This study integrates field observations with seismic and well data, including structural, sedimentological and palaeontological interpretations and geochemical analyses, to characterize the petroleum system elements of Central-East Iran. The sedimentary record of this province reflects a complex tectonic evolution, spanning from Gondwanan stability through Neo-Tethyan rifting and Cimmerian orogenesis, to Cenozoic intra-arc and intermountain basin development driven by Neo-Tethyan subduction and the Arabian–Eurasian collision. The only proven petroleum system is Cenozoic, sourced from and trapped within the Oligocene–Miocene Qom Formation. Hydrocarbons are generated from organic-rich mudstones in the Qom Formation c- and e-members. Fractured shallow-marine limestones in the Qom Formation e-Member are the main reservoirs sealed by evaporites in the uppermost Qom Formation or base of the Upper Red Formation. Despite discoveries such as Alborz and Sarajeh, exploration has not been commercial due to discontinuous source rocks, poor seals and structural complexity during the late Neogene. The Paleozoic–Mesozoic successions host key components of the petroleum system, including source rocks such as the Upper Devonian–Lower Carboniferous Shishtu Formation and the Lower–Middle Jurassic Shemshak Group, along with reservoir carbonates of the Middle Permian Jamal Formation. Hydrocarbon generation is likely to have occurred prior to the Cenozoic, resulting in a temporal mismatch with the formation of structural traps.
The Bozhong Sag, a hydrocarbon-rich depression in the Bohai Bay Basin, contains multiple sets of source rocks with similar environment of deposition, posing challenges for oil-source correlation. This study optimizes a neural network approach to address the nonlinear relationships between biomarker parameters and hydrocarbon origins. Using 28 biomarker parameters from 43 source rock samples, we built conventional discriminant analysis and neural network models. The neural network achieved 95% accuracy in distinguishing three source rock groups, outperforming the discriminant method (79%). Due to the higher accuracy the neural network method was extended to investigate oil-source correlation for 17 crude oil samples from oilfield A. Results reveal that oils above 3600 m mainly originate from Es 1 Member, while deeper oils derive from Es 3 Member, which is consistent with established charging histories (5-6 Ma for deeper reservoirs, ∼2.5 Ma to present for shallower ones). Generally, this study presents a novel oil-source correlation technique that combines traditional biomarker parameters with machine learning, enabling a significant improvement in classification accuracy. This approach is not only pivotal for hydrocarbon exploration and exploitation in the Bohai Bay Basin but also establishes a widely applicable methodology for oil–source correlation in other complex basins worldwide.
In 2020, a novel unconventional reservoir exhibiting coexisting oil and gas was discovered within the Leikoupo Formation in the central Sichuan Basin. Characterized by extra-low porosity and low permeability, the genesis of the reservoir pores has not been systematically investigated. This study integrates petrography, XRD, rock pyrolysis, biomarkers, fluorescence microscopy, gas adsorption and CT scanning to elucidate the characteristics of this reservoir and decipher the relationship between reservoir formation and the original sediments. Experimental results indicate that the reservoir space is largely controlled by the primary mineral framework and hydrocarbon generation overpressure, developing clay intergranular pores, organic matter pores and lamination fractures. Mutual adsorption between clay and organic matter facilitates organic matter preservation to a certain extent. However, their heterogeneous distributions contribute to reservoir heterogeneity and induce multi-point hydrocarbon generation. The findings underscore the critical roles of sedimentary differentiation, organic–inorganic interactions and internal hydrocarbon generation dynamics within a closed system in the formation of this unconventional shale reservoir in the Leikoupo Formation. They further emphasize the sedimentologically constrained evolutionary characteristics of the shale reservoir. This study delivers sweet-spot evaluation insights and a conceptual framework for unconventional petroleum research.
Tight sandstone reservoirs commonly develop multiscale pore-throat systems, and differences in pore-throat structure influence movable fluid occurrence and seepage capacity. In this study, the Chang-6 3 tight sandstone reservoir within the Chang-6 interval in the Huaqing area, Ordos Basin, was investigated using casting thin sections, scanning electron microscopy, X-ray diffraction, high-pressure mercury intrusion porosimetry, nuclear magnetic resonance, and multiscale fractal analysis to clarify pore-throat structure and its control on movable fluid occurrence. The results show that reservoir space is dominated by residual intergranular pores, dissolution pores, and intercrystalline pores, with pore-throat sizes mainly concentrated between 0.04 and 0.18 μ m. Movable fluid saturation ranges from 20.98% to 55.90%, averaging 35.23%, and decreases from type II to type IV reservoirs. NMR pore partitioning based on the T₂ cutoff shows that movable fluids are mainly hosted in mesopores, contributing 34.75%-76.28%; micropores mainly control bound fluid occurrence, whereas macropores contribute limited movable fluids where connectivity is poor. NMR and HPMI fractal results indicate that mesopore- and macropore-related fractal dimensions generally fall within the effective fractal range, whereas micropore-related dimensions deviate from the conventional range. SEM box-counting results show that poorer-quality reservoirs have more complex pore boundaries. Sensitivity analyses of SEM thresholds, NMR pore partitioning based on the T 2cutoff , and HPMI segmentation boundaries confirm that the main mesopore- and macropore-related interpretations remain stable. These findings identify mesopores as the dominant pore-throat scale controlling movable fluid storage and seepage, providing multiscale fractal evidence for evaluating movable fluid occurrence and reservoir quality in tight sandstones.
Natural gas hydrates, as a promising clean energy resource with abundant reserves, face critical challenges in commercial exploitation due to thermo-hydro-mechanical (THM) coupling effects and formation stability concerns. This paper reviews recent advances in multiscale investigations of hydrate-bearing sediments, focusing on their mechanical responses and fluid flow behavior within porous media. Key challenges include: maintaining the integrity of core samples during recovery; limitations in pore-scale imaging and simulation caused by sample accessibility and computational constraints; complex fluid flow mechanisms in clay-rich and silty layers; and uncertainties associated with boundary conditions and phase change simplifications in coupled THM simulations. To address these issues, a multiscale research framework is recommended—integrating high-resolution imaging with molecular dynamics simulations, standardizing high-pressure in-situ core sampling and permeability testing procedures, and exploring reservoir–wellbore interaction and failure mechanisms. Future research should prioritize breakthroughs in microstructural characterization, scale-bridging constitutive modeling, and multiphysics coupling techniques to support the safe and efficient development of gas hydrate resources.
Fault seal analysis tries to predict the length of hydrocarbon column that a fault can trap before capillary leakage occurs. Several tools and empirical relationships have been developed in the petroleum industry to aid this exercise. These assess cross-fault juxtapositions and allow an estimation of the fault gouge permeability and its potential seal capacity. This seal capacity is often based on the inferred clay content of the fault zone as this tends to correlate with capillary seal properties of a fault gouge. A plethora of parameters can affect a fault seal evaluation from the quality of seismic imaging and trap mapping through to the fault deformation mechanisms, and the distribution and properties of the resultant fault gouge that help provide the membrane seal. A review of some methods that may help frame the uncertainty in seal prediction is offered via a worked example. Stochastic modelling can help illustrate the impact that key parameters such as the stratigraphic template, Vshale estimate, fault throw and published algorithms may impose on the seal calculation. Predicted fault seal capacity tends to have a negatively skewed distribution and should be quoted as a range. It is recommended that the mode be quoted as the expected value.
Located within the Subei Basin, the Gaoyou Sag is abundant in hydrocarbon resources and exhibits significant potential for shale oil exploration and development. However, the organic matter enrichment patterns and palaeoenvironmental evolution of the second member of the Funing Formation (E(1)f(2)) in the Huazhuang area remain poorly understood, particularly regarding the complex origins of organic matter and their coupling with sedimentary environments. To address these issues, representative shale and crude oil samples from the E(1)f(2) interval were systematically analysed using gas chromatography-mass spectrometry, X-ray diffraction and inductively coupled plasma mass spectrometry. The results show that the average pristane/phytane (Pr/Ph) ratio is 0.58, the V/Cr ratio is close to 1 and the average V/(V + Ni) ratio is approximately 0.7. The Sr/Cu ratio is significantly greater than 10 in the lower section but markedly less than 10 in the upper section. The Sr/Ba ratio ranges from 0.06 to 1.23, progressively decreasing from bottom to top. A comprehensive analysis indicates that the lower E(1)f(2) was deposited in a saline lacustrine anoxic environment, while the upper E(1)f(2) transitioned to brackish-water conditions under a warm and humid climate. Based on the distribution of the C-27-C-29 steranes, the organic matter is determined to have been mainly derived from a mixture of lower aquatic organisms and terrestrial higher plants. The warm-humid climate, decreasing water salinity and bottom-water anoxia jointly promoted the enrichment and preservation of organic matter. This study establishes an organic matter enrichment model co-controlled by palaeoclimate and palaeosalinity, providing a theoretical basis for shale oil exploration in similar lacustrine basins.
The Late Triassic to Early Jurassic Minjur Formation is an unconformity-bound, transgressive-regressive sequence composed of channelized fluvial sandbodies and coastal floodplain/playa mudrocks deposited along the northern margin of Gondwana. A comprehensive sedimentological, sequence stratigraphic and seismic geomorphological analysis of the Minjur Formation in Abu Dhabi has significantly enhanced our understanding of its depositional environments, the controls on reservoir distribution and its overall exploration potential.Reservoir distribution within the Minjur Formation has been interpreted through an integrated approach involving seismic geomorphology, core and wireline log analysis and regional stratigraphic correlations. In the southwestern onshore region of Abu Dhabi, sinuous, potentially marine-influenced axial channel networks indicate persistent sediment transport towards the Neo-Tethys Ocean to the north. Conversely, the eastern onshore region exhibits a broader drainage system composed of smaller, northeastward-flowing isolated and branching channels. These channels tend to narrow downstream, suggesting more intermittent flows that probably terminated inland within floodplain or playa settings.The deposition of the Minjur Formation was probably influenced by a combination of tectonic activity, localized halokinesis, eustatic sea-level changes and climatic variability. From an exploration perspective, the pronounced lithological contrast between the channelized sandbodies and surrounding floodplain mudrocks, along with the presence of bounding unconformities and syndepositional halokinesis, offers substantial potential for stratigraphic trapping throughout the region.
Significant progress has been achieved in Paleogene hydrocarbon exploration in the Pinghu Slope Belt of the Xihu Depression, but the mechanisms by which fault-cap rock configurations control differential accumulation remain unclear. Using 3D seismic interpretation, geochemical data, fault activity analysis and fluid-inclusion geochronology, this study investigates the multistage evolution of the Pinghu Fault (F1) and its coupling with cap-rock development in governing hydrocarbon migration. The results indicate that the Pinghu Slope Belt has excellent source-rock conditions, and the geochemical characteristics of the oil and gas suggest that the hydrocarbon accumulation is characterized by near-source hydrocarbon charging. F1 evolved from multiple isolated segments into a unified fault plane through lateral and dip linkage, followed by late-stage segmented reactivation. Source rocks reached peak hydrocarbon generation by the end of the Miocene, with two key charging events at c. 15 Ma (local) and c. 5 Ma (regional). Pre-Late Miocene dip linkage and subsequent reactivation provided critical vertical migration pathways during the peak generation. Although thick mudstone cap rocks occur in the Pinghu Formation, faulting has disrupted their continuity. Analysis of fault-cap rock configurations shows that seal integrity is lost when the residual thickness falls below 63.6 m, while fault throws under 100 m reduce the accumulation potential near faults. Under a multiphase tectonic background, the coupled fault-cap rock sealing capacity plays a critical role in hydrocarbon migration and vertical distribution. This provides important insights for predicting exploration targets in faulted basins.
This study investigated the geochemical characteristics of the Upper Cretaceous source rocks in northern Jordan, including the quantity and quality of organic matter, the depositional environment and the thermal maturity. Several methods were applied, encompassing maceral examination and multi-geochemical analyses such as total organic carbon (TOC), Rock-Eval pyrolysis, pyrolysis-gas chromatography (PY-GC), liquid and gas chromatography (GC) and 1D basin modelling. Results demonstrated that the Cenomanian Naur-Shueib strata are non-source rocks, while the Turonian-Maastrichtian strata (Wadi Essir-Ghareb formations) are mainly good to excellent source rocks. The hydrogen index (HI) results suggest that the Cenomanian strata have mainly mixed kerogen Type II-III, and minor kerogen Type III, whereas the Turonian-Maastrichtian source rocks are dominantely contributed by kerogen Types II and I. These findings match the maceral examinations, showing a dominance of vitrinite macerals in the Cenomanian beds, and amorphous organic matter (AOM) in the Turonian-Maastrichtian strata. The PY-GC and gross composition suggest that the Upper Cretaceous strata may have produced paraffinic oil with a high content of wax, and displayed a predominance of naphthenic oils, with a less significant presence of aromatic naphthenic oils and aromatic asphaltic oils. The Pr/Ph, Pr/n-C-17 and Ph/n-C-18 ratios, along with the low gas/oil ratios (GORs), suggest that the Upper Cretaceous formations predominantly comprise oil-prone kerogen derived from marine organic matter (algae/bacteria) and deposited under strongly reducing conditions. Comprehensive 1D basin modelling, combined with thermal maturity indicators (vitrinite reflectance (R-o), T-max, the production index (PI) and the gross chemical composition), indicate that the Cenomanian formation is immature to marginally mature, whereas the Turonian-Maastrichtian source rocks are completely immature. This study and compiled published data demonstrated that the Turonian-Maastrichtian strata are immature organic-rich source rocks, possibly prospective as unconventional hydrocarbon resources in northern Jordan, particularly the Maastrichtian formation.
By constructing and dynamically simulating a three-dimensional geological model of a hydrocarbon prospect in the North Sea, several development strategies were tested to assess how hydrocarbon fields in sand injectite systems could be optimized. Significant reductions in water production and a moderate increase in oil can be achieved if a well is placed at a shallow depth in a sand-injectite system within an interval where sand injectites are not normally resolved on seismic data, net-to-gross (N/G) is low (typically less than 0.1) and stand-off to the oil-water-contact (OWC) is maximized. The low N/G of such wells challenges the paradigm that a successful development well must have a high proportion of net sand. While the cumulative volume of oil production may be similar to a development well placed closer to an OWC in a seismically mapped drill target, the cumulative volume of water produced may be significantly reduced. In the simulations presented here a broad K-v/K-h range was used to test the gross vertical connectivity uncertainty within the sand injectite system. A sweet spot exists at a K-v/K-h of around 0.1 - above that value water breakthrough and cut were accelerated, while below that sand injectite connectivity and water flood were choked back. The gross architecture and flow potential of both seismically mapped and non-seismically resolved sand injectites should be considered. Scenarios may exist where lateral sweep within a seismically mapped sand injectite is enhanced due to reduced vertical connectivity within the non-seismically resolved sand injectites.
Hydrogen sulfide (H2S) is a relatively common component in hydrocarbon fields, where it may be mixed with hydrocarbon oil or gas in proportions of up to 50% or more. Such hydrocarbons are often described as 'sour'. The H2S primarily originates from thermochemical sulfate reduction associated with evaporites, although biogenic pathways may apply in some cases. Hydrocarbon fields with the highest concentrations of H2S often remain undeveloped, representing already-discovered resources that could support the transition towards a lower-carbon economy. Meanwhile, hydrogen - recognized as a critical element of the energy transition - can be obtained from H2S currently by several energy consuming processes. A new subsurface engineering concept introduced here combines the rehabilitation of stranded sour hydrocarbon resources via H2S removal with the production of potentially economic amounts of hydrogen. The proposed approach removes H2S from the hydrocarbons as they are passed through a subsurface iron-bearing 'scavenging' reservoir. Reactions between the sour hydrocarbons and the iron minerals in this reservoir convert H2S to solid iron sulfide (pyrite) releasing hydrogen gas during the process. Sweetened hydrocarbons, hydrogen or both can then be produced. Subsurface removal of H2S and sequestering of sulfur from known stranded hydrocarbons avoids the cost and risk of surface-based H2S facilities, as well as exploration costs for new hydrocarbons in pristine locations. Here we term hydrogen produced from H2S in this way 'amber hydrogen', an addition to the hydrogen colour spectrum that can also be applied to hydrogen produced from H2S by any method.
High-quality source rocks exert primary control on hydrocarbon accumulations in continental lacustrine basins, particularly for tight sandstone oil reservoirs. The identity of the principal source rocks for the Chang 7 tight oil in the Yanchang Formation, Ordos Basin, and their control mechanisms on accumulation and enrichment remain uncertain. This study integrates gas chromatography-mass spectrometry (GC-MS) analysis of mudstones, oil shales and crude oils with hydrocarbon generation-expulsion simulations, abnormal pressure calculations and fluid-inclusion trapping pressure reconstructions to establish oil-source correlations, characterize primary source rocks and define controlling accumulation mechanisms. Results demonstrate that: (1) the Chang 7 tight oil was sourced predominantly from Chang 7 oil shales in a 'lower generation-upper reservoir' configuration; (2) these oil shales are laterally extensive with a substantial thickness (>15 m), high organic matter abundance (average total organic carbon 11.36 wt%), excellent kerogen quality (types I and II1) and moderate thermal maturity (average vitrinite reflectance 0.85%); (3) the cumulative hydrocarbon generation intensity averages 159.46 & times; 10(4) t km(-2), providing abundant material for tight oil accumulations; (4) source-reservoir pressure differentials (SRPDs) averaging 15.58 MPa have provided the necessary driving force for efficient oil charging into tight reservoirs; and (5) a high-quality oil shale distribution directly governs the tight oil distribution, with transitional zones between hydrocarbon generation centres and high-pressure domains representing optimal enrichment fairways. These findings clarify the fundamental role of lacustrine oil shales in tight oil systems and provide practical guidance for exploration in analogous continental basins.
Mud leakage during workover can contaminate existing fractures and lead to significant deviations in refracturing treatment-pressure designs. This study aims to characterize mud leakage behaviour in fractured reservoirs and predict its impact on refracturing treatment pressure. A two-phase Darcy flow framework was established to simulate mud leakage and to obtain the spatial distribution of mud saturation. Based on the simulated mud-retention geometry in existing fractures, a treatment-pressure prediction model was developed by partitioning the fracture into mud-occupied and unleaked flow regions and incorporating permeability damage. The workflow was validated using field data from two mud-contaminated refracturing wells in the Tarim Basin, NW China (wells A and B). Field data indicate leaked mud volumes of 13.0 m(3) (Well A) and 9.6 m(3) (Well B), accompanied by substantial productivity degradation (the unrestricted flow rates decreased from 142.3 & times; 10(4) to 52.2 & times; 10(4) m(3)/day in Well A and from 38 & times; 10(4) to 1 & times; 10(4) m(3)/day in Well B) and residual permeability ratios of 0.366 and 0.026, respectively. A baseline pressure prediction that ignores mud impact underestimates the observed treatment-pressure window (110-120 MPa for Well A; 120-130 MPa for Well B) by 20.3-36.2 and 14.6-42.2 MPa, respectively. After incorporating mud retention and permeability damage, the predicted pressure ranges shift to 109.6-117.4 MPa (Well A) and 122.4-146.9 MPa (Well B), yielding a clear overlap with the measured pressure windows and substantially reducing the mismatch. This study provides an additive and practically applicable method for pressure-design correction and risk assessment in mud-contaminated refracturing operations.
Kerogen wettability can significantly affect the preferential movement of fluids in organic-rich mudrocks as kerogen constitutes a significant fraction of mudrock volumes. In previous publications, the determination of the wettability of kerogen and organic-rich mudrocks was typically achieved using contact angle measurements through the sessile drop method, which might not be considered to be a ground truth quantitative measure of wettability. This method also requires pellets of kerogen to create a surface for the contact angle to be measured. No standardized procedure exists for making pellets under stress and with saturating fluid to replicate reservoir conditions. In this paper, we introduced a novel method for quantifying the wettability of kerogen, collected from different organic-rich mudrock formations (i.e. formations A, B and C), as a function of thermal maturity using adsorption isotherms. We compared the results from the adsorption isotherm experiments with contact angle measurements. Results demonstrated a reduction in water adsorption capacity as thermal maturity increases. The cumulative amount of adsorbed water (within the range of 0-60% relative humidity) in the isolated kerogen sample decreased by 75.3 and 91.8% for formations B and C, respectively, compared with formation A. Kerogen from formation A formed a 50 degrees air/water contact angle, whereas kerogen fromformation B formed a 111 degrees air/water contact angle and kerogen from formation C formed a 109 degrees air/water contact angle.
The pre-salt Aptian reservoirs are responsible for close to 80% of Brazil oil production. The unusual in situ deposits, constituted by magnesian clays, calcite spherulites and fascicular shrubs, were precipitated in a huge alkaline lacustrine system before the formation of the South Atlantic. The processes that generated the associated resedimented deposits are comparatively still poorly understood, although they correspond to important reservoirs in many pre-salt fields in the Santos, Campos and Kwanza basins. Systematic core and petrographical descriptions have provided detailed textural and compositional characterization of resedimented pre-salt deposits from the Santos Basin. They are composed mainly of carbonate intraclasts eroded from the in situ deposits. The predominant massive structure, widespread spatial distribution and lack of subaerial exposure indicate that gravitational flows, waves or surface currents cannot be the main depositional processes. Internal waves produced by perturbation of the chemocline in the stratified lacustrine system are considered able to generate the observed subtle, recurrent and widespread intercalation of resedimented and in situ deposits. The construction of realistic depositional models for the significant occurrence of these deposits in the pre-salt system will help to minimize the exploration risks and optimize the hydrocarbon recovery efficiency of the producing fields.
Northern Egypt and its Western Desert region are hydrocarbon provinces that record important Mesozoic extension, yet Jurassic and older synrift strata are still poorly characterized in these two areas, particularly in the onshore Shushan Basin. This work uses seismic-reflection data tied to borehole and geochemical data to investigate three main Jurassic synrift seismic and depositional megasequences in the Shushan Basin: (1) a Lower Jurassic retrogressive megasequence; (2) a Middle Jurassic prograding megasequence; and (3) an Upper Jurassic retrogressive megasequence. These megasequences, defined for the first time in this work, accompanied Late Triassic-Early Cretaceous tectonic extension, with deposition occurring in proximal environments such as rivers, lakes and deltas. Terrigenous organic matter was preserved over long periods of time within clay-rich source intervals, as confirmed via organic geochemical analyses. Significantly, the presence of Type II and Type III kerogen, and a total organic carbon content of up to 3.91% suggest good hydrocarbon source-rock potential in specific Jurassic intervals. One-dimensional burial models suggest that, with sufficient burial, these source intervals generated oil and gas with a recorded maximum yield in the Early Miocene. As a corollary, this work indicates that conventional and unconventional hydrocarbon exploration targets exist in the Shushan Basin. The results show Middle Jurassic shale-rich intervals to be prime tight-gas targets, while Upper Jurassic carbonate units are promising conventional reservoirs in both the central and southern parts of the basin. The high formation temperatures recorded show that geothermal options are also feasible for deep wells, expanding the economic importance of northern Egypt.
The Termit Basin, a well-explored hydrocarbon-rich basin in West Africa, provides an excellent case study for investigating oil families, palaeoenvironments and organic matter (OM) inputs in the Trans-Saharan epicontinental basins. This study examines 19 newly discovered southeastern oils using gas chromatography, gas chromatography-mass spectrometry and stable carbon isotopic analysis. While three oil families (I, II and III) were previously identified in the basin based on discoveries made prior to 2020, this study identified, for the first time, family I oils in the far east of the basin, and first recognized two new families (IV and V) by chemometric analysis and correlations of 14 biomarkers and carbon isotope compositions. Families I and IV show more terrigenous inputs than family V. Our results do not support previous work suggesting that family I was derived from algal-dominated OM. Compared with family I, a contribution of marine sources was defined for family IV, although terrigenous inputs remained significant. Family V originated from source rocks with more inputs of marine OM. Family V is divided into subfamilies V1 and V2, of which subfamily V2 is distinguished by greater algal inputs under more reducing conditions. The identification of family V proved the presence of a new petroleum system related to marine algal-rich source rocks in the Termit Basin. Our results suggest significant terrigenous OM influx and extensive marine algae blooms in the Trans-Saharan epicontinental seas during the Late Cretaceous, coinciding with sea-level changes.
Secondary migration is poorly understood and the generally favoured transport mechanisms fail to explain many of its apparent characteristics. Here, building on work originally developed in the1940s, I resurrect an old hypothesis of migration as a colloidal dispersion but in more detail than hitherto. This contribution expands on this hypothesis of migration with a focus on its theoretical mechanisms, limitations and advantages. The aim is to develop a self-consistent model to demonstrate how this transport mechanism might work. A better understanding of secondary migration of petroleum has implications for conventional and unconventional plays, and for reservoir diagenesis.
The hypothetical model for colloidal secondary migration, presented in part I, is tested here with numerical models to examine its viability and to determine the conditions under which it becomes ineffective. The main assumptions are that petroleum migrates as a Pickering emulsion of individual nanodroplets (a few tens of nanometres in size) and groups or 'flocs' of nanodroplets. These are nanodroplets are protected from coalescence by coatings of silica, asphaltenes and clay fines. Migration is achieved by diffusion (Brownian motion) of the nanodroplets, and advection of the flocs, working together cooperatively. The cases tested here with numerical models are: (1) Oil migration into an anticlinal structure (e.g. Ghawar Anticline, Saudi Arabia); (2) Gas migration into an anticlinal structure (e.g. Ghasha Anticline, United Arab Emirates); (3) Migration within a tight gas sandstone in a foreland basin (e.g. Niobrara gas field, Rock Island gas field, USA); (4) Migration within a tight oil sandstone in a foreland basin and its effects on a tight (shale) gas reservoir (e.g. Powder River Basin, USA); (5) Migration of heavy oil in a foreland basin (e.g. Western Canada Sedimentary Basin); and (6) The role of colloidal migration in reservoir diagenesis. The main implications of the model in these situations are: (1) and (2) Colloidal migration is highly efficient in the conventional oil and gas windows and is generally orders of magnitude faster than Darcy migration. (3) The mechanism breaks down rather abruptly in good carrier beds in the gas window, typically at a pore-throat size of c. 1 mu m. It provides a satisfactory explanation for the filling of unconventional tight gas sandstones and their low water saturations. (4) With lower-quality carrier beds, the mechanism breaks down in the late oil window, leading to tight oil carrier-bed plays. (5) The colloidal mechanism can migrate heavy oils relatively fast and easily, compared with Darcy flow, because the main resistance is the viscosity of the porewater rather than that of the petroleum. (6) Migrating Pickering emulsions provide an effective means of transporting inorganic matter long distances into traps. This has strong implications for reservoir diagenesis. For example, the mechanism can account for the observed trends of quartz cementation in petroleum traps and the timing of petroleum fluid inclusions in quartz overgrowth cements.If this hypothesis is substantiated by direct observation of the proposed petroleum nanodroplets, many traditional concepts of petroleum systems will have to be revised.
