Secondary Hydrocarbon Migration Research Articles

An exhumed palaeo‐hydrocarbon migration fairway in a faulted carrier system, Entrada Sandstone of SE Utah, USA

AbstractThe Moab Anticline, east‐central Utah, is an exhumed hydrocarbon palaeo‐reservoir which was supplied by hydrocarbons that migrated from the Moab Fault up‐dip towards the crest of the structure beneath the regional seal of the Tidwell mudstone. Iron oxide reduction in porous, high permeability aeolian sandstones records the secondary migration of hydrocarbons, filling of traps against small sealing faults and spill pathways through the Middle Jurassic Entrada Sandstone. Hydrocarbons entered the Entrada Sandstone carrier system from bends and other leak points on the Moab Fault producing discrete zones of reduction that extend for up to 400 m from these leak points. They then migrated in focused stringers, 2–5 m in height, to produce accumulations on the crest of the anticline. Normal faults on the anticline were transient permeability barriers to hydrocarbon migration producing a series of small compartmentalized accumulations. Exsolution of CO2 as local fault seals were breached resulted in calcite cementation on the up‐dip side of faults.Field observations on the distribution of iron oxide reduction and calcite cements within the anticline indicate that the advancing reduction fronts were affected neither by individual slip bands in damage zones around faults nor by small faults with sand: sand juxtapositions. Faults with larger throws produced either sand: mudstone juxtapositions or sand: sand contacts and fault zones with shale smears. Shale‐smeared fault zones provided seals to the reducing fluid which filled the structural traps to spill points.

Study on secondary migration of hydrocarbons in Tazhong area of Tarim Basin in terms of carbazole compounds

Fractionated carbazoles have been detected for the first time in crude oils from the Tazhong area of the Tarim Basin, and these nitrogen compounds were successfully utilized in the study of petroleum migration. Alkylcarbazoles are quite abundant in all the samples analyzed; small amounts of benzocarbazoles were detected only in some of the sample, and dibenzocarbazoles were not found in the oils. Based on the distributions of G1, G2 and G3 types of C2-alkylcarbazoles, the ratio of C3-/C2-carbazoles and the relative concentrations of alkylcarbazole and alkylbenzocarbazole, oils in the Carboniferous CIII reservoir in the Tazhong uplift are thought to have laterally migrated to the high level of Tazhong structure No. 4 from both northwest and southeast. The study here also shows that oils in the area may have undergone long-distance migration.

堆積盆シミュレーションにおける石油の二次移動とそのモデル化

Modeling secondary migration and accumulation of hydrocarbons is one of the principal requirements in multi-dimensional basin simulation. In this paper, the treatment of secondary migration on basin simulators was discussed from both numerical and experimental point of view.Firstly, a new gridding method is proposed for increasing reproductivity by decreasing discretization errors, in which thin grids in both source/seal bed and carrier bed along their lithologic boundaries are constructed. Case studies using an imaginary siliciclastic sedimentary basin show that this treatment can reproduce secondary migration pattern that is close and consistent with those obtained from thinly divided grid systems without increasing cpu times and memory spaces. This treatment is also easily included into most of the previously developed basin simulators, thus, it would be an effective tool for modeling secondary migration in sedimentary basins.Secondly, displacement patterns are discussed based on the relative magnitudes among buoyancy, interfacial, and viscous forces using the results of one-dimensional vertical oil-water displacement experiments. Two displacement patterns are recognized during the experiments, one clearly formed a typical shock front and the other did not. Through trial-and-error matching approach using a two-phase fluid flow simulator, we found that the “shock-front” pattern can be reproduced by using typical relative permeability curves, while for “non-shock-front” case, we need quite different curves to reproduce observed results. It suggests that ordinary relative permeability curves obtained from special core analysis in the field of reservoir engineering might not be valid for modeling secondary migration.Such investigations would be important for improving our understanding of petroleum migration in sedimentary basins, and should be conducted in parallel with the application of simulators to actual basins.

A multidisciplinary approach to modelling secondary migration: a Central North Sea example

Abstract Numerical simulations assist in understanding secondary migration, and can help estimate which traps in a basin may have received a hydrocarbon charge. This is illustrated by a suite of numerical models used to track the secondary migration of hydrocarbons into an Upper Jurassic Fulmar discovery in the Central North Sea. The models include areal flow calculations using Exxon’s proprietary reservoir simulator, and cross-section calculations using TEMISPACK, a commercial basin modelling package. While the application of conventional reservoir simulation techniques to geologic time-scale problems is itself a novel approach, the most important development has been in the integration of fluid flow modelling with techniques for dating the timing of hydrocarbon charge. These techniques have been used to constrain and validate the model results. In addition, sensitivity studies permit evaluation of the required permeability for effective lateral migration. The areal calculations provide information about migration timing and the fill history of several traps. These fields are charged from mature Kimmeridge source rocks, mapped within the local drainage area. Several model runs were used to evaluate the sensitivity of migration timing to carrier bed permeability and capillary pressure characteristics. Calculations indicated that for reservoir quality carrier beds (permeability ≥ 1 mD) secondary migration can be geologically instantaneous, and that even low permeability silts can serve as effective migration pathways. A cross-sectional model was used to integrate cross-stratal and strata-parallel migration. The model included hydrocarbon expulsion from Kimmeridge source rocks into the Fulmar sandstone and lateral migration up the flank of the structure. Drilling results indicate that leakage into younger Tertiary strata has occurred. The calculation sugests a portion of the top seal breached by 10–20 Ma. Evidence of partial seal loss includes a seismic chimney interpreted above the predicted breached seal, and an appraisal well high on the Jurassic structure which encountered hydrocarbon-stained reservoir rocks with an apparent palaeohydrocarbon contact. Furthermore, hydrocarbons in the overlying Tertiary reservoirs can be geochemically tied to the remaining Jurassic accumulation. Finally, analysis of authigenic cements, particularly the K-Ar ages of fibrous illite, suggests that hydrocarbons occupied the trap until approximately 10 Ma. Analysis of Tertiary hydrocarbon fluid inclusions further indicates that hydrocarbons entered these Tertiary reservoirs approximately 10 Ma. These latter two techniques now enable the modeller to apply temporal constraints to hydrocarbon charge simulation. Such constraints allow ‘history matching’ analogous to field scale reservoir simulations.

Information gain in prospect assessment by using basin modeling

To enhance the quality of oil- and gas-resource assessments and to reduce the risks in oil and gas exploration, a number of assessment techniques have been developed. Unfortunately, these techniques have not always been effective in the timely transfer of information. The amount of time that is required for preparing assessments does not always allow for the necessary high-quality data to be generated. To overcome this problem, a method based on an analysis of the phase state of oil and the dynamics of fluids in secondary migration of hydrocarbons is proposed. The phase state of the oil and fluid potential for secondary migration is estimated initially for each prospect together with the extent of the drainage area. On the basis of these estimates, statistical calculations can be made for the generation and expulsion of hydrocarbons. As a result, more reliable data are available for prospect assessment. The application of this method has a practical significance in that it brings the role of basin modeling in prospect assessment into full play, increases the reliability of petroleum-resource assessments, and reduces the risks in exploration. A case study from the Beitang region in eastern China is presented.

Exhumed Hydrocarbon Traps in East Greenland: Analogs for the Lower-Middle Jurassic Play of Northwest Europe

Four exhumed hydrocarbon traps crop out in the Traill O region of East Greenland, each at the footwall crest of a fault-block formed during Early Cretaceous rifting. Former oil accumulations are indicated by a pore fill or pore lining of solid bitumen within the Jurassic sandstone-dominated Vardekloft and Olympen formations. The Vardekloft Formation is divided into an undated fluvial-dominated lower unit (0-520 m) and a Bajocian-Callovian upper unit (65-1020 m) deposited in a shallow-marine environment. The Oxfordian Olympen Formation (0-250 m) contains shallow-marine and fluviodeltaic deposits. The sandstones are dominantly quartzarenites, and petrographic fabrics, such as dissolved feldspar, late quartz cement, and stylolites, are consistent with burial depths in excess of 2.5 km. Porosities ranged from 7 to 27% (generally about 20%, about one-half of which was primary), and permeabilities ranged from 1 to 622 md, prior to the formation of solid bitumen. The distribution of solid bitumen in each trap can be mapped out, allowing sealing elements and original oil-water contacts to be defined. Three of the four exhumed traps (Mols Bjerge, Laplace Bjerg, and Bjornedal) were simple one-seal structural traps. Conformable Upper Jurassic mudstone, unconformable Albian-Cenomanian mudstone, and normal faults are the three top-sealing elements. The fourth (Svinhufvuds Bjerge) was a poly-seal trap with a combined top-seal and a low-side fault closure. Preliminary estimates of the volume of original oil in place within these structures range from 0.2-1.1 billion bbl for the Mols Bjerge trap to 5.3-11.9 billion bbl for the Bjornedal trap. These estimates are prone to large errors, due to uncertainties in estimating original trap geometry, hydrocarbon saturation, and net/gross ratio, and in the understanding of volume changes of hydrocarbon in each trap during thermal degradation of the oil. The Upper Jurassic Bernbjerg Formation is the only known potential source rock in the region, which would require a drainage distance of less than the fault-block spacing to fill the largest of the traps. Secondary hydrocarbon migration into these traps occurred between the Cenomanian (age of the youngest sealing element) and early Eocene to late Oligocene (when widespread volcanism and sill intrusion resulted in thermal degradation of the oil). Each of these structures is relatively well exposed and accessible; we believe that they will provide excellent analogs for studies of enhanced recovery from the mature Lower-Middle Jurassic oil fields of Northwest Europe.

Geological Models for the Next Decade: What Do We Need to Reduce Hydrocarbon Exploration Risk?

Several main areas of quantitative geologic model development, needed over the next decade, are outlined using illustrative examples to emphasize need. In order of importance these areas are: (i) motion of multiple faults in 3-D tied to multi-phase fluid-flow and overpressure evolution in sediments: (ii) dynamical primary and secondary hydrocarbon migration in 3-D; (iii) self-consistent salt and sediment dynamical interactions; (iv) turbidite and sequence stratigraphic models; (v) self-consistent dynamical tectonic and sediment evolution models; (vi) integrated economic and geological relative importance and risking methods. As vital adjuncts, each area of model development should include the capabilities: (a) of forward and inverse modes of operation; (b) of being able to provide quantitative measures of uniqueness, resolution, precision and sensitivity in relation to intrinsic model assumptions, parameters in the model, numerical limits, and in respect of quality, quantity and sampling frequency of present-day data used as control information; (c) of yielding quantitative probabilistic assessments of the range of results in view of the indeterminancy of point (b); (d) of culling needed data from a common data base; (e) of being built and used in a user-friendly, technology-transferable mode. No crystal ball is perfect, so this present view of the next decade's needs in geologic modeling should be continuously up-dated and modified as future information becomes available, which will influence the values, worth, and priorities of the presently estimated future needs in geologic model requirements.

Secondary migration of hydrocarbons in inclined layers

SUMMARY The 1-D models of segregated two-phase flow in reservoir engineering are utilized to model lateral secondary migration of hydrocarbons in slightly inclined and permeable layers. It is assumed that the layers are sealed below and above by low-permeability strata. The flow is then characterized by a gravity number and a mobility ratio when capillary forces are neglected. For buoyancy-driven migration, gravity numbers (much) larger than 1, these models imply that the Darcy velocity of the flow is only given by the buoyancy force due to the density difference between water and oil. For gravity numbers larger than 1, the thickness of the hydrocarbon zone below the sealing top is proportional to the inverse gravity number. Furthermore, if the oil flow in the layer is only a small fraction of the total flow, the height of the hydrocarbon zone is also proportional to this fraction. It is therefore concluded that in buoyancy-driven migration with large gravity numbers, where the hydrocarbon part of the total flow is small, only a small fraction of the upper part of the layer is saturated with oil. Therefore, only a little oil may be lost due to irreducible saturation, and long-range migration is possible.

Scaled Physical Model of Secondary Oil Migration

A scaled physical model was constructed to simulate gravity- and capillary-controlled flow of oil into a water-saturated sand during secondary hydrocarbon migration. The model provided both visualization of the flow patterns and estimates of hydrocarbon transport rates and efficiencies. The dimensions and physical properties of the model were designed so the balance of gravity, capillary, and viscous forces was the same in the model as in the geologic system. The physical model was a sand pack between glass plates; the pack was 52 cm high, 100 cm long, 2.5 cm thick, and inclined at a 5° dip; its porosity was 42%, and its permeability was 7.0 × 10-10 m2 (710 d). It modeled a geologic carrier bed 27 m thick with 20% porosity and 9.9 × 10-14 m2 (100 md) permeability overlying a source rock. A dyed oil was injected into the lowest corner at a rate of 1 cm3/day, and it exited the highest corner at atmospheric pressure. Oil movement was followed both visually and by ultrasonic velocity measurements. The behavior of fluids in the model led us to the following conclusions for oil transport through water-wet, homogeneous carrier beds. The rate-limiting step in charging a trap is not secondary migration, but rather the rate of oil release from the source rock. High hydrocarbon loss may occur during vertical migration (when the carrier bed lies above the source) because of extensive dispersion. Losses during lateral migration are probably minimal because flow is concentrated below the top seal.

Three-phase fluid migration with solubilities in a two-dimensional basin simulation model

Three-phase fluid migration with solubilities is examined in a two-dimensional basin simulation model. Darcy's law is applied with the driving forces of excess pressure from disequilibrium compaction, buoyancy and capillary pressure controlling the flow of different fluid phases. Relative permabilities are related to the saturation fractions taken by each fluid phase in the pore space. The test results show that solubilities have a significant impact on both primary and secondary hydrocarbon migration and accumulation. The spatial and temporal patterns of hydrocarbon migration and accumulation with solubility are various, depending on the specific geological, geothermal and geochemical conditions. Because the dynamic features of hydrocarbon migration are tied to phase saturation through relative permeability variations, and to phase solubility through temperature and pressure dependence, this study indicates that the hydrocarbon accumulation history must be considered in exploration assessments of basins. Application of the phase-dependent migration model to a geological section descriptive of the Hammerfest Basin, Barents Sea shows that Tertiary uplift and erosion, which lead to the leakage of hydrocarbons, are probably the dominant causes of the majority of exploration sub-commericial holes in the Hammerfest Basin.

Role of overpressures and in situ stresses in fault-controlled hydrocarbon migration: a case study

Two wells (No. 1 and No. 2), separated by 2 km and situated in the upper prospective zone of a Tertiary basin in South-East Asiat, cross the same Mio-Pleistocene shaly-sandy series. From 1500 m downwards, these series are subject to significant overpressures related to an active margin. Comparison of well data, in terms of sonic compaction profiles, anomalous pressures and temperatures, has provided evidence of both a positive pressure and a temperature anomaly below a vertical depth of 1800 m in well 2. This anomaly is closely associated with the presence of liquid hydrocarbons in the 1900–2000 m reservoir interval. The confirmed deep source of these fluids and the amounts that have migrated during a short time interval can be explained only by the transitory dynamics of active transfers along faults and fractures. The episodic nature of this movement is the result of hydromechanical mechanisms in which the interactions between the high pressure regime and principal in situ stresses appear to be fundamental. The processes which induce open faulting and fluid pressure build-up in the direction of reservoirs with lower pressure regimes occur preferentially during phases of lateral tectonic stress relaxation, as soon as the effective minimum stress component becomes negative. The analysis of this case study gives a better understanding of the dynamic phenomena involving secondary hydrocarbon migration and caprock efficiency. The results obtained will help to optimize the overpressure prediction approach in comparable geological contexts.

Late Diagenetic Dolomitization of Lower Ordovician, Upper Knox Carbonates: A Record of the Hydrodynamic Evolution of the Southern Appalachian Basin

Late diagenetic dolomitization of the Lower Ordovician, Upper Knox Group in the southern Appalachian basin was closely associated with widespread secondary porosity development, hydrocarbon migration, and local Mississippi Valley-type mineralization. Regionally extensive (^sim70,000 km2), late diagenetic dolomites consist of replacement dolomites and zoned dolomite cements. Late diagenetic replacement dolomites comprise 15 to 50% of all Knox matrix dolomites. The ^dgr18O (-11.9 to -5.3^pmil), ^dgr13C (-3.8 to +0.9^pmil), and 87Sr/86Sr (0.70895 to 0.70918) values of late diagenetic replacement dolomites overlap with those of the first zone of dolomite cements (zone 2), early replacement dolomites, and Lower Ordovician arine calcites, reflecting rock buffering of initial dolomitizing fluids and extensive neomorphism of replacement dolomites by subsequent late diagenetic fluids. Nonporous to sucrosic, late diagenetic dolomites have porosities (1 to 16%) and permeabilities (0 to 1030 md) significantly greater than those of early diagenetic replacement dolomites and host limestones ( 165°C), saline (13 to 22 wt.% NaCl equivalent) basinal brines that underwent extensive fluid-rock interaction with clastics. Precipitation temperatures of late diagenetic dolomites estimated from fluid inclusion homogenization temperatures and systematic trends in ^dgr18O va ues record a regionally developed, prograde-to-retrograde thermal history. Knox late diagenetic dolomites are interpreted to record the spatial and temporal evolution of large-scale fluid flow systems that developed in response to different burial and tectonic stages of the southern Appalachian basin. The occurrence of zoned dolomite cements in tectonic fractures and breccias, and their close association with noncarbonate diagenetic minerals of Pennsylvanian to Early Permian ages, suggest that most Knox late diagenetic dolomites record deep subsurface (2 to >5 km) fluid migration in response to late Paleozoic Alleghenian tectonism (330 to 265 Ma). Late diagenetic matrix dolomites served as long-lived conduits that focused and channeled diagenetic fluids in the deep subsurface. The occurrence of bitumen in secondary porosity within late diagenetic dolomite indicates that they likely were the most viable reservoirs during hydrocarbon migration in the late Paleozoic.

An Integration of Secondary Hydrocarbon Migration Modeling and GIS into Resource Assessment: ABSTRACT

An Integration of Secondary Hydrocarbon Migration Modeling and GIS into Resource Assessment: ABSTRACT

Organic inclusions as an indicator of oil/gas potential assessment of carbonate reservoir beds

Organic inclusions could be formed at the stages of either primary or secondary migration of hydrocarbons so long as mineral crystallization or recrystallization takes place in the sediments, presenting a direct indicator of oil/gas evolution, migration and abundance. Based on the study of organic inclusions in carbonate-type reservoir beds of commercial importance from North China, Xingjing, North Jiangsu, Jianghan, Sichuan and Guizhou in China, many inclusion parameters for oil/gas potential assessment of carbonate reservoir beds are summarized in this paper, including: 1) Types of organic inclusion: Commercially important oil beds are characterized by inclusions consisting of either pure liquid hydrocarbons or liquid plus minor gaseous hydrocarbons, while commercially important gas reservoirs are characterized by inclusions consisting of either pure gaseous hydrocarbons or gas plus minor liquid hydrocarbons. 2) Quantity of organic inclusions: The number of organic inclusions in commercially important oil/gas reservoirs is over 60% of the total inclusion percentage. 3) Temperature of saline inclusions: The homogenization temperatures of contemporaneous saline inclusions in oil reservoirs range from 91–161 °C, while in gas reservoirs from 150–250 °C). 4) Inclusion composition: In commercially important oil reservoirs, C1/C2=2−10, C1/C3=2−4, C1/C4=2−21, (C2−C4)/(C1−C4)(%)>20, (CH4+CO+H2)/CO2 (molecules/g)=0.5−1.0, and in C2−C3−nC4 triangle diagram there should be an upside-down triangle with the apex within the ellipse, while in commercial gas reservoirs, C1/C2=10−35, C1/C3=14−82, C1/C4=21−200, (C2−C4)/(C1−C4)(%) 1, and there would be an upright triangle with the apex within the ellipse.

Three-Dimensional Modeling of Secondary Hydrocarbon Migration: Principles and Experiences in the Pannonian Basin

Secondary migration is important, but because of its complexity, it is rarely studied in modern basin analysis even though it is a primary condition of successful hydrocarbon exploration. The purpose of the three-dimensional model for secondary hydrocarbon migration is to show the regularity, path, direction, and amount of the migrating hydrocarbon from the petroleum source rocks so we can predict the volume of oil and gas that are available to a trap. The method is quantitative, which constructs the hydrocarbon source map and the map of the potential migrational path. Also we can use [open quotes]hydrocarbon loss maps,[close quotes] to construct hydrocarbon flux maps, which show the amount of hydrocarbons that flowed at each point of the migration surface that is the amount of accumulated hydrocarbon in different areas. A fundamental thesis is that even the best traps can be productive only if they are on a migration path; otherwise, they are [open quotes]empty.[close quotes] The Geological Institute of the Miskolc University and the Hungarian Oil and Gas Co. have collaborated since 1988 to develop this method and the program. According to model calculations in the Pannonian basin, this method appears to be effective because almost all of the knownmore » hydrocarbon fields could have been predicted. Also, we could identify several promising, but so far unexplored, areas. The first prospect that was selected for drilling on this basis was an oil discovery.« less

Large-scale fluid flow in the Middle Devonian Presqu'ile barrier, Western Canada Sedimentary Basin

Saddle dolomite cements are regionally extensive in the Middle Devonian Presqu9ile (or Keg River) barrier and are spatially associated with Mississippi Valley-type mineralization at Pine Point (Northwest Territories). From northeastern British Columbia to Pine Point over a lateral distance of 400 km, these dolomite cements show general trends of decreasing 87 Sr/ 86 Sr ratios (0.7106 to 0.7081) and homogenization temperatures (178 to 92 °C), with some increase in δ 18 O values (-16‰ to -7‰ PDB). These regional trends suggest that hotter and more radiogenic basinal fluids moved eastward updip along the Presqu9ile barrier and mixed with cooler ambient formation waters. These movements of basinal fluids were probably related to tectonic thrusting and compression, sedimentary loading, and tectonic uplift on the western margin of the Western Canada Sedimentary Basin, which began to form during Late Jurassic to Early Cretaceous time and climaxed during the Late Cretaceous to Paleocene. The Middle Devonian Presqu9ile barrier appears to have acted as a deeply buried regional conduit system that played an important role in focusing and channeling these basinal fluids. These regional fluid flows appear to have been responsible for extensive burial dolomitization, secondary migration of hydrocarbons, and local Mississippi Valley-type mineralization in the Western Canada Sedimentary Basin.

中国古第三紀南嚢湖成堆積盆地の石油地質地化学

The Paleogene to Neogene Nan Xian sedimentary basin, which is typical of non-marine oil producing sedimentary basins in eastern China, is composed of four structural depressions called the Bi Yang Depression, Nan Yang Depression, Xiang Yang Depression, and Shuang Gou Depression, respectively. The northern Bi Yang and Nan Yang Depressions are the major oil fields in Nan Xiang sedimentary basin, where 3×109 ton of crude oil has been produced during the 40 years since the start of petroleum exploration in the 1950's. Nan Xian crudes are generally characterized by high wax contents (30 to 50%), high pour points (40 to 50°C), and low sulphur contents (0.05 to 0.14%), suggesting that the crude oils are derived from biodegraded higher plants. Some biomarkers such as steranes and hopanes in crude oils, however, suggest significant contribution of zoo- and phytoplanktons.Oil/source rock correlations by biomarkers showed that black shales of middle Paleogene He Tao Yuan Formation are major source rocks in Nan Xiang sedimentary basin. The He Tao Yuan Formation is characterized by a sequence of fluvial alluvial, delta front, and deep basin facies in lacustrine depositional environment. The He Tao Yuan black shale was formed by turbidity current deposition in a deep lake basin when great amounts of river borne clastic sediments accumulated during the marked subsidence of the basement. The He Tao Yuan black shales were enriched in organic matter (present average total organic carbon content=1.8%) because of the increased primary production due to temperate climate and the anoxic depositional environment in the deep basin center. The kerogen of the He Tao Yuan black shale is characterized by oil prone Type I and Type I-II kerogens. The Bi Yang Depression and a part of Nan Yang Depression, especially, could possess the most favorable depositional condition for the formation of petroleum source rocks among others. Several reservoir structures were formed during the uplift of basement during late Paleogene to early Neogene time. Reservoir rocks are mainly sans nes of He Tao Yuan Formation deposited in fluvial and alluvial planes, and delta front in Nan Xiang paleo-lake. He Tao Yuan source rocks have been maturated enough to produce hydrocarbons with the re-subsidence of basement in Neogene Tertiary time. Lithofacies of turbidite alternation was advantageous for the effective expulsion and secondary migration of petroleum hydrocarbons. Much of the hydrocarbons generated have been efficiently accumulated into previously formed traps of the same stratigraphic horizon to form petroleum deposits. The Bi Yang and Nan Yang Depressions have mainly produced liquid oils with a little gas of biodegraded origin. In addition to shallow reservoir depth and oil prone kerogen types of source rocks, the low gas/oil ratio in Bi Yang and Nan Yang oil fields is mainly due to that the He Tao Yuan source rocks have not been overmatured to generate thermocatalytic gases through the evolution history of Nan Xian sedimentary basin.

Computer Simulation of Secondary Hydrocarbon Migration and Entrapment: ABSTRACT

Computer Simulation of Secondary Hydrocarbon Migration and Entrapment: ABSTRACT

A Model of Secondary Hydrocarbon Migration As a Buoyancy-Driven Separate Phase Flow

A mathematical model of secondary migration is described which permits the prediction of hydrocarbon migration and accumulation patterns in a sedimentary basin, if source rock expulsion rates and geometrical and hydraulic properties of major carrier systems are known through geological time. In this model, secondary migration is treated as buoyancy-driven, segregated flow of hydrocarbons in hydrostatic aquifers. Lateral, updip migration is conceived as a Boussinesq-type, free-surface flow, with source and sink terms representing supply from source rocks and leakage through cap rocks and faults. This permits a two-dimensional, map-view mathematical description of a three-dimensional, time-dependent secondary migration system. A nine-point finite difference approximation has been developed to minimize numerical dispersion, and upstream-weighting is used to obtain stable solutions. Example computations for simple, single carrier bed structures are presented.

THE DISTRIBUTION OF MAJOR OIL AND GAS RESERVES IN REGIONAL BASIN STRUCTURES – AN EXAMPLE FROM THE POWDER RIVER BASIN, WYOMING, USA

The location and geographic distribution of oil and gas reserves within a producing basin often indicate that a remarkable concentration of reserves has taken place in a small area. The concentration of reserves is the result of secondary hydrocarbon migration, itself governed by the basin‐wide regional structure which was present at the time of migration. These factors permit the definition of the most prospective areas of a new basin or play at an early stage in the exploration cycle. Basic geochemical data are required for the definition of critical details of the effective generative depocentre, and regional geological‐geophysical data are required to establish regional structures near particular source‐bed levels, or near top Basement as the deepest prospective level. Other data commonly utilized in the early stages of exploration, such as basin classification schemes, reservoir bed studies and tectonic analyses, are rather less important in forward basin evaluation.A particularly clear example of the importance of the regional basement structure in the concentration of oil reserves exists in the Powder River Basin, Wyoming, USA. Cumulative oil production here was over 1.9 B brls** in 1984 from more than 460 oilfields and pools. However, 1.5 B brls (79% of the basin output) were produced from only 22 fields (4.7% of the number of fields and pools in the basin). It is also remarkable that all 22 major oilfields in the Powder River Basin are located on positive Bouguer gravity anomalies, which are expressions of deep basement irregularities. Regional lateral oil migration in the Powder River Basin appears to have utilized routes resulting from Laramide deformation (Late Cretaceous ‐ Paleocene).The resultant basin structure was accentuated by regional structural‐topographic anomalies, which became sites of major structural and stratigraphic traps. In this case regional gravity maps seem to show sufficient details of the deep structure for the accurate definition of major exploration targets.The Powder River Basin is thus an excellent example of the importance of regional geological and geophysical reconnaissance data aimed at, and available for, the definition of major migration pathways at an early stage of hydrocarbon exploration. When combined with geochemical data, such an approach will become the basis for forward exploration in all known basins.