Hydrocarbon Migration Modeling Research Articles

Discovery and inspiration of large- and medium-sized glutenite-rich oil and gas fields in the eastern South China Sea: An example from Paleogene Enping Formation in Huizhou 26 subsag, Pearl River Mouth Basin

Based on the practice of oil and gas exploration in the Huizhou Sag of the Pearl River Mouth Basin, the geochemical indexes of source rocks were measured, the reservoir development morphology was restored, the rocks and minerals were characterized microscopically, the measured trap sealing indexes were compared, the biomarker compounds of crude oil were extracted, the genesis of condensate gas was identified, and the reservoir-forming conditions were examined. On this basis, the Paleogene Enping Formation in the Huizhou 26 subsag was systematically analyzed for the potential of oil and gas resources, the development characteristics of large-scale high-quality conglomerate reservoirs, the trapping effectiveness of faults, the hydrocarbon migration and accumulation model, and the formation conditions and exploration targets of large- and medium-sized glutenite-rich oil and gas fields. The research results were obtained in four aspects. First, the Paleogene Wenchang Formation in the Huizhou 26 subsag develops extensive and thick high-quality source rocks of semi-deep to deep lacustrine subfacies, which have typical hydrocarbon expulsion characteristics of “great oil generation in the early stage and huge gas expulsion in the late stage”, providing a sufficient material basis for hydrocarbon accumulation in the Enping Formation. Second, under the joint control of the steep slope zone and transition zone of the fault within the sag, the large-scale near-source glutenite reservoirs are highly heterogeneous, with the development scale dominated hierarchically by three factors (favorable facies zone, particle component, and microfracture). The (subaqueous) distributary channels near the fault system, with equal grains, a low mud content (<5%), and a high content of feldspar composition, are conducive to the development of sweet spot reservoirs. Third, the strike-slip pressurization trap covered by stable lake flooding mudstone is a necessary condition for oil and gas preservation, and the NE and nearly EW faults obliquely to the principal stress have the best control on traps. Fourth, the spatiotemporal configuration of high-quality source rocks, fault transport/sealing, and glutenite reservoirs controls the degree of hydrocarbon enrichment. From top to bottom, three hydrocarbon accumulation units, i.e. low-fill zone, transition zone, and high-fill zone, are recognized. The main area of the channel in the nearly pressurized source-connecting fault zone is favorable for large-scale hydrocarbon enrichment. The research results suggest a new direction for the exploration of large-scale glutenite-rich reservoirs in the Enping Formation of the Pearl River Mouth Basin, and present a major breakthrough in oil and gas exploration.

Regional source rock thermal stress modeling and map-based charge access modeling of the Port Isabel passive margin foldbelt, northwestern Gulf of Mexico

The Port Isabel passive margin foldbelt covers 17,000 km2 of the northwestern deepwater U.S. Gulf of Mexico. Seven oil exploration wells have been drilled in the area from 1996 to 2007, yielding a single uncommercial gas discovery. The 5–7 km thick Oligo-Miocene section prevents drilling from penetrating the underlying Paleogene and Mesozoic source rocks. Accommodation space for the Oligo-Miocene section is created by the collapse of a paleo-salt wall, leading to linked fault systems in the upper decollement to the east. We use 13 exploration wells to construct 1D and map-based 2D basin models to investigate the burial and thermal history of three inferred source rock horizons (Paleogene, Turonian, and Tithonian). We interpret a 2D seismic data grid tied to four wells to constrain stratigraphic depths and thicknesses of the younger and shallower Wilcox source rock horizons, and the Jurassic and Cretaceous source rock horizons. Our results indicate that vitrinite reflectance is a proxy for the thermal stress levels reached by the source rocks as supported by maps of hydrocarbon charge access. We conclude that all three source rock intervals have reached varying degrees of maturity, expelled hydrocarbons in late Paleogene to mid-Neogene, and likely continue expelling hydrocarbons to the present-day at a reduced rate. The deposition of the Oligocene and Middle Miocene sedimentary section has buried the underlying source intervals and likely brought them into the gas/condensate window in the present-day. Our mapping of the extensive seismic reflection grid reveals four-way structural closures, three-way stratigraphic traps, and salt truncation structures associated with amplitude anomalies which may support our predictions for maturity in the underlying source rocks. Our thermal stress maps predict that the modeled source rocks are mature and our charge access models for the available wells constrain migration patterns, although the timing of the early hydrocarbon charge and late trap formation remain significant risk factors.

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Permian and Triassic hydrocarbon migration and accumulation in the Cainan area, Junggar Basin, China

Gas Chromatography-Mass Spectrometer (GC-MS), chloroform asphalt “A”, and carbon isotope measurements were used to determine hydrocarbon migration pathways. This study focused on hydrocarbon migration pathways and accumulation distribution in the Wucaiwan region, Junggar Basin, China. The biometric parameters were used to compare oil sources. Type and distribution characteristics of natural gas were determined in order to study the different strata. Quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) were analyzed to determine the hydrocarbon migration and charging periods. Geochemical indexes, such as, n-alkane, triterpenoids, sterane, and hopane, were utilized to investigate the pathways of hydrocarbon migration. Recent studies on petroleum maturity have focused on comparison of source rocks and reported that the maturity effects of source rock and reservoir oil are weak, while those effects are high in the Liuchu area. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The ααα C29 (20 S)/(20 S + 20 R), C29ββ/(αα + ββ), and C31 hopane 22R/C30 hoopane ratios, and C19/C21 tricyclic terpane ratio, C19/C21 tricyclic terpenes, C31 (22 S)/(22 S + 22 R), and C29 (20 S)/(20 S + 20 R) ratios were analyzed to determine the maturity of crude oil. Petroleum migrated along fault, sandbody, and unconformity, which suggest vertical and lateral migration occurred. Reservoir sandstone porosity and mudstone content of the thick caprock are likely to limit lateral hydrocarbon migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The study offers an improved understanding of uncertain hydrocarbon migration pathways and further developed the hydrocarbon migration and accumulation models.

Study on Hydrocarbon Accumulation Periods Based on Fluid Inclusions and Diagenetic Sequence of the Subsalt Carbonate Reservoirs in the Amu Darya Right Bank Block

In order to provide paleofluid evidence of hydrocarbon accumulation periods in the Amu Darya Right Bank Block, microexperiments and simulations related to the Middle-Upper Jurassic Callovian-Oxfordian carbonate reservoirs were performed. On the basis of petrographic observation, the diagenetic stages were divided by cathodoluminescence, and the entrapment stages of fluid inclusions were divided by laser Raman experiment and UV epifluorescence. The hydrocarbon generation (expulsion) curve and burial (thermal) history curve of source rocks were simulated by using real drilling data coupled with geochemical parameters of source rocks, such as total organic carbon (TOC) and vitrinite reflectance ( R o ). The above results were integrated with microthermometry of fluid inclusions by inference the timing of hydrocarbon migration into the carbonate reservoirs. The horizon-flattening technique was used to process the measured seismic profile and restore the structural evolution profile. Four diagenetic periods and three hydrocarbon accumulation periods were identified. (i) For Syntaxial stage, the fluid captured by the overgrowing cement around particles is mainly seawater; (ii) for (Early) Mesogenetic burial stage, the calcite cements began to capture hydrocarbon fluids and show yellow fluorescence under UV illumination; (iii) for (Late) Mesogenetic burial stage, two sets of cleavage fissures developed in massive calcite cements, and oil inclusions with green fluorescence were entrapped in the crystal; (iv) for Telogenetic burial stage, blue fluorescent inclusions along with hydrocarbon gas inclusions developed in dully luminescent calcite veins. Based on the accurate division of hydrocarbon migration and charging stages, combined with the structural evolution history of the traps, the hydrocarbon accumulation model was established. Because two of the three sets of source rocks are of marine origin, resulting in the lack of vitrinite in the kerogen of those source rocks, there may be some deviation between the measured value of R o and the real value. Some systematic errors may occur in the thermal history and hydrocarbon generation (expulsion) history of the two sets of source rocks. Due to the limitations of seismic horizon-flattening technique—such as the inability to accurately recover the inclined strata thickness and horizontal expansion of strata—the final shape of the evolution process of structural profile may also deviate from the real state in geological history. The accumulation model established in this study was based upon the fluid inclusion experiments, which can effectively characterize the forming process of large condensate gas reservoirs in the Amu Darya Right Bank Block and quantify the timing of hydrocarbon charging. However, the hydrocarbon migration and accumulation model does not take the oil-source correlation into account, but only the relationship between the mature state of source rocks and the timing of hydrocarbon charging into the reservoirs. Subsequent research needs to conduct refined oil-source correlation to reveal the relationship between gas, condensate, source rocks, and recently discovered crude oil and more strictly constrain and modify the accumulation model, so as to finally disclose the origin of the crude oil and oil reservoir forming process in the Amu Darya Right Bank Block, evaluate the future exploration potential, and point out the direction of various hydrocarbon resources (condensate gas and crude oil).

Study on fault-controlled hydrocarbon migration and accumulation process and models in Zhu I Depression

Through the analysis of the faults and their internal structure in Zhu I Depression, it is found that the internal structure of the late fault is obviously segmented vertically. It develops unitary structure (simple fault plane) in shallow layers, binary structure (induced fracture zone in hanging wall and sliding fracture zone in footwall) in middle, layers and ternary structure (induced fracture zone in hanging wall and sliding fracture zone in middle, and induced fracture zone in footwall) in deep layers. Because the induced fracture zone is a high porosity and permeability zone, and the sliding fracture zone is a low porosity and ultra-low permeability zone, the late fault in middle layers has the character of “transporting while sealing”. The late fault can transport hydrocarbon by its induced fracture zone in the side of the hanging wall and seal hydrocarbon by its sliding fracture zone in the side of the footwall. In deep layers, the late fault has the character of “dual-transportation”, induced fracture zones in both sides of hanging wall and footwall can transport hydrocarbon. The early fault that only developed in the deep layers is presumed to be unitary structure, which plays a completely sealing role in the process of hydrocarbon migration and accumulation due to inactivity during the hydrocarbon filling period. Controlled by hydrocarbon source, early/late faults, sand bodies and traps, two reservoir-forming models of “inverted L” and “stereo-spiral” can be proposed in middle layers, while two reservoir-forming models of “cross fault” and “lateral fault sealing” are developed in the deep layers of Zhu I Depression.

Petroleum migration and accumulation: Modeling and applications

Subsurface hydrocarbon observations at any scale serve as critical clues to understand and reconstruct migration pathways and charge histories through geological time to assess the risk of petroleum exploration targets. Hydrocarbon migration commonly occurred millions of years ago, and the pathways can rarely be observed in wells or in outcrops. Therefore, hydrocarbon migration modeling tools are important to test and quantify the processes and elements, which impact hydrocarbon migration. This paper presents a new method of analyzing migration in superimposed basins, which have experienced multiple stages of basin subsidence and inversion, during which multiple episodes of hydrocarbon generation, migration, and accumulation occurred. The new modeling method first identifies the character of the migration and accumulation units by synthesizing geological factors, such as heterogeneity of carrier beds and reservoirs. Second, hydrocarbon migration is analyzed as a geologic process, for which the invasion-percolation (IP) migration method seems to be most suitable. The IP migration method demonstrates a good relationship between migration driving and resisting forces along pathways and thus can be used to reasonably model hydrocarbon migration processes at any scale of units in a basin. The new migration method provides insights into quantitative methods that can be applied to petroleum system analysis. The new method has been applied to several Chinese basins and has proven to be useful for defining exploration targets and resource assessments in mature, frontier, and, especially, tectonically complex basins. A case study of the Upper Triassic Chang 7 and Chang 8 units in the southern Ordos Basin, central China, is presented to demonstrate a multistage hydrocarbon accumulation unit. Modeling results show that the same pairs of reservoir-seal sets contained different accumulation units in the geological past with different styles of hydrocarbon migration and different accumulation patterns. It can be concluded that the style and character of early hydrocarbon migration have significantly affected the more recent hydrocarbon migration and the present-day distribution of hydrocarbons.

Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China

The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step- or “Z”-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J1b, K1q, N1s1, and N1s2 have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J1b, K1q, and N1s, respectively.

Application of Geographic Information System (GIS) to Model the Hydrocarbon Migration: Case Study from North-East Malay Basin, Malaysia

The purpose of this study is to model the migration of hydrocarbon using Geographic Information System (GIS). Understanding hydrocarbon migration is important since it can mean the difference between success and failure in oil and gas exploration project. The hydrocarbon migration modeling using geophysical method is still not accurate due to the limitations of available data. In recent years, GIS has emerged as a powerful tool for subsurface mapping and analysis. Recent studies have been carried out about the abilities of GIS to model hydrocarbon migration. Recent advances in GIS support the establishment and monitoring of prediction hydrocarbon migration. The concept, model, and calculation are based on the current geological situation. The spatial data of hydrocarbon reservoirs is determined by its geometry of lithology and geophysical attributes. Top of Group E horizon of north-east Malay basin was selected as the study area due to the occurrence of hydrocarbon migration. Spatial data and attributes data such as seismic data, wells log data and lithology were acquired and processed. Digital Elevation Model (DEM) was constructed from the selected horizon as a result of seismic interpretation using the Petrel software. Furthermore, DEM was processed in ArcGIS as a base map to shown hydrocarbon migration in north-east Malay Basin. Finally, all the data layers were overlaid to produce a map of hydrocarbon migration. A good data was imported to verify the model is correct.

Three-dimensional hydrocarbon migration and accumulation modeling based on finite volume method

Abstract Aiming at the issue that the application effect of current 3-D hydrocarbon migration and accumulation modeling technique cannot meet the actual requirement because of over-simplified geologic model, a 3-D dynamic geologic model using PEBI grid in bedding and columnar shape was established, which can be used to solve the heterogeneity in reservoirs of various sedimentary facies, and to reduce the effect of mixed lithologies on modeling accuracy. A 3-D numerical modeling technique based on finite volume method was established, including the construction of variable grid flow equation, decomposition and calculation of full-tensor permeability, and calculation of conductivity etc. Some related processing techniques, such as smoothing of key parameter curves, stability processing of upstream and downstream of grid flow, etc. were used to improve the convergence of Newton's iteration. Automatic adjustment of time step and multi-core parallel computation were taken to enhance the running efficiency of the software. In a case study of Nanpu sag in the Bohai Bay Basin, the hydrocarbon migration and accumulation process, oil saturation and hydrocarbon resources abundance in various periods were simulated, the modeled oil saturation, accumulation quantity and hydrocarbon distribution locations coincide with current exploration status. The results also showed that the proved ratio of hydrocarbon resources in target layers is 84.4%, the majority of the resources are distributed in Block B and Block C, and it is predicted that undiscovered resources are mainly near Well NP2-16 in Block C and in the structure north of Well NP5-4 in Block A.

Effects of carrier bed heterogeneity on hydrocarbon migration

Reservoir/carrier bed heterogeneity is a common geological phenomenon. This study applied a hydrocarbon migration model based on the invasion percolation theory to simulate the formation of hydrocarbon migration pathways in heterogeneous carrier beds. The results indicate that the pathways and hydrocarbon accumulations in reservoirs may differ from conventional models when continuous low-permeability layers occur as networks within reservoirs. Such low-permeability layers may have formed through depositional or diagenetic processes within reservoir rocks at variable scales. Oil-bearing reservoir in Donghe Sandstone in Hadexun Oilfield in northern Tarim Basin, China, was analyzed to demonstrate the forming mechanisms of substantial tilting of oil-water contact. Donghe Sandstone is a quartz sandstone deposited in an open marine shoreface-shelf environment during a major transgression in Early Carboniferous. . Major diagenetic products are abundant tabular concretions along bedding planes and cross laminae. The low-permeability concretions serve as fluid flow barriers which compartmentalize the Donghe Sandstone reservoir. As a result, the oil-water contacts and the saturation of oil in the reservoir appear irregular and tilted in Hadexun Oilfield and neighboring regions.

Is there a pre-Cretaceous source rock in the Colombia Putumayo Basin? Clues from a study of crude oils by conventional and high resolution geochemical methods

A geochemical characterization of sixteen crude oil samples from the Putumayo Basin, southern Colombia, was carried out. This basin is located to the north of Ecuador's Oriente Basin, one of the most prolific hydrocarbon basins in South America. Regardless of the fact that these two basins seem to share the same geological evolution, the volume of hydrocarbon reserves found in the Oriente Basin is five times greater than in the Putumayo Basin. This represents an exploratory opportunity to the extent that a better understanding of the petroleum system processes in the Putumayo Basin can be achieved. Newly available geochemical technology shows evidence that these crude oils originated from Late Cretaceous source rocks. The novel application of an age-related biomarker, the C25-highly branched isoprenoid, has constrained the age of the principal source of all these oils as Late Cretaceous or younger. Advanced geochemical technologies, such as compound specific isotope analyses of biomarkers (CSIA-B) and diamondoids (CSIA-D), and quantitative extended diamondoid analysis (QEDA), have confirmed, repeatedly, that the oil samples are all related to the same source with minor facies variations. The integration of these results with geological data suggests the presence of a very efficient petroleum system, characterized by an alternating sequence of soA§urce and reservoir rocks. Thermal maturity of the oils from biomarker and diamondoid parameters ranges from well before the peak of hydrocarbon expulsion to the beginning of the late hydrocarbon generation phase. The aerial distribution of these maturity parameters suggests the existence of two, or possibly three, pods of active source rocks, located to the southwest and to the east of the basin, and possibly to the north. This would modify the classic hydrocarbon migration model for the Putumayo Basin, increasing the hydrocarbon potential of the basin. Given the low level of thermal maturity documented in the Cretaceous sequence that has been drilled, the possibility to evaluate the presence of a very reactive kerogen with hydrocarbon expulsion thresholds at lower temperatures is proposed.

Hydrocarbon Generation and Migration Modeling in Southwestern Margin of the Ulleung Basin, East Sea

Hydrocarbon Generation and Migration Modeling in Southwestern Margin of the Ulleung Basin, East Sea

Hydrocarbon Origin and Accumulation Model of Putaohua Reservoir in Southern Daqing Placanticline Area

There are great oil and gas exploration prospect in south of Daqing Placanticline, with unclear understanding of source rock and accumulation model, the progress of oil exploration is restricted. To definite the source of oil and gas, according to chromatography data and analysis data, combined with potential of hydrocarbon generation and expulsion, oil-gas migration pathway, the hydrocarbon migration and accumulation model is proposed. It can be concluded that the oil from Putaohua reservoir in the south of Daqing Placanticline area mainly come from K2qn1 source rock locally, while the hydrocarbon sources of K2qn1 in the east and west of the depression makes small contribution to the research area. Migrate in source area is the main hydrocarbon migration and accumulation mode. Re-define the oil source of Putaohua reservoir can help enhance the cognition of the hydrocarbon accumulation condition and accumulation model, in order to direct the research for the accumulation and distribution principle of oil and gas exploration and favorable area prediction in the future.

Identification of NW-Trending Faults in the Northwestern Junggar Basin (NW China) and its Significance of Hydrocarbon Migration

The presence of the NW-trending faults in the northwestern Junggar Basin (NW China) and their relation to hydrocarbon migration were discussed. The presence of the faults was confirmed by new seismic and stratigraphic studies. They formed a rectangular-shape fault system together with the previously and commonly acknowledged NE-trending faults. Hydrocarbon shows are present widely in the cross of the two types of faults on the basis of field survey. Representative shows were further analyzed by petrography and geochemistry, in order to understand hydrocarbon migration features. It is implied that the two types of faults are both significant for the migration. In particular, the newly identified NW-trending faults can act as the primary and ultimate pathway for migration from the petroleum source to accumulation areas. Thus a new complex fault-controlled hydrocarbon migration model was suggested. Favorable hydrocarbon exploration targets were predicted according to the model, providing new information for shaping exploration and exploitation strategies. The results also have wide implications for the study in elsewhere mountain-front piedmont areas where the hydrocarbon exploration and exploitation is generally related to fault.

Extending NMR data for permeability estimation in fine-grained sediments

We combine nuclear magnetic resonance (NMR) transverse relaxation time data and gamma ray data to estimate lithology-dependent permeability in silt- and clay-rich sediments. This approach extends the utility of the Schlumberger-Doll Research (SDR) permeability equation from reservoirs to aquicludes and seals, and thus improves the value and robustness of NMR data. Data from Keathley Canyon, northern Gulf of Mexico show that NMR data can be used to define permeability from 10 −18 to 10 −14 m 2 (0.001–10 millidarcies) as calibrated and tested by direct measurements on core samples. We performed uniaxial, constant rate-of-strain consolidation experiments on sediments from Keathley Canyon to determine core-scale permeability. Permeabilities from these experiments were compared to permeabilities calculated from logging-while-drilling data. A better fit between log-derived permeability and laboratory-measured permeability was obtained using the SDR equation with a variable coefficient A, rather than a constant A as is typically used. We show how A is a function of lithology and can be modeled from gamma ray data. The relationship between A and gamma ray values suggests that variations in A are caused by platy clay minerals and the effect they have on the pore system. Our results provide improved means for permeability estimation for application in basin flow modeling, hydrocarbon migration modeling, and well completion design.

Genetic models of structural traps related to normal faults in the Putaohua Oilfield, Songliao Basin

The Putaohua Oilfield is a fault-prolific area and the faults have close relation with structural traps. The genetic models of the structural traps in the Putaohua Oilfield can be divided into two types: individual fault model and multi-fault interaction model. This is based on the description of displacement distribution of typical individual normal faults, the geometry of the footwall and hanging wall, and the analysis of the interaction between faults and the corresponding change in geometry when the faults grow. The individual fault model is that the displacement reaches a maximum at or near the center of fault and decreases toward the fault tips, so a half-graben is formed on the hanging wall of the fault and a half-anticline is formed on the footwall because of the isostatic process. The multi-fault interaction model is that during the growth of faults, they overlap and interact with each other, and accommodation zones are formed in the overlapping segments. The accommodation zones are favorable targets for hydrocarbon exploration, and the trap characteristics are dependent on the extent of overlap and occurrence of faults. The multi-fault interaction model can be subdivided into three types: synthetic accommodation zone, convergent accommodation zone and divergent accommodation zone. Hydrocarbon migration and accumulation models of each type have been developed. The hydrocarbon migration and accumulation models of the traps with different genetic models have their own characteristics in the different stages of fault growth.

Analysing exploration uncertainties by tight integration of seismic and hydrocarbon migration modelling

High success rates in the exploration for oil and gas can be achieved by incorporating best practice strategies in estimating the geological uncertainties from seismic data and geological models. A tight coupling of the seismic information and hydrocarbon migration modelling may allow for a consistent handling of uncertainties throughout the analysis. Seismic uncertainties include velocities used for depth conversion, the positioning of structural interpretations including faults, and assigning flow properties from seismic attributes. The necessary output from the seismic uncertainty analysis could be provided as uncertainty fields that may be used as input to hydrocarbon migration modelling. The nonlinearity of the hydrocarbon migration process, including flow-path selection and trap phase filtering, frequently requires that local uncertainties are addressed in more detail. These uncertainties may require high-resolution seismic analyses in order to be further resolved. The structural interpretation is of particular importance to accumulation uncertainties, and fault juxtaposition and carrier dip direction uncertainty estimations can improve phase prediction estimates in exploration prospects. It is suggested that an improved best practice for exploration for oil and gas should include a tight coupling of the handling of uncertainties from seismic data in hydrocarbon migration modelling.

岩船沖油・ガス田のタービダイト砂岩への炭化水素移動・集積モデル

Hydrocarbon migration modeling through heterogeneous turbidite successions was carried out in the Iwafuneoki field, offshore Japan. The model, which uses 3D seismic data as an indicator of rock properties and employs the invasion percolation for simulation algorithm, enabled us to trace complicated migration pathways controlled by sand distribution patterns, sealing capacity of shale and hydrocarbon phase in pore spaces. It successfully predicted possible hydrocarbon distributions deductively, as well as reproducing known accumulations in much greater detail than conventional models do. It can therefore provide another practical measure to quantify the exploration risk of prospective locations, in addition to other inductive approaches like seismic attribute analyses.

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.