelling. First, a low‐resolution fault map is used, with only the large faults interpreted, and next, both large and small faults are included. The simulations show high overpressures generated in the western area, in the deeper part of the Viking Graben, and hydrostatic in the eastern areas. A sharp transition zone results from using the low‐resolution fault map in the simulations. Small N–S striking faults situated in between the wells have to have higher sealing capacity than expected from juxtaposition analysis alone, to be able to match the overpressures measured in well 30/5‐2 and 30/8‐1S in the Tune Field, and well 30/8‐3 east of Tune. The intermediate pressure in the western part is probably related to flow in the deeper parts of the sedimentary column in the compartment, where well 30/8‐3 is situated. The secondary oil migration models show that overpressures have major effects on the migration pathways of hydrocarbons. The level of detail in the fault interpretation is important for simulation results, both for pressure distribution and for hydrocarbon migration.

A modified alternating‐direction finite volume method for modeling secondary hydrocarbon migration and accumulation processes

AbstractWe present a finite volume method for the coupled systems of nonlinear partial differential equations arising in secondary hydrocarbon migration and accumulation processes in basin modeling. We propose a modified alternating direction implicit splitting acceleration technique to solve the scheme in an effective and robust manner. We apply the scheme to simulate model problems with clear physical features and to secondary migration and accumulation problems in real petroleum reservoirs. The numerical experiments show that the scheme is very robust and generates stable and physically reasonable numerical results, even in the extremely long time period that ranges from millions of years to tens of millions of years. This clearly shows the strong potential of the method developed. © 2003 Wiley Periodicals, Inc. Numer Methods Partial Differential Eq 19: 254–270, 2003