Article

An Experimental Study of Secondary Oil Migration

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Abstract

Experiments using long glass columns packed with glass beads or sand have been done to investigate secondary oil migration under hydrostatic conditions. Different combinations of bead sizes, oil densities, oil-water interfacial tensions, and column orientations have been tested. In some experiments, the oil was replaced by air. The observations included the oil migration pathway, the minimum oil column height needed for migration, and the rate of advance of the migration front. Migration was found to take place along restricted pathways and an imbibition front often formed at the bottom of the oil zone. The minimum oil zone height needed for migration can be predicted accurately if the values of the drainage and imbibition capillary pressures are known for the saturations at which the oil just becomes disconnected. In most experiments, the migration front advanced at a constant rate, which depended on the fluid properties, bead size, initial oil height, and pore structure. Migration rate is dependent on buoyant and capillary forces, but the dependence on capillary forces becomes weaker as the oil length increases. Column orientation also has been found to affect migration efficiency.

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... At the microscopic scale, the physical forces include buoyancy, capillary pressure and hydrodynamic forces, among which buoyancy and capillary pressure are the primary driving and restraining forces, respectively (Schowalter, 1979;England et al., 1987;Hindle, 1997). After expulsion, hydrocarbons will initially accumulate along the interface between reservoir and source rock, and will initiate secondary migration when hydrocarbon saturation is achieved and buoyancy exceeds capillary forces (Dembicki and Anderson, 1989;Schowalter, 1979;Illing, 1939;Catalan et al., 1992). ...
... In most cases, hydrocarbon migrates through confined pathways or conduits in porous and permeable carrier beds (Dembicki and Anderson, 1989;Catalan et al., 1992). Only 1%-10% parts of carrier beds serves as effective conduits for hydrocarbon migration (England et al., 1987). ...
... These migration pathways show sheet-like migrating petroleum fronts (Rhea et al., 1994), and they are commonly difficult to effectively predict (Hao et al., 2007). ''Driving-force'' where the structural morphology is the mainly controlling factor of the positions of hydrocarbon migration pathways (Gussow, 1954;Dembicki and Anderson, 1989;Catalan et al., 1992;Thomas and Clouse, 1995;Hindle, 1997Hindle, , 1999, and is believed to cause hydrocarbon migration pathways to act like restricted streams or rivers (Hindle, 1997(Hindle, , 1999Hao et al., 2007). For this reason, the migration pathways can be effectively predicted. ...
Article
An important exploration breakthrough has been achieved in the western subsag of the Bozhong subbasin, but the hydrocarbon accumulation mechanism was not clear. The hydrocarbon migration and accumulation mechanism of the western subsag of the Bozhong subbasin is discussed based on the modeling of hydrocarbon migration pathways and the study of late-stage reactivation of neotectonic faults. Three processes for lateral petroleum migration and accumulation can be recognized in the studied area: 1) migration and accumulation along the T8 unconformity; 2) migration and accumulation within the Guantao Formaiton (N1g); and 3) interaction of migration and accumulation along the T8 unconformity and Guantao Formation (N1g). The reactivation of faults in the studied area began 5.1 Ma. Following hydrocarbon lateral migration, late-stage reactivated neotectonic faults serve as effective vertical conduits for hydrocarbon migration and accumulation into the shallow Minghuazhen Formation (N1m) reservoirs. The modeling results of preferential petroleum migration pathways (PPMPs) and favorable accumulation areas are consistent with the actual exploration results. Two kinds of potential exploration targets can be predicted in the northwestern Bozhong subbasin: the first kind is hydrocarbon accumulation areas near or within generative kitchens (e.g. Target 1); the other kind is hydrocarbon accumulation areas removed from the generative kitchens, but with hydrocarbon sourcing from multiple generative kitchen and numerous PPMPs (e.g. Target 2). Studying preferential petroleum migration pathways will help reduce exploration risk.
... In the field, it is also very difficult to locate or identify any active migration pathway as well as the remaining structure left after the migration. Therefore, a laboratory experiment gives a unique means of observing real oil and gas migration processes in porous media and studying the transport mechanism (Schowalter, 1979;Dembicki and Anderson, 1989;Catalan et al., 1992). ...
... Because of the limitations of experimental model building and observation technique capability, it is difficult to design a proper 3-D model to simulate secondary migration processes. Most published experiments dealing with lateral migration were based on onedimensional or two-dimensional (2-D) models (Emmons, 1921;Lenormand et al., 1988;Catalan et al., 1992;Thomas and Clouse, 1995;Wagner et al., 1995Wagner et al., , 1997Meakin et al., 2000;Tokunaga et al., 2000;Zhang et al., 2003;Hou et al., 2004Hou et al., , 2005Luo et al., 2004;Løvoll et al., 2004Løvoll et al., , 2010Toussaint et al., 2005), which may not reflect the complexity of hydrocarbon lateral migration within the carrier-seal system. Therefore, the main objective in this study is to conduct a 3-D physical experiment using a relatively large box model that should be closer to reality than the previous experiments to investigate the characteristics of oil migration in a 3-D space. ...
... The scales separating these three fractal dimensions are determined from the observed separation in linear regimes of the crosses as W1 = 2.25 cm (0.9 in.) separating small and medium scales and W2 = 9.9 cm (3.9 in.) separating medium and large scales. These observed values are consistent with the predicted values of H and x, which are expected to separate scales where different types of forces are in competition, and different fractal dimensions. it can change from 1 and 10% (Schowalter, 1979;England et al., 1987;Dembicki and Anderson, 1989;Catalan et al., 1992), which makes the estimates of residual oil saturation from different researchers inconsistent (Schowalter, 1979;England et al., 1987;Dembicki and Anderson, 1989;Hirsch and Thompson, 1995) and makes accurate estimates of the losses occurring during secondary migration difficult. Carruthers and Ringrose (1998) pointed out that determining the oil-rock contact volumes is the basic work for accurate estimates of the losses occurring during secondary oil migration. ...
Article
Full-text available
A three-dimensional physical experiment was conducted to study secondary oil migration under an impermeable inclined cap. Light-colored oil was released continuously at a slow rate of about 0.1 mL/min from a point at the base of an initially water-saturated porous model. With buoyancy as a primary driving force, a vertical cylindrical shape of an oil migration pathway was observed first, and then a layer-shaped lateral migration pathway was observed beneath the top inclined sealing plate once the oil cluster had reached the top cap. Magnetic resonance imaging was used to observe the migration processes-for example, morphology of the migration pathway, intermittency of oil bubbles, and variation of oil saturation within the migration paths. Results show that the snap-off phenomenon (related to fast local imbibition processes) occurred more commonly during vertical migration than it did during lateral migration. The lateral migration pathway that parallels to the top inclined cap has a typical vertical thickness of 2 to 4 cm (0.8-1.6 in.) (i.e., roughly 40-80 pores). This thickness is consistent with the prediction derived from scaling laws related to pore size and Bond number. Along the lateral migration direction, the sectional area and the horizontal width of the migration pathway fluctuate significantly, although the average oil saturation along the pathway remains almost the same. After stopping the initial oil injection, the sectional area of the migration pathway shrinks significantly. Therefore, we believe that this significant shrinking of the migration pathway is the main reason why only a relatively small volume of oil and gas has been lost during secondary migration.
... Oil and gas commonly migrate along irregular pathways even in macroscopically homogeneous media (Schowalter, 1979;Dembicki and Anderson, 1989;Catalan et al., 1992;Hirsch and Thompson, 1995;Luo et al., 2004). The complex geometry of pathways is closely related to the heterogeneity of carriers at all scales (Luo, 2011;Luo et al., 2016). ...
... Physical experiments on migration have long been regarded as an important way to quantitatively understand the migration mechanism and processes (Emmons, 1924;Schowalter, 1979;Catalan et al., 1992;Luo et al., 2004). However, only local and simplified features of two-phase expulsions can be observed through the experiments (Lenormand et al., 1988;Dembicki and Anderson, 1989;Selle et al., 1993), in which only dynamic relationships among buoyancy and capillary pressures were considered (Thomas and Clouse, 1995;Luo et al., 2004;Vasseur et al., 2013). ...
... Secondary migration of petroleum plays an important role in petroliferous basins and is a practical problem in oil and gas exploration. Thanks to physical modellings (Dembicki and Anderson, 1989;Catalan et al., 1992;Thomas and Clouse, 1995;Zeng and Jin, 2003) and numerical simulations (Bethke, 1985, Bethke et al., 1991 we have grasped the mechanisms of secondary petroleum migration. ...
... Therefore, it is difficult to predict the petroleum migration pathways because of complex heterogeneity. However, others consider petroleum migration pathway as very restricted streams (Dembicki and Anderson, 1989;Hindle, 1989Hindle, , 1997Catalan et al., 1992;Thomas and Clouse, 1995), and structural morphology is the most important factor that controls the positions of petroleum migration pathways in sedimentary basins (Pratsch, 1983(Pratsch, , 1986(Pratsch, , 1994Hindle, 1997). They believe migration pathways can be predicted and migration pathway simulation can be a powerful tool to reduce exploration risk (Hindle, 1997(Hindle, , 1999). ...
... Despite the criticism drawn by the IP method due to its lack of time-dependence, advantages such as low computational demand and the ability to honor fine-scale heterogeneity are unquestioned. The modified invasion percolation (MIP) approach (Wilkinson and Willemsen, 1983;Frette et al., 1992;Glass and Yarrington, 1996;Meakin et al., 2000;Carruthers, 2003) is considered here for two fundamental reasons: 1) buoyancy-dominated flow conditions are relevant for the key problem of long term CO 2 migration, plume stabilization, and resulting saturation, similar to oil losses during migration (Catalan et al., 1992;Carruthers and Ringrose, 1998;Sylta et al., 1998;Luo et al., 2004;Luo et al., 2007;Vasseur et al., 2013;Luo et al., 2015); and 2) MIP methods allow a wide range of models to be considered efficiently in order to generate sufficient data for revealing fundamental characteristic trends and quantifying influencing factors (Meckel et al., 2015). ...
... Based upon laboratory observations through synthetic (Dembicki and Anderson, 1989;Catalan et al., 1992;Frette et al., 1992) and natural systems (Rasmussen, 1997) on capillarydominated immiscible fluid displacement, Chandler et al. (1982) and Wilkinson and Willemsen (1983) proposed invasion percolation, as opposed to the continuum approach based on Darcy's law, to better honor the mechanics of migration processes occurring under capillary equilibrium conditions. These authors observed that displacements such as secondary oil migration were controlled by the balance between forces exerted by buoyancy and capillarity, which is described by the Young-Laplace equation, relating the capillary pressure, P c , to the interfacial tension between fluids, , the contact angle, Â, and the meniscus curvature, R, which is proportional to the pore size:. ...
Article
During the post-injection and stabilization period of geological carbon sequestration, the primary forces governing CO2 migration and entrapment are capillarity and buoyancy, delineating a specific field of application for numerical flow models. In contrast with conventional modeling approaches that assume laminar viscous flow regime, a modified invasion percolation simulator is used to mimic the physics of fluid flow for vanishing pressure gradients. The current investigation extends a previous study simulating 2D CO2 invasion through stochastic and natural geologic models. Research presented here expands methods for addressing role of heterogeneity on fluid migration by quantifying the influence of 3D variability in threshold capillary pressure and bedform architecture on CO2 saturation. The goal is to develop a predictive method for volumetric storage capacity for buoyant flow conditions. Realistic sedimentary models are generated for eight common clastic facies with accurately represented bedform morphology. Resulting 3D models consist of matrix and lamina cells that are populated independently with probability density functions representative of sandstone lithologies with different grain sizes and sorting. Results from thousands of MIP simulations reveal saturation in the eight models to be a non-linear function that is primarily influenced by the contrast in threshold capillary pressures between matrix and lamina (observable lithologic heterogeneity), suggesting some predictive ability is achievable from common sedimentologic descriptors, although quantifying the independent effect of depositional architecture remains more difficult.
... Petroleum migration is a dynamic process in geologic history and is a difficult topic to assess in a petroleum system (Magoon and Dow, 1994;Magoon et al., 2005). Generally, buoyancy and capillary pressure are the driving and restraining forces for petroleum migration, respectively (Schowalter, 1979;England et al., 1987;Dembicki and Anderson, 1989;Catalan et al., 1992;England, 1994;Thomas and Clouse, 1995). Groundwater flow may act either as driving force or as restraining force with respect to their hydrodynamic properties. ...
... Petroleum migration acts as a sheet-like migrating petroleum front, and migration pathways are difficult to effectively predict (Rhea et al., 1994;Bekele et al., 2002). By contrast, petroleum migration pathways in macroscopic scale are mainly controlled by structural morphology (Gussow, 1968;Pratsch, 1986;Hindle, 1997;Hao et al., 2007;Xu et al., 2014), which have been defined by simulating experiments (Dembicki and Anderson, 1989;Catalan et al., 1992;Thomas and Clouse, 1995) and case studies in maturely explored basins (e.g. Hao et al., 2007Hao et al., , 2009). ...
... Secondary migration of petroleum plays an important role in petroliferous basins and is a practical problem in oil and gas exploration. Thanks to physical modellings (Dembicki and Anderson, 1989;Catalan et al., 1992;Thomas and Clouse, 1995;Zeng and Jin, 2003) and numerical simulations (Bethke, 1985, Bethke et al., 1991 we have grasped the mechanisms of secondary petroleum migration. ...
... Therefore, it is difficult to predict the petroleum migration pathways because of complex heterogeneity. However, others consider petroleum migration pathway as very restricted streams (Dembicki and Anderson, 1989;Hindle, 1989Hindle, , 1997Catalan et al., 1992;Thomas and Clouse, 1995), and structural morphology is the most important factor that controls the positions of petroleum migration pathways in sedimentary basins (Pratsch, 1983(Pratsch, , 1986(Pratsch, , 1994Hindle, 1997). They believe migration pathways can be predicted and migration pathway simulation can be a powerful tool to reduce exploration risk (Hindle, 1997(Hindle, , 1999. ...
Article
Full-text available
The origin of thirteen major oil fields in Zhu III sub-basin, Pearl River Mouth Basin, was studied by using the results of Rock-Eval pyrolysis on 340 samples and biomarker analysis on 18 source rock samples and 33 oil samples. The two possible source rock intervals have different biomarker assemblages and were deposited in different environments. The Eocene Wenchang Formation (E2w, 49.5-35 Ma) is characterized by high hopane/sterane ratio (>37.84), high 4-methyl sterane index (0.28-1.06), low gammacerane index (<0.09), low extended tricyclic terpane ratio [ETR=(C28 + C29)/(C28+C29 + Ts), 0.13-0.20] and bicadinane/C30 hopane (<0.02), which was deposited in fresh-brackish water and dominated by algae. On the contrary, Oligocene Eenping Formation (E3e, 35-30 Ma) has high gammacerane index (>0.10), high bicadinane/C30 hopane (up to 73.62) but low hopane/sterane ratio (<12.50), and it was deposited in relative saline water environment with significant high terrestrial plant debris input. Because of complex geologic settings, oils have different distribution. By using oil-source correlation analysis and hierarchical cluster analysis, two source-related oil groups were identified. Oils found in the Wenchang A depression and Yangjiang uplift, which are classified to oil group 1, were derived from E3e. Oils found in the Wenchang B depression and Shenhu uplift, which are classified to oil group 2, were derived from both E2w and E3e source rocks. But the Qionghai uplift received supply from both the Wenchang A and B depression. This distribution pattern is also proven by using a simple three-dimensional model called PathWay™. An explanation was put forward in this paper about the oils in Zhu III sub-basin and four potential petroleum accumulations were roughly predicted where no well drilled.
... The final step in calculating residual migration losses is to assign a residual oil saturation to the calculated pore volume of each carrier bed. Estimates of the amount of residual petroleum retained in a carrier bed range considerably, from Ͻ1 to 30% of the pore volume (Schowalter, 1979;Catalan et al., 1992;Hirsch and Thompson, 1995). For this article, a residual oil saturation of 7.4%, as determined experimentally by Catalan et al. (1992) for a tilted column, was used to determine the residual losses resulting from secondary migration. ...
... Estimates of the amount of residual petroleum retained in a carrier bed range considerably, from Ͻ1 to 30% of the pore volume (Schowalter, 1979;Catalan et al., 1992;Hirsch and Thompson, 1995). For this article, a residual oil saturation of 7.4%, as determined experimentally by Catalan et al. (1992) for a tilted column, was used to determine the residual losses resulting from secondary migration. Applying this percentage to the pore volume that experienced secondary migration in each carrier bed ( migration losses for each catchment. ...
Article
The New Albany-Chesterian petroleum system of the Illinois basin is a well-constrained system from which petroleum charges and losses were quantified through a material-balance assessment. This petroleum system has nearly 90,000 wells penetrating the Chesterian section, a single New Albany Shale source rock accounting for more than 99% of the produced oil, well-established stratigraphic and structural frameworks, and accessible source rock samples at various maturity levels. A hydrogen index (HI) map based on Rock-Eval analyses of source rock samples of New Albany Shale defines the pod of active source rock and extent of oil generation. Based on a buoyancy-drive model, the system was divided into seven secondary-migration catchments. Each catchment contains a part of the active pod of source rock from which it derives a petroleum charge, and this charge is confined to carrier beds and reservoirs within these catchments as accountable petroleum, petroleum losses, or undiscovered petroleum. A well-constrained catchment with no apparent erosional or leakage losses is used to determine an actual petroleum charge from accountable petroleum and residual migration losses. This actual petroleum charge is used to calibrate the other catchments in which erosional petroleum losses have occurred. Petroleum charges determined by laboratory pyrolysis are exaggerated relative to the actual petroleum charge. Rock-Eval charges are exaggerated by a factor of 4-14, and hydrouspyrolysis charges are exaggerated by a factor of 1.7. The actual petroleum charge provides a more meaningful material balance and more realistic estimates of petroleum losses and remaining undiscovered petroleum. The total petroleum charge determined for the New Albany-Chesterian system is 78 billion bbl, of which 11.4 billion bbl occur as a accountable in place petroleum, 9 billion bbl occur as residual migration losses, and 57.6 billion bbl occur as erosional losses. Of the erosional losses, 40 billion bbl were lost from two catchments that have highly faulted and extensively eroded sections. Anomalies in the relationship between erosional losses and degree of erosion suggest there is potential for undiscovered petroleum in one of the catchments. These results demonstrate that a material-balance assessment of migration catchments provides a useful means to evaluate and rank areas within a petroleum system. The article provides methodologies for obtaining more realistic petroleum charges and losses that can be applied to less data-rich petroleum systems.
... palaeo-uplifts and slope zones (Catalan et al., 1992), which are of great significance to the exploration in the Tarim Basin, Sichuan Basin, Ordos Basin, and other areas. The formation and development of large oil and gas fields in the world are mostly related to the background of paleo-uplifts, such as the North Sea Oil Field (United Kingdom), the Red Water Oil and Gas Field in Alberta Basin (Canada), the Oakola Gas Field in Permian Basin (United States), the East Texas Oil Field, the East Sichuan (China), the Kaijiang Gas Field, the Daqing Oilfield in Songliao Basin, etc. (Lorant et al., 2000;Fox et al., 2014;Pang et al., 2019;Bai, 2021;Yan et al., 2021). ...
... Experimentally derived lateral oil migration rates are quite rapid in a geologic context, indicating migration of as much as hundreds of kilometers in <1 m.y. (Dembicki and Anderson, 1989;Catalan et al., 1992;Sylta, 2002). If lateral migration dominated, such rapid migration velocity would in-dicate that for paleo-oils within single migration events (i.e., with similar maturities and same λ max populations), their charge timing along migration pathways should overlap; if vertical migration prevailed, modeling results suggest it would take additional hundreds of millions of years for in situ source rock in the north to reach similar maturity as that in the south (Fig. S4.1), thus the charge timing for paleo-oils with similar maturities should get younger toward the north. ...
Article
Full-text available
Tracing secondary oil migration pathways is critical for understanding petroleum system evolution histories. Traditional tools (e.g., molecular indicators and numerical modeling) utilized for evaluating oil migration processes either lead to ambiguous interpretations or only provide qualitative estimates. We quantitatively constrain secondary oil migration processes under an absolute time frame by integrating oil-inclusion fluorescence and in situ calcite U-Pb dating on calcite veins and cements hosting primary oil inclusions. Fluorescence spectra of oil inclusions and U-Pb ages were obtained on samples from ultra-deep Ordovician reservoirs along two major faults in the Halahatang oilfield, Tarim Basin (northwestern China). Absolute U-Pb ages suggest two main oil charge events during 475–433 Ma and 294–262 Ma, respectively, and revealed a northward-decreasing trend for oil maturity during single charge events. Vertical migration of oil from in situ source rock through active (or reactivated) faults is believed to be the key process inducing the spatial maturity variation in charged oils and considered as the main mechanism of secondary migration, with brecciated fault zones and dilatant fractures along faults acting as major vertical oil-migration pathways. The successful application of this approach has wider implications for elucidating petroleum migration processes in tectonic complex basins worldwide.
... This can be achieved using basin modelling consisting of an integrated framework of different phenomena, such as: rock deposition and compaction (Walderhaug et al., 2001;Lander and Walderhaug, 1999), multiphase flow during HC migration and accumulation Hantschel and Kauerauf, 2009;Clarke et al., 2006), as well as heat flow and phase composition analyses (Al-Hajeri et al., 2009;Walderhaug et al., 2001;Buntebarth and Schopper, 1998;Nabi and Al-Khoury, 2012b,a). One of the most sophisticated processes in basin modelling is petroleum migration, which is responsible for the HC accumulation inside the reservoir (Allan, 1989;Catalan et al., 1992;Thomas and Clouse, 1995;Hantschel et al., 2000;Schowalter, 1979;Karlsen and Skeie, 2006). Several factors complicate the numerical simulation of HC migration, including its uncertain nature and the extensive computing effort required (Wendebourg and Harbaugh, 1997;Sylta, 2002). ...
Article
One of the most sophisticated and significant stages of basin modelling is simulation of hydrocarbon (HC) migration. At this stage, the attempt is made to estimate the probability of HCs existence in the region of interest. This can be done by utilising readily available numerical reservoir simulation tools. Such tools are typically based on the Darcy flow model and are more frequently used for less time-consuming procedures. For instance, identification of the structural features of the formation and estimation of the production profiles. Despite all the advantages of this approach, there are some significant drawbacks including the extended computational time required to simulate the hydrodynamic process of HC migration. This issue cannot always be resolved by increasing computational power due to technological limitations. Thus, the authors suggest a method of the numerical scheme by splitting it along the coordinates (further called the NSS-method), allowing for a significant reduction in the computational time when modelling HC migration. Explicit and implicit numerical models are implemented and scrutinized for the purpose of this research. The validity of these models is verified by their comparison with the available analytical solutions and by analyzing the stability of these numerical schemes. As a result, the influence of the NSS-method on the accuracy of the calculation was insignificant, allowing a decrease in the computational time by several hundred times.
... in most published works, researchers could only observe oil migration pathways along the edges of the models [9,10]. With recent developments in science and technology, new technical methods have been used to observe the oil migration process, including migration pathways and oil saturation: (a) ultrasonic techniques [11], (b) magnetic resonance imaging (MRI; [12][13][14]), and (c) X-ray computed tomography (CT; [15][16][17][18]). ...
Article
Full-text available
Subsurface migration and accumulation of oil and gas have interested researchers for a long time, but these processes may occur over very long geological periods and are difficult to observe directly, so experimental simulations are warranted. In this study, an experimental method was developed to model hydrocarbon migration in the subsurface structure. Oil migration was simulated in a sandbox model, and industrial CT scanning was used to observe both the internal geometry of the model and the oil migration pathways. In the sandbox model, a NaI solution was used to simulate water, white oil was used to simulate hydrocarbon, and fine quartz sand, glass bead, silica powder, and brown corundum were chosen to represent brittle crust, based on suitable material parameters. A NaI-saturated layered sandbox model was constructed with an along-strike basal discontinuity, which during compression allowed a simple anticline with doubly verging reverse faults to form. Oil was then released continuously at a low rate from an orifice under one limb of the anticline. Initially, the oil migrated vertically through the fault zone until it reached the top of the fault zone; it then migrated laterally along the core of the anticline, saturating a model reservoir by buoyancy and capillary force. This experimental analog helps to explain hydrocarbon migration and accumulation within the Anjihai and Santai anticlines in northwest China.
... Many studies have indicated that buoyancy and residual pressure are the two main driving forces for subsurface hydrocarbon migration (Hubbert, 1953). Buoyancy is generated by the density disparity between the hydrocarbons and the formation water, which indicates that during the migration process for certain hydrocarbons against a stable structural background, the buoyancy is nearly constant (Cartwright et al., 2007;Catalan et al., 1992;Dembicki et al., 1989;Karlsen et al., 2006). However, according to the definition of the AGRP, as the variations in the differences of the residual pressure and the distances between source regions and reservoir regions, the residual pressure as a driving force could play different roles in the hydrocarbon migration process (Du et al., 2005;Eichhubl et al., 2000;England, 1987;Harding et al., 1989). ...
Article
Abnormal stratigraphic pressure is highly significant for hydrocarbon migration and accumulation for the exploration and exploitation of exploratory fields. However, the relationship between abnormal pressure and hydrocarbon migration processes is difficult to characterize quantitatively. In this paper, a new parameter, the attenuating gradient of residual pressure (AGRP), which is defined as the variation in residual stratigraphic pressure over a unit distance in a certain direction, is introduced to characterize hydrocarbon migration forced by residual pressure and hydrocarbon accumulation influenced by fault seals in the Huimin Depression, Bohai Bay Basin. The AGRP against the geological background can be calculated by the formation pressure of the source region by equivalent depth method using well log data (sonic travel time/velocity and resistivity) formation pressure of hydrocarbon reservoirs by drill stem tests of 32 exploration wells. For the Huimin Depression, the calculation results of the third member of the Paleogene Shahejie Formation (Es3) reservoir interval show that the northern tectonic uplift belt (NTUB) and parts of the central deep sag zone (CDSZ) and southern slope belt (SSB) are characterized by stepped distributions of high AGRP values ranging from 1.2 to 2.5 MPa/km with developed faults. The other parts of the Huimin Depression are characterized by continuously distributed low AGRP values from 0.5 to 1.0 MPa/km. The AGRP is effective for characterizing and evaluating hydrocarbon migration and accumulation in structural hydrocarbon traps with AGRP values higher than 1.0 MPa/km, which indicates that these reservoirs are dominated by residual pressure as the main driving force. For these traps, oil and gas tend to migrate to the high-AGRP areas, which indicates a large driving force by residual pressure. Furthermore, the stepped distribution of the AGRP suggests a well-sealed fault and hence good preservation conditions for hydrocarbon accumulation. This study shows that the AGRP can characterize hydrocarbon migration and accumulation more precisely and hence provide guidance for petroleum exploration and exploitation, especially in rift petroliferous basins with abnormal pressure and developed faults.
... This can be achieved using basin modelling, consisting of an integrated framework of different phenomena, such as rock deposition and compaction, multiphase flow during HC migration and accumulation, as well as heat flow and phase composition analyses (Al-Hajeri et al 2009). One of the crucial and most sophisticated processes in basin modelling is petroleum migration, which is responsible for the HC accumulation inside the reservoir (Allan 1989;Catalan et al 1992;Thomas and Clouse 1995;Hantschel et al 2000;Schowalter 1979;Karlsen and Skeie 2006). ...
Article
One of the most sophisticated and significant stages of basin modelling is hydrocarbon (HC) migration. In order to scrutinize this issue, it is expedient to utilize already available numerical reservoir simulation tools. Such tools are typically based on the Darcy flow model and are used to identify the structural features of the formation and estimate the production profile. Likewise, the migration of HCs can also be modelled allowing to clarify the possible location of HC deposits with higher accuracy. Despite all the advantages of this approach, there are some significant drawbacks, including long computational time required to simulate the hydrodynamic process of HC migration. This issue cannot always be resolved by increasing computational power due to its technological scarcity. Thus, the authors suggest using a method of the numerical scheme splitting along the coordinates (further called NSS-method), allowing to significantly reduce the computational time when modelling HC migration. Explicit and implicit numerical models are created and scrutinized for the purpose of this research. The validity of these models is verified by their comparison with the available analytical solutions and by analyzing the stability of numerical schemes. As a result, the influence of NSS-method on the calculation accuracy was insignificant, allowing to decrease the computational time and number of time steps approximately by three orders of magnitude and 300 times, respectively.
... However, the nature of petroleum migration pathway is still controversial. Some researchers [7][8][9][10][11][12][13][14][15][16][17][18][19][20][21][22][23][24][25][26] believed that the petroleum fluids migration is mainly driven by structural morphology, and modeling of petroleum fluids migration pathways can be a powerful tool to reduce exploration risk. Others [27][28][29][30][31] propose that petroleum fluids tend to pass through a high-permeable, thin sandstone bed than through a low-permeable and thick sandstone bed, controlled by the heterogeneity of the porosity and permeability of the carrier beds. ...
Article
Full-text available
The Eocene lacustrine sediments are the primary source rocks in the Huizhou Sag of the Pear River Mouth Basin. This study employs basin modeling for four representative wells and two profiles in the Huizhou Sag to reconstruct the process of generation, expulsion, migration, and accumulation of hydrocarbon fluids. The Eocene source rocks started to generate hydrocarbon at 33.9 Ma and are currently in a mid-mature and postmature stage. Hydrocarbons are mainly expelled from the Eocene Wenchang Fm, and the contribution of the Eocene Enping formation is minor. Under the driving forces of buoyancy and excess pressure, major hydrocarbons sourced from the Eocene source rocks firstly migrated laterally to the adjacent Eocene reservoirs during the postrift stage, then vertically via faults to Oligo-Miocene carrier beds, and finally laterally to the structural highs over a long distance during the Pliocene-Quaternary Neotectonic stage, which is controlled by both structural morphology and heterogeneity of carrier beds. Fault is the most important conduit for hydrocarbon fluid migration during the Neotectonic stage. Reactivation of previous faults and new-formed faults caused by the Dongsha Movement (9.8–4.4 Ma) served as vertical migration pathways after 10.0 Ma, which significantly influenced the timing of hydrocarbon accumulation in the postrift traps.
... Two-dimensional physical experiments have been widely used to investigate the hydrocarbon transport in conventional reservoirs (Dembicki Jr and Anderson, 1989;Catalan et al., 1992;Thomas and Clouse, 1995;Zeng and Jin, 2003). These physical models can provide both visualization of the flow patterns and distribution characteristics of water and gas. ...
... Limitations arise when applying the methods discussed above in tight reservoirs. Further investigation is needed due to the large variety of the patterns hydrocarbon migration (Catalan et al., 1992). In micro-and nano-scale pore and pore throat networks, a continuous oil column cannot be formed in a migration pathway because the capillary resistance is significantly larger than buoyancy, and that buoyancy has little effect on the migration (Weimer et al., 1986;Law and Spencer 1993;Yurewicz et al., 2008). ...
... The distributary channel sand and mouth-bar sand of the delta facies in the lower member are more likely to be sealed by large-scale nonreservoir depositional elements such as mud plug deposits. In addition, simulation experiments (Dembicki and Anderson 1989;Catalan et al. 1992;Thomas and Clouse 1995), migration modeling (Sylta 1991;Hindle 1997;Hantschel et al. 2000), and field observations in geological basins (Miles 1990;Terken and Frewin 2000;Terken et al. 2001) have all suggested that hydrocarbons move through only a small portion of the carrier rock during lateral migration (Hindle 1997). The hydrocarbons migrate through probably less than 10% of the cross-sectional area that contains high porosity and permeability (England et al. 1987). ...
Article
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. © 2016, National Research Council of Canada. All Rights reserved.
... Petroleum migrates via a series of pulses in the form of stringers (Berg, 1975) along focused and restricted pathways defined by the balance between driving (buoyancy) and dissipative (capillary) forces (Carruthers, 2003). Migration continues when all petroleum stringers are interconnected, for which a continuous supply of petroleum is required (England et al., 1987;Catalan et al., 1992). When no further petroleum is supplied into the migration pathways, migration ceases and some petroleum is left in the pore space. ...
Article
Oil and gas explorers routinely estimate the probability of success (PoS) of exploration projects, which is used for the calculation of risked prospective resources, their expected monetary value, ranking of the prospects and exploration portfolio management. Most often, the estimation of the geological PoS is based on subjective judgments about probabilities for individual geological risk factors. However, such subjective probabilities are not reliable in the low-validity environments with significant degrees of uncertainty and unpredictability, to which many exploration projects belong. When explorers assign probabilities for risk factors, they are geared by their variably incomplete knowledge and fragmentary experience, use judgmental heuristics under the influence of cognitive and motivational biases, and are prone to logical fallacies (unless they are aware of these limitations and account for them in scientifically responsible ways). As a result, assessments of geological PoS tend to be inconsistent across an exploration company, which leads to biased portfolios that fail to deliver on promise. Recent research and experience from other industries suggest that algorithms are superior to expert judgments in low-validity environments. This paper presents a review of relevant literature on the psychology of decision making and risk assessment methods used in petroleum exploration, and proposes a new algorithm for geological PoS assessment, realized in the form of systematic risk tables for probabilities of six geological risk factors (structure, presence of reservoir facies, reservoir deliverability, seal, source presence and maturity, and migration). The risk tables enable explorers to convert geological information into quantitative probabilities while counteracting the deficiencies of expert judgment and reducing the effects of biases. The risk tables take into account both the data-derived and model-derived positive, negative and neutral evidence for each of the risk factors, utilize the most elementary, fundamental and relevant subsurface information and can be used in a wide variety of exploration projects. The risk tables shift the focus of geological risk assessment from arguing about the probability values to a more objective and consistent evaluation of subsurface data and models. Probabilities are extracted from risk tables in a manner transparent to all involved, including peers, managers and investors. Implementation of the risk tables will allow explorers to dispassionately and consistently put high PoS values on relatively low-risk prospects and low PoS values on relatively high-risk prospects, and would enable managers to make well-informed drilling decisions. The use of risk tables will lead to less biased prospect inventories, effective portfolio management and better long-term exploration performance.
Chapter
This chapter reviews the theories, concepts, and practices that go into developing basin models to predict maturation, hydrocarbon generation, expulsion, and migration. Emphasis is placed on 1-D basin models that can be built, run, and interpreted by exploration geologists. The elements that go into building burial and temperature histories and how maturity and hydrocarbon generation and expulsion are discussed without delving into the details of the mathematics. Results from one-dimensional (1-D) models are reviewed, and some insight is given on how to use the main graphical data displays. Methods for validating models, exploring sensitivities to input parameters, and an approach to volumetric estimations are also examined.
Article
The piggyback thrust wedge is a common structural style in thrust belts, which controls the lateral arrangement of hydrocarbon distribution. This study conducted physical simulation experiments of structural deformation and hydrocarbon accumulation by using the piggyback thrust wedge as the geological model. According to the experimental results, hydrocarbon accumulation patterns were obtained by investigating the evolutionary history of the fault‐sealing performance while inverting the coupling relationship between the fault evolution and hydrocarbon accumulation. The structural deformation experiment showed that the evolution of the fault displacement and dip angle was characterized by gradual and staged progress. The kaolin smear continuity deteriorated with fault evolution. The soybean oil accumulation experiment demonstrated that the fault‐sealing performance in the rear of the thrust wedge was inferior to that in the front. Hydrocarbon migration was mostly lateral in the front of the thrust wedge and mainly vertical in the rear. Quantitative analysis showed that the fault‐sealing performance had three closed, partially closed, and open stages, which gradually deteriorated with the structural evolution. Three hydrocarbon accumulation patterns were identified in the piggyback thrust wedge: synchronized, adjustment, and non‐adjustment patterns. The evolution of the structural deformation and faults‐sealing performance resulted in spatio‐temporal differences in hydrocarbon accumulation in the thrust belts of central‐western China. The front of the thrust wedge had a higher exploration potential than the rear. The image is fault‐sealing evolution, which was evaluated by the structural deformation and hydrocarbon accumulation experiment. The soybean oil injection was performed at the last minute, but the injection can be performed in any fault‐sealing stage. So, the image theoretically inverts the coupling relationship between fault‐sealing capacity and hydrocarbon accumulation in time and space.
Article
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 (20S)/(20S + 20R), C29ββ/(αα + ββ), and C31 hopane 22R/C30 hoopane ratios, and C19/C21 tricyclic terpane ratio, C19/C21 tricyclic terpenes, C31 (22S)/(22S + 22R), and C29 (20S)/(20S + 20R) 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.
Article
Sandstone carrier transport property evaluations are of great significance for hydrocarbon migration and accumulation analysis, but quantitative characterization and case studies are insufficient. In this article, a new parameter, relative transport index (RTi), is defined to quantitatively evaluate the capability of a sandstone carrier to transport hydrocarbon. The example of the middle sub-member of the third member of Eocene Shahejie Formation (Es³2) in the southern slope of the Dongying Depression was first delineated into different sub-units based on the fourth-order sequence boundaries for a more detailed evaluation. The sandstone permeability was estimated by combining core-plug measurements with well logging to obtain more available data. The percolation characteristics of different models were analyzed to determine the total equivalent permeability of the carrier unit and were then combined with the inclination of the carrier to define and quantify RTi. This paper also characterized the hydrocarbon migration pathways and corresponding migration intensity based on the hydrocarbon occurrences and eventually revealed the relation between RTi and hydrocarbon migration and accumulation. The results show that the hydrocarbon migration pathways are mainly distributed in the regions with a relatively high RTi value. The continuous increase in RTi corresponds to the favorable direction of hydrocarbon migration, and the hydrocarbon migration can also occur in the direction in which RTi decreases slowly. The combination of all sub-units of hydrocarbon migration pathways formed three main migration directions (MMD) within the Es3² carrier unit. Moreover, the RTi value of the carrier unit is positively correlated with the corresponding hydrocarbon migration intensity, the strongest hydrocarbon migration occurred in the direction MMD2, and the hydrocarbon migration intensities that occurred in Es3²2, Es3²3, and Es3²4 sub-units are significantly stronger than those that occurred in other sub-units. The Wangjiagang Step-fault Zone (WSFZ) with continuous delta sandstone mainly acted as the lateral conduits for the long-distance hydrocarbon migration, and the disparity in migration intensities along the three MMDs resulted in different scales of hydrocarbon accumulation in Es³2 at the edge of the southern slope.
Article
The study of transtensional faults is significantly important for analysing migration and accumulation of hydrocarbons in petroliferous basins. The purpose of this study is to present disparities in the temporal and spatial evolution of two boundary transtensional faults (northern Linshang Fault and southern Xiakou Fault) in the Huimin Depression by 2D structural restoration and quantitative calculations of fault activity. This paper also reveals the controls of transtensional faults on the migration and accumulation of hydrocarbons by considering the stress normal to the fault plane (P), the shale gouge ratio (SGR) of the fault zone, and models of migration pathways. The results show that the transtensional systems within the Huimin Depression were generated from the reactivation of basement faults under an oblique extensional stress field. The Linshang Fault linked two initially separated segments and then behaved as a single fault since the Ek period, whereas the Xiakou Fault retained significant three-segment growth properties during the Paleogene. During the hydrocarbon charging period, the weak activity and strong vertical sealing restricted the occurrence of vertical migration around the Xiakou Fault, while the relatively strong movement and weak vertical sealing resulted in multilayer hydrocarbon accumulations around the Linshang Fault. Meanwhile, the vertically closed fault with high SGR (>0.6) acted as barriers and trapped hydrocarbons on the lateral migration pathways, whereas the vertically closed fault with low SGR (<0.6) served as conduits for further lateral migration into structurally higher positions. The discovered hydrocarbons are concentrated around transtensional fault systems, and the divergent E-W-striking brush-shaped secondary faults trapped abundant hydrocarbons within the hanging wall, demonstrating the important controls of the transtensional faults on the migration and accumulation of hydrocarbons in the Huimin Depression.
Article
The Qi-nan Slope belt is located in the southwestern Qikou Sag in the Bohai Bay Basin and has had relatively little oil and gas exploration. The mechanism of oil migration remains unclear due to the lack of understanding of the oil-oil relationship, the definition of oil migration pathways, and the controversy over the contributing source rocks. Based on hierarchical cluster analysis, the crude oils in the Qi-nan Slope are divided into three groups (A, B and C) with different geochemical compositions. Group A oils, including Class A1 and Class A2 biodegraded oils, and Group C oils are contributed by Es1x and Es3 source rocks with different organic facies, and distributions are limited to the WXZ oilfield in the western slope. Group B oils, including Class B1 and Class B2 biodegraded oils, mainly originated from Es1x source rocks and are widely distributed in the southern slope. The significant correlation between the relative migration distance (RMD) of oils and pyrrolic nitrogen compounds, rather than the parameters related to oil maturity, indicates that the pyrrolic nitrogen compounds can effectively trace oil migration directions in the Qi-nan Slope, and 1,8-DMC/2,6-DMC is the best indicator. For oil migration conduits, no large-scale faults developed in the inner part of the slope, and the oil-gas test results from major wells on the seismic profiles suggest that oils are mostly concentrated in Es1x with no obvious vertical migration in this area. Therefore, we speculate that the Es1x sand body provided the migration pathway for crude oil and controlled its uneven accumulation in the slope area. The isopleth map of the 1,8-DMC/2,6-DMC ratio, the distribution characteristics of the oil test results from major wells and the morphology of the Es1x transporting layer suggest that the overall migration direction of oil was dispersedly from the Qi-nan Sub-sag to the southern areas of the slope and that structural ridges provided preferential migration pathways for hydrocarbon accumulation.
Article
This study focused on vertical migration of petroleum in the Liuchu area, China. The physical properties of petroleum and changes in the geochemical characteristics of the study area were also investigated. Biomarkers such as, nitrogen compounds, n-alkanes, triterpenoids, steroids, hopanes, and cholestanes were analyzed in this regard. Petro-physical characteristics, such as, density, viscosity, concentrations of wax, resin, and sulfur of oil were studied. The rNa⁺/rCl⁻ ratio of Ed2 formation water ranged from 0.25 to 5.7, oil density of Ed2 formation ranged from 0.85 to 0.95 g/cm³, and oil resin concentration 10–50%, oil wax content in Ed2 formation ranged from 2 to 29% were lower than that of Es1. The rNa⁺/rCl⁻ ratio and mineralization of formation water data were examined to demonstrate the migration pathways. Geochemical and crude oil physical indexes were utilized to investigate the relationship between petroleum migration and seismic data. Cholestane αββ, ααα cholestane, diacholestane, steroid, and low ring terpenes in the formation were utilized to trace petroleum migration. Recent studies on petroleum maturity of have focused on comparison of source rocks and have reported that the maturity effects of source rock and reservoir oil are weak while those effects are high in the Liuchu aera. 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 (20S)/(20S + 20R) and C29 (ββ)/αα + ββ) ratios ranged from 0.2 to 0.35 Further, C31 (22S)/(22S + 22R), C32(22S)/(22S + 22R), and C29 (20S)/(20S + 20R) ratios ranged from 0.3 to 0.8, and 0.131 and 0.81, respectively. Petroleum migrated along migration channels. This suggested that vertical migration occurred after formation of the source rock fault and lateral migration occurred along the sandbody. Reservoir sandstone content, overlying mudstone content, and thickness of caprock are likely limited lateral petroleum migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The results of this study enabled optimization of uncertain petroleum migration pathways and improved the petroleum migration and accumulation model.
Article
Passive-margin deep-water fold-and-thrus belts (DWFTBs) have been the focus of a number of studies in recent decades because many oil and gas fields have been discovered in traps associated with them. Nevertheless, the impact of DWFTBs on petroleum plays remains unclear. In this study, we developed models for petroleum migration and accumulation in the offshore Rovuma Basin and Lamu Basin DWFTBs located along the passive continental margin of East Africa based on an integrated analysis of seismic, geochemical and geological data. Using available high-quality seismic data in the depth domain, we were able to quantify the evolution of thrust anticline growth by applying the area-depth-strain (ADS) method. Our results indicate that the offshore Lamu Basin DWFTB was active from the late Cretaceous period to the early Miocene period, while the offshore Rovuma Basin DWFTB has been active from the Oligocene period. Geochemical parameters and basin modeling show that widespread lower Jurassic mudstone is the dominant source of petroleum resources, with peaks of oil and gas generation in the Cretaceous and Cenozoic periods, respectively. Based on this, we suggest that the traps within the offshore Lamu Basin DWFTB contain oil generated from lower Jurassic sources that migrated along faults and accumulated during the late Cretaceous period and gas generated from the same sources during the Cenozoic period. Conversely, there is an insufficient amount of oil in the offshore Rovuma Basin DWFTB owing to the absence of oil migration pathways or traps as a result of the DWFTB's more recent formation from the Oligocene period.
Article
The physical mechanisms responsible for hydrocarbon migration in carrier beds are well understood. However, secondary migration is one of poorly understood facets in petroleum system. The Carboniferous Donghe sandstone reservoir in the Tarim Basin's Hudson oilfield is an example of a secondary (or unsteady) reservoir; that is, oil in this reservoir is in the process of remigration, making it a suitable geologic system for studying hydrocarbon remigration in carrier beds. Experimental methods including grains containing oil inclusions (GOI), quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) -- together with the results from drilling, logging and testing data -- were used to characterize the nature of oil remigration in the Donghe sandstone. The results show that (1) significant differences exist between paleo- and current-oil reservoirs in the Donghe sandstone, which implies that oil has remigrated a significant distance following primary accumulation; (2) due to tectonic inversion, oil remigration is slowly driven by buoyancy force, but the oil has not entered into the trap entirely because of the weak driving force. Oil scarcely enters into the interlayers, where the resistance is relatively large; (3) the oil-remigration pathway, located in the upper part of the Donghe sandstone, is planar in nature and oil moving along this pathway is primarily distributed in those areas of the sandstone having suitable properties. Residual oil is also present in the paleo-oil reservoirs, which results in their abnormal QGF-E. A better understanding of the characteristics of oil remigration in the Donghe sandstone in the Hudson oilfield can contribute to more effective oil exploration and development in the study area.
Article
Fractional wettability has been widely recognized in most of the oil reservoirs and it is a crucial factor that controls the fluid flow behaviour in porous medium. The overall effect of the proportion of oil-wet grains on the fluid flow properties has been well discussed. However, recent studies found that the random distribution and coordination of oil-wet and water-wet grains could make multi-phase flow behaviours extremely complicated in such media. The multiphase flow mechanisms in fractional wettability media remains unclear. In this study, oil imbibition experiments were systematically conducted using glass cylinders packed with fractional-wet glass beads. To study the effect of fractional wettability on multiple-phase flow properties, samples with different oil-wet grain proportions were prepared, and fifteen repeated experiments were conducted for each oil-wet proportion. The experimental results showed that oil imbibition was largely dependent on but not strictly a function of the proportion of oil-wet grains in the medium. The imbibition behaviours of samples with the same fractional proportion could vary significantly, as some samples exhibited complete oil migration, while others did not. This probabilistic phenomenon is likely due to the random distribution of oil-wet and water-wet grains. A pore throat may behave as oil-wet or water-wet depending on the relative proportion of oil-wet grains the pore throat contains. When the grains that comprise the pore throat are dominated by oil-wet grains, the throat behaves as oil-wet, and vice versa. Only when these oil-wet pore throats are connected to form a complete oil-wet pathway throughout the medium can the oil continuously imbibe into the medium. Therefore, the extent of oil imbibition depends on the completeness of the oil-wet pathway, which is controlled by the proportion of oil-wet grains in the medium. The higher the proportion of oil-wet grains in the medium, the larger the number of oil-wet pore throats that can form; thus, the higher the possibility that those oil-wet pore throats can connect to form continuous oil-wet pathways.
Chapter
This chapter reviews the theories, concepts, and practices that go into developing basin models to predict maturation, hydrocarbon generation, expulsion, and migration. Emphasis is placed on 1-D basin models that can be built, run, and interpreted by exploration geologists. The elements that go into building burial and temperature histories and how maturity and hydrocarbon generation and expulsion are discussed without delving into the details of the mathematics. Results from 1-D are reviewed, and some insight is given on how to use the main graphical data displays. Methods for validating models, exploring sensitivities to input parameters, and an approach to volumetric estimations are also examined.
Article
In the NW Songliao Basin, NE China, petroleum is produced from fluvio-deltaic sandstones in the Upper Cretaceous Yaojia Formation. Source rocks are dark-colored lacustrine shales of the Qinshankou Formation. In this paper, two models were developed to characterize the petroleum migration pathways in the lower member (Member 1) of the Yaojia Formation. In the first model, which applies to the northern region of the study area, petroleum migrates only in the lowermost carrier bed in Member 1 immediately above the area of the source kitchen, and later in multiple carrier beds outside this area. In the second model, which represents migration patterns in the central and southern regions of the study area, petroleum migrates in multiple carrier beds both within and outside the area of the source kitchen. Pressures in the Yaojia Formation were inferred to be hydrostatic while petroleum expulsion and migration took place. Therefore seven “migration-accumulation” (i.e., local palaeo-drainage) systems were defined according to the fluid potential gradients. Migration loss was found to vary markedly between migration-accumulation systems in the study area, and was controlled by factors including the shape, width and area of the effective source rocks, the thickness and distribution of carrier beds inside the source area, the migration distance outside the source area, and the number of carrier beds involved in petroleum migration. Using these two models, petroleum loss during secondary migration was estimated. The loss during secondary migration was approximately 5.21 billion bbl of petroleum, which is approximately 6% of the petroleum expelled into the first Member of the Yaojia Formation. Nearly 80% of the total migration loss occurred in all the carrier beds above the source area.
Chapter
The processes of petroleum migration are still under discussion and not very well understood. Reservoir engineering and production modeling, which are usually based on Darcy type separate phase flow and mass conservation, are successfully applied to model petroleum flow, at least in reservoirs (Peaceman, 1977; Aziz and Settari, 1979; Barenblatt et al., 1990; Dake, 2001) Engineering success and the persuasiveness of the approach justify a transfer of the methodology from reservoirs to petroleum systems and from timescales of years to millions of years.
Article
The former understanding about actual hydrocarbon migration paths is mainly based on the micro scale physical simulation or the computer simulation, and the actual oil and gas migration paths only rely on indirect evidence. This paper takes Puwei area of Dongpu depression as an example, firstly we find out the dominated migration pathways of main sandbodies and faults, then analyze their relationships with hydrocarbon kitchens and reservoirs to evaluate their effectiveness, and lastly identify the paths of hydrocarbon migration by combining the tracking of nitrogen compounds indicators. The results show that ridge like structures analysis combined with geochemical indicators tracking can identify actual hydrocarbon migration paths accurately. Ridge like structures of sandbody top and fault plane are the dominated migration pathways, their ability to become actual migration paths, as well as the amount of hydrocarbon carried depend on the oil and gas volume supplied by hydrocarbon kitchens. In Puwei area, oil and gas mainly migrated vertically along ridge like structures of fault plane, followed by lateral migration along ridge like structures of sandbody top in Puwei sag and Pucheng right wing slope. Nitrogen compounds indicators tracking shows that the majority of ridge like structures in this area are actual oil and gas migration paths.
Chapter
Secondary migration is the process by which hydrocarbons are transported from mature source rocks through water-saturated rocks, faults or fractures and become concentrated as trapped accumulations of oil and gas. The forces governing secondary migration of hydrocarbons are buoyancy and capillarity (Schowalter, 1979). Experimental data suggest that the secondary migration of oil in porous, permeable sediments takes place along restricted pathways or conduits (Dembicki and Anderson, 1989). These conduits are formed after the oil has penetrated far enough into the reservior rock for the bouyancy forces acting on the oil to overcome the capillary pressure in the pore throats. Long-range petroleum migration of the order of 100 km in the horizontal direction and about 2 km in the vertical direction is not uncommon (England et al., 1987).
Article
A laboratory method was designed to determine the oil/hydrocarbon residues. By using spectrometer and various other measurements the pore throat radius threshold of oil accumulation was gradually obtained in addition to using environmental scanning electron microscope. Results show that the pore throat radius threshold of sample from Jurassic sandstone oil reservoirs in Sichuan Basin is 44 nm and the lower limit of effective porosity is 1.4%, which effectively increases the reservoir resources statistics amount by about 29%.
Article
The controlling effect of fault dense belts on the preferred direction of oil-gas migration is discussed and favorable parts of fault dense belts for oil accumulation inside and outside oil source area are discussed based on the characteristics of fault dense belts of Fuyang Formation in Sanzhao Depression, combining with the oil and gas distribution of in Fuyang Formation of study area in this paper. The results show that there are four types of fault dense belts in Fuyang Formation of Sanzhao Depression, namely antithetic-graben-antithetic fault terrace, horst-graben-antithetic fault terrace, antithetic-graben-consequent fault terrace, and horst-graben-consequent fault terrace. The strike of fault dense belt is the preferred direction of oil-gas migration and horsts and antithetic inside oil source area of fault dense belts are favorable parts for oil accumulation where the strikes of fault dense belt and the layer are parallel or small-angle intersection. Inside oil source area horst and antithetic of fault dense belts are favorable parts for oil accumulation. And horsts and antithetic outside oil source area are favorable parts for oil accumulation and the grabens are secondary favorable ones where the angle of the strikes of fault dense belt and layer ranges from 0 to 45 degrees. The antithetic and horsts are preferential for oil accumulation where the angle ranges from 45 to 90 degrees.
Article
The article analyses the overburden pressure impact on rock porosity and permeability by measuring permeability changes of different grain size samples under different overburden pressure, the gas saturation of tight sandstone reservoir by measuring gas saturation of different grain size samples under critical injection pressure, the relationship between porosity and gas saturation in tight sandstone reservoir by measuring Kuqa foreland basin of deep tight sandstone core porosity and permeability parameters. Experiments show that there is a positive correlation between the reservoir permeability and rock grain size, that is, the smaller rock grain size, the lower reservoir permeability, and there is a negative correlation between overburden pressure and reservoir permeability, that is, the greater overburden pressure, the smaller reservoir permeability (but the overburden pressure has little effect on reservoir permeability, when it increases to a certain extent), and there is a negative correlation between reservoir gas saturation and reservoir grain size and permeability, that is, the smaller the grain size and lower reservoir permeability, the higher gas saturation. And according to the results of physical simulation, we propose two conceptions which are permeability class change and permeability differential of tight sandstone. Lastly, it concludes that reservoir inhomogeneity and reservoir permeability differential of tight sandstone reservoir are the main controlling factors on reservoir gas saturation, that is, the better reservoir homogeneity, the higher reservoir gas saturation, and the smaller permeability differential, the higher reservoir gas saturation.
Article
Fuyu oil layer in Xingbei Region of Daqing placanticline is a typical example of hydrocarbon migration and accumulation outside of source area, identifying the accumulation rule can refer to the regional hydrocarbon exploration services and the deployment of a similar study domestic and foreign. A comprehensive analysis of petroleum sources, tectonic character and matching relation between faultsand body was made. And physical properties data of in-place oil in high pressure and sidewall coring data were used as migtation "tracers". The results show that hydrocarbon resource is Mermber 1 of Qingshankou Group in southern Qijiagulong Depression and high value area sof hydrocarbon generation and expulsion located in northwest and southwest to study area respectively. The three kinds of advantage migration channels respectively are fault-lithological transporting ridge in northwest slope zone, anticline-lithological transporting ridges in central anticline axial region and lithological transporting ridges in southwest slope zone. Among them, the most advantage migration channels are anticline-lithological transporting ridges in central anticline axial region. Oil and gas mainly migrate around anticline axial region and western steep slope belt, but not in eastern gentle slope belt, with the restriction of transporting ridges. Oil and gas reservoirs are formed mainly along transporting ridges. Main enrichment sites are local structural highs in anticline axial region and the footwall area of antithetic fault in southwest slope zone. ©, 2014, Central South University of Technology. All right reserved.
Article
In order to evaluate and recognize the steep slope zone which have had significant exploration discovery and the exploration potential of Qinnan area. Combining qualitative appraisement and quantitative description method, the data of composition and carbon isotope of natural gas, analysis of oil-source correlation of oil associated with natural gas and numerical simulation of hydrocarbon migration are used to systematically study the gas genetic type and its hydrocarbon exploration potential in this area. The results show that: the natural gas in uplift is Neogene dissolved gas and mainly dry gas, and in steep slope is Paleogene condensate gas and mainly wet gas. The natural gas in steep slope is mainly oil-type gas, the data of carbon isotopic shows reversal, and the biomarker indicates the oil associated with natural gas is mixed oil source from the source rocks of E 2s 3 and E 3s 1. And the numerical simulation of hydrocarbon migration shows that only the "active" source rocks in step-fault zone make contribution for the oil-gas field. Non-hydrocarbon gas is CO 2, mantle-derived inorganic gas. Qinnan sag is a "little but fertile" hydrocarbon-generation sag. Source rocks of E 2s 3 and E 3s 1 are good, and those of E 3d L are moderate to good. Qinnan area hydrocarbon mainly comes from Shahejie source rocks(E 2s 3 and E 3s 1). Simulation of hydrocarbon dominant migration and source rocks evaluation show that the steep slope, western slope, Shijiutuo salient gentle slope and south end of Liaoxi low uplift are favorable exploration areas.
Article
Based on the analyses of petroleum systems in the Chaluhe sag, hydrocarbon secondary migration in thesource-reservoir assemblage (E2s-E2s) was evaluated by using 2D basin modeling technique. This study aims to investigate the individual hydrocarbon migration-accumulation units, analyze different conditions for the hydrocarbon accumulation, and locate possible favorable areas as exploration targets. The following conclusions are drawn: (1) Key geologic elements of the petroleum systems are well integrated in the Chaluhe, three events of hydrocarbon accumulation can be identified, and the E2s-E2s (!) is recognized as the most significant petroleum system in the study area. (2) Secondary migration direction and intensity were mainly controlled by the fluid potential energy field. Hydrocarbon accumulation during the main period of hydrocarbon migration was characterized by wide distribution and high density. Hydrocarbon fluids mainly charged two areas with lower fluid potential, namely along the northwest basin-marginal fault and the eastern Wanchang Liangjia uplifts, respectively. (3) The Chaluhe sag consists off our hydrocarbon migration-accumulation units, including units I, II, III, and IV. Unit II has the best potential for hydrocarbon migration and accumulation, followed by unit I. The periclinal area in the Wanchang uplift ranks to be the most favorable area for oil and gas exploration in the Chaluhe sag.
Article
Most large-scale flow and transport simulations for geologic carbon sequestration (GCS) applications are carried out using simulators that solve flow equations arising from Darcy's law. Recently, the computational advantages of invasion-percolation (IP) modeling approaches have been presented. We show that both the Darcy's-law- and the gravity-capillary balance solved by IP approaches can be derived from the same multiphase continuum momentum equation. More specifically, Darcy's law arises from assuming creeping flow with no viscous momentum transfer to stationary solid grains, while it is assumed in the IP approach that gravity and capillarity are the dominant driving forces in a quasi-static two-phase (or more) system. There is a long history of use of Darcy's law for large-scale GCS simulation. However, simulations based on Darcy's law commonly include significant numerical dispersion as users employ large grid blocks to keep run times practical. In contrast, the computational simplicity of IP approaches allows large-scale models to honor fine-scale hydrostratigraphic details of the storage formation which makes these IP models suitable for analyzing the impact of small-scale heterogeneities on flow. However, the lack of time-dependence in the IP models is a significant disadvantage, while the ability of Darcy's law to simulate a range of flows from single-phase- and pressure-gradient-driven flows to buoyant multiphase gravity-capillary flow is a significant advantage. We believe on balance that Darcy's law simulations should be the preferred approach to large-scale GCS simulations. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd.
Article
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.
Article
The cratonic region of the Tarim Basin contains two main Lower Paleozoic source rocks-the Middle-Upper Ordovician and Lower-Middle Cambrian. However, few research focus on the relation between the evolution of hydrocarbon kitchens and its role in controlling oil and gas. Based on previous research results, this paper applies geochemical parameters of rock pyrolysis, hydrocarbon expulsion threshold theory and hydrocarbon-generated potential methods to identify the effectiveness of source rocks from the Lower Paleozoic while quantitatively calculating the hydrocarbon expulsion intensities and amounts for the two sets of source rocks. The above result is used to analysis the distribution of the effective hydrocarbon kitchen in each primary history stage and the controls on oil and gas. This study shows multiple phases of oil and gas generation and expulsion from the Cambrian-Ordovician source rocks with four oil-generating peaks with large-scale oil migration and accumulation. According to the changes in hydrocarbon expulsion intensity within different stages, we can elucidate the evolution of the source kitchens, because the hydrocarbon kitchens from the two sets of source rocks migrated in time and space, and there are multiple hydrocarbon expulsion centers. Based on the concept of the oil/gas threshold distribution model, the relation between the quantitative characterization of the hydrocarbon kitchen controlling function, and quantitative prediction of reservoir formation probability is studied, and the result shows that oil and gas reservoirs are located in more than 50% probability of controlling area. However, different periods and different layers of stacked hydrocarbon kitchen is complex and causing the main mixing of oil and gas. All these hydrocarbon expulsion centers had control over the distribution of oil and gas in the basin. From a macro and quantitative point of view, this discovery will provide certain guide for oil and gas exploration.
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There are low porosity and permeability in the Jurassic sandstone in the Yongjin Block, Junggar Basin. Reservoir is main controlled element of petroleum accumulation. It is adverse to hydrocarbon pool. However, unconformity effectively promotes the porosity and permeability of sandstone under it. An important unconformity between Jurassic and Cretaceous Periods developed in the central Junggar Basin. The chemical index of alteration (CIA) values indicate that it experienced physical weathering during development, transported the matrix off the semi-weathering rock, and consequently improved the reservoir quality of sandstone. Water with organic acids that are generated during organic matter maturation could dissolve the feldspar in semi-weathered zone, and would remove the dissolved products from the sandstone. All these would further improve reservoir quality. There are tight sandstone of the Jurassic which is adverse to hydrocarbon accumulation. However, because unconformtiy ocured and experienced the reservoir-improved geologic progresses. The semi-weathered zone of J/K unconformity became the preferred pathway for petroleum migration due to these two geological processes. The Paleo-soil layer on top of the J/K unconformity formed a good trap for the passing hydrocarbons, and accumulated it to become a commercial petroleum pool.
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It is well known that the hydrodynamic behaviour of faults may be rather different from that of their surrounding beds. These characteristics may not be constant through time for a single fault and especially change during rupture events. Various numerical tests were performed using the TEMISPACK software to calculate the quantity of hydrocarbons that can migrate through damaged zones with high permeability in and near to a fault. The paper examines the influence on fluid flow of (1) the thickness of the fault zone, (2) the connectivity between fault and carrier beds, and (3) the opening time when permeability increases sporadically. The results confirm the importance of fault zones on hydrocarbon migration. Even when very narrow (2 meters), temporarily open (< 100 000 years), and moderately permeable (<10 mD), faults focus the migration of hydrocarbons. The flow is stronger in narrow, temporary faults but the quantities in circulation remain essentially the same. The nodes of the migration paths are the connections between faults and carrier beds (and/or source rock). This connection has a greater influence on the quantity of migrating hydrocarbons than does the intrinsic permeability of the fault. Given major hydrocarbon losses in the rock's porosity, thick drains are less efficient than are narrow zones for bringing the hydrocarbons to the reservoirs.
Article
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 invasionpercolation 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 heterogeneousmedia. Inmacroscopically 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.
Chapter
Movement of petroleum from the source via carrier bed to the reservoir rocks is called migration. This is divided into primary migration, defined as the movement of oil and gas through and out of the fine-grained source rocks, and secondary migration, the movement through wider pores in carrier and reservoir rocks to the trap. (Not discussed here are the aspects of petroleum entrapment, redistribution in traps and petroleum loss from traps — generally called “dismigration” — or the various types of traps.) In addition to petroleum generation, petroleum migration is the principal process in the formation of explorable petroleum accumulations (which, however, represent only a special case of petroleum migration in which an otherwise diffuse fluid flow field is highly focussed towards a reservoir structure).
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Numerical simulation of careful parallel arithmetic of oil resources migration-accumulation of Tanhai Region (three-layer) was done. Careful parallel operator splitting-up implicit iterative scheme, parallel arithmetic program, parallel arithmetic information and alternating-direction mesh subdivision were put forward. Parallel arithmetic and analysis of different CPU combinations were done. This numerical simulation test and the actual conditions are basically coincident. The convergence estimation of the model problem has successfully solved the difficult problem in the fields of permeation fluid mechanics, computational mathematics and petroleum geology.
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The program Migrate2 models the formation, migration and accumulation of hydrocarbons through time in a three-dimensional (3-D) model of part of a sedimentary basin. The program is written in Visual C++ for the Win32 environment, and allows visualisation of both the input data for the model during the model construction phase, and the results through all of the time steps in the model. Program input consists of 3-D interpretations of seismic data, together with physical data such as porosity and permeability, and geochemical data, which is used to predict hydrocarbon formation. Output consists of a series of 3-D models of the volume of rock through time, which can be freely scaled and viewed from any angle, and coloured to represent a variety of parameters. This program is a preliminary stage for the full predictive modelling of hydrocarbon accumulation evolution.
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