Petroleum Migration Research Articles

Improving petroleum migration risk analysis by using play analogues

Improving petroleum migration risk analysis by using play analogues

Composition changes of hydrocarbons during secondary petroleum migration

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

Study on diesel vertical migration characteristics and mechanism in water-bearing sand stratum using an automated resistivity monitoring system.

Oil spills frequently occur on both land and sea. Petroleum in mobile phase will cause serious pollution in the sediment and can form a secondary pollution source. Therefore, it is very important to study the migration of petroleum in sediments ideally in a rapid and simplified approach. The release of diesel was simulated using fine beach sand to construct a model aquifer, and dynamic monitoring was carried out using an automated monitoring system including a resistivity probe originally developed by our research group. The mobile phase migration fronts were determined accurately using wavelet analysis method combined with resistivity curve method. Then, a relationship between resistivity and the joint oil-water content was established. The main conclusions were as follows. The seepage velocity of the diesel with high mobility at the initial stage of infiltration was faster, followed by a period when gravity seepage was dominant, and finally a redistribution period at the later stage, which was mainly an oil-water displacement process. The resistivity trends for diesel infiltration in different water-saturated soil layers varied with depth. The resistivity in the vadose zone fluctuated significantly, increasing initially and later decreasing. The resistivity change in the capillary zone was relatively small and constant in the initial stage; then, it increased and subsequently decreased. The resistivity in the saturated zone was basically unchanged with depth, and the value became slightly larger than the background value over time. Overall, for a large volume of mobile phase diesel leakage, the arrival migration fronts can be detected by wavelet analysis combined with resistivity curves. The thickness of the oil slick in the capillary zone can be estimated by resistivity changes. The relationships between resistivity and both the moisture content and oil-water joint saturation are in agreement with the linear models. The research results provide basic data and a new data processing method for monitoring of contaminated sites following major oil spills using the resistivity method.

Fractionation of dibenzofurans during subsurface petroleum migration: Based on molecular dynamics simulation and reservoir geochemistry

Dibenzofurans, oxygen-containing heterocyclic aromatics, are ubiquitous in crude oils. Their geochemical implications in petroleum geochemistry have been studied in numerous previous publications. Here, we present the distribution of dibenzofuran and its methylated homologues, and calculate the polarity and solubility of methyldibenzofuran isomers based on the Connolly surfaces and molecular dynamics simulation. The results show that the geo-chromatographic fractionation effect is evident due to absorption onto the water/silica matrix carrier bed during the oil migration process. Two potential molecular indicators relative to dibenzofurans, i.e. the total content of dibenzofurans and the relative abundances of 1-methyldibenzofuran to 4-methyldibenzofuran, are proposed for tracing the oil migration orientation and filling pathways. These two indicators were applied successfully in Paleozoic marine carbonate and Tertiary lacustrine sandstone reservoirs. The variations of source input, depositional environment, and maturity for oils from same source bed/kitchen appear to have no significant effect on these two indicators. It suggested that these two dibenzofuran indicators are potentially effective molecular tracers for orientation and filling pathways in oil migration.

Control factors of high and stable production of Jurassic Da'anzhai Member tight oil in central Sichuan Basin, SW China

By systematically analyzing the basic geological characteristics of tight oil in Jurassic Da'anzhai Member in the middle of Sichuan Basin (Central Sichuan area) and combining with a large number of exploration and development data, we examine the main controlling factors and exploration direction for high and stable production of tight oil. Tight oil in the Da'anzhai Member has the following characteristics: large and low abundance resources; generally tight, relatively high quality reservoirs; adjacent source rocks and reservoirs, favorable migration and accumulation of oil; extensive oil-bearing pores. Development practice reveals that the high and stable production oil wells for tight oil are mainly distributed in fractured vuggy reservoirs in the shore-lacustrine sedimentary subfacies, and fractures are very important in affecting the high and stable production of tight oil in the Da'anzhai Member. Natural gas plays an important role (gas drive) in petroleum migration and accumulation and high production of oil wells. Combined with the characteristics of high and stable production, exploration and development results, drilling cost and other factors, it is considered that the Da'anzhai Member located in the middle and south part of Sichuan Basin is a promising field for exploration and development of tight oil in the Jurassic of the Sichuan Basin.

Secondary migration of petroleum along syncline axes: a case study of the southern Kuqa Foreland Basin

Tracing petroleum migration pathways for petroleum exploration in a sedimentary basin is challenging. Paleo-uplifts are generally considered to represent the primary migration directions of petroleum. Here we propose a model for the Kuqa Foreland Basin, in which petroleum migrates along the axes of synclines between paleo-uplifts, based on an integrated analysis of seismic, geochemical, and production data. Interpretation of detailed seismic data indicates that petroleum is unlikely to migrate to the paleo-uplifts because of their relatively low positions, fault disruptions, or a lack of Mesozoic reservoirs. Geochemical parameters, including the ratios of alkyl dibenzothiophenes and the gas wetness parameter, show that petroleum maturity gradually decreases along the axes of synclines between paleo-uplifts from northeast to southwest. Petroleum production data and gas/oil ratios also show decreasing trends from northeast to southwest. This evidence suggests that petroleum is likely to migrate along the axes of the synclines between the paleo-uplifts from northeast to southwest. This study not only enhances the scientific understanding of secondary migration, but also may be useful to guide petroleum exploration in the southern Kuqa Foreland Basin.

Structure kinematics of a transtensional basin: An example from the Linnan Subsag, Bohai Bay basin, Eastern China

The Linnan subsag is a petroliferous, secondary tectonic unit of the Huimin sag that is located in the western part of the Jiyang depression in the Bohai Bay basin, eastern China. In this study, the authors calculated basin extensional rate and slipping displacement of boundary faults in the dip and strike directions, using seismic and drilling data. The evolution of the Linnan transtensional basin from the Eogene through the Quaternary is quantitatively described, and a dynamic model is established. The Linshan and Xiakou boundary faults of the Linnan subsag are used as a case study to describe a method to calculate the strike and dip slipping displacements of active faults under oblique extension. The results quantitatively illustrate the behavior of the Linnan subsag boundary faults over time. The Linnan subsag transtensional basin experienced four stages of evolution: weak extension during the Kongdian Formation, rapid extension and fault depression during the fourth member of the Shahejie Formation, intensive transtension and fault depression during the third member of the Shahejie Formation–Dongying Formation, and weakening fault depression during the Guantao Formation–Pingyuan Formation. The results of this study provide further understanding of the processes of petroleum migration and accumulation in the region.

Raman spectroscopic study of cyclohexane at pressures below 1000 MPa

At present, the room temperature freezing pressure of cyclohexane is still uncertain, and the phase transition pressure of solid I - solid III is not reliable at ambient temperature. In this work, we have performed a Raman spectroscopic study of cyclohexane in a Moissanite anvil cell at pressures below 1000MPa at 25°C, and analyzed the characteristic of Raman brands νs(CH2), νas(CH2) and νb(Ring). Two phase transition pressures 80MPa and 550MPa were determined by a quartz pressure gauge, and they are the room temperature freezing pressure of cyclohexane and the phase transition pressure of solid I to solid III, respectively. Furthermore, from the phase diagram of cyclohexane, it is inferred that pressure plays an important role on the stability of cyclohexane as the main constituent of oil, and it can be beneficial to understanding the formation, migration and preservation of petroleum in subterranean rock strata.

Effects of elastic anisotropy on primary petroleum migration through buoyancy-driven crack propagation

Material anisotropy may significantly influence the behavior of fluid transport in sedimentary basins and other environments with laminated or foliated rocks. In this paper, we present a fracture mechanics model to investigate primary migration of petroleum (oil and gas) through propagation of a vertical, buoyancy-driven blade crack in a transversely isotropic source rock. The source rock is assumed to have very low permeability and hence can be modeled as a linear elastic medium. Fracture parameters (stress intensity factor and crack opening displacement) are derived using an equivalent set of anisotropic elastic properties. The crack propagation velocity (i.e., petroleum migration velocity) and crack opening (fracture aperture) are determined using a fracture mechanics criterion together with the first order approximation of plane Poiseuille flow equations of fluid mechanics. For subhorizontal layering, we find that the fluid migration velocity and fracture aperture are significantly increased if the elastic modulus in the vertical direction is smaller than that in the horizontal direction. Finally, we discuss the applicability of the formula for isotropic materials along with the equivalent anisotropic elastic parameters introduced in this paper to evaluate fracture aperture for cracks in anisotropic rocks.

Control of facies, maturation and primary migration on biomarkers in the Barnett Shale sequence in the Marathon 1 Mesquite well, Texas

A great deal is known about the genetic relationships between biomarkers and their biogenic precursors in organic rich rocks. The same is true of the way in which biomarker compound ratios change during maturation. On the other hand, very little is known about whether a crude oil can fully retain its inherent compositional ancestry during expulsion from a source rock. Thanks to shales being characterized in great detail for their unconventional resource potential, new information is gradually coming to light. Here we report on observations in biomarker geochemistry of a thermally mature core of the Barnett Shale, in which organofacies and maturity are essentially the same, but where intraformational sources and reservoirs have already been reported.Our results indicate that most biomarkers are not fractionated as the primary migration of petroleum within source rocks takes place. The 20S/(20S + 20R) ratio of C27 steranes is uniform in the whole source-rock sequence, while the 20S/(20S + 20R) ratio of C29 steranes shows indistinctly high values in the reservoir unit. The 20S/(20S + 20R) ratio of diasteranes and the 22S/(22S + 22R) ratio of C31 17α-hopanes do not appear to have been fractionated, which may be a result of the thermal isomerization reactions predominating over and masking out the possible fractionation effects. Diasteranes/steranes ratios do not exhibit features that suggest an association with fractionation, but rather are broadly correlated with lithology. However, compared to the diasteranes/steranes ratios, the Ts/(Ts + Tm) ratio is much more sensitive to changes in mineral compositions. Variations in the Ts/(Ts + Tm) ratio show a positive correlation (R2 = 0.73) with mixed-layer illite-smectite content. Fractionation in the Ts/(Ts + Tm) ratio, if it has so occurred, may be subsequently overprinted by in-situ clay-catalyzed reactions.

Structural patterns of the late Mesozoic crustal detachment system in the Raoyang Sag, Bohai Bay Basin, eastern China: New insights from 3D seismic data

Understanding the late Mesozoic tectonic origin and structural patterns of the Bohai Bay Basin (BBB) is of growing importance for its buried-hill petroleum exploration. This study revealed, based on 3D seismic and borehole data, that the Raoyang Sag in the Jizhong Depression, western BBB, was dominated by a crustal detachment system during the late Jurassic to the early Cretaceous. It was characterized by the WNW-dipping low-angle detachment fault F0 (namely Cangxi Fault), the structural dome cored by Archean Basement rocks at the footwall and supradetachment basins on the hanging wall. We suggested the late Mesozoic volcanic materials and coarse deposits accumulated in the supradetachment basins had locally diminished the petroleum prospect, but the syndetachment deformation and denudation had contributed to it by means of promoting petroleum migration from source rocks to reservoirs and improving porosity and permeability of the reservoir rocks by karstification and structural fracturing.

Application of biomarkers to petroleum migration in the Linyi fault area, Huimin Depression, Bohai Bay Basin, China

A geochemical investigation was carried out on 32 crude oil samples to investigate the origin of the oil and to trace the migration direction in the Linyi fault area, Huimin Depression, Bohai Bay Basin, China. The oils, which were characterized by low gammacerane content and a dominance of C27 over C29 regular steranes, originated from the source rock of the third member of the Shahejie Formation (Es3) in the Linnan Sag. A sequential charge of low- and high-maturity oils from the Es3 source rocks resulted in a decrease in oil maturity in the migration direction. The petroleum migration direction in the footwall of the Linyi fault was northward, away from the fault, and the migration direction at the southwest end (in the hanging wall) of the Linyi fault was westward, along the fault, as evidenced by lateral gradients of biomarker parameters of various maturity, density, and viscosity.

Gas purge microsyringe extraction coupled to comprehensive two-dimensional gas chromatography for the characterization of petroleum migration

Several nitrogen-containing compounds play important roles as molecular indicators in petroleum migration but are usually absent or present at very low concentrations, especially when oils have been subjected to severe biodegradation or water washing. In this study, we use thiophenic compounds (such as dibenzothiophene and its alkylated homologs) as alternative oil migration indicators because they appear to exhibit strong absorption/adsorption interactions with solid organic/mineral phases due to their molecular structure, similar to organic nitrogen compounds. To improve the detection sensitivity of trace analytes, a gas purge microsyringe extraction (GP-MSE) device was developed and coupled to comprehensive two-dimensional gas chromatography/time-of-flight mass spectrometry (GC×GC-TOFMS) for the simultaneous analysis of biomarkers and trace nitrogen- and sulfur-containing compounds in crude oils. Twenty oil samples collected from the Hashan region of the Junggar Basin in China were classified as having different biodegradation levels and confirmed to be primarily sourced from the Fengcheng Formation with similar maturities and depositional environments. In addition to the commonly used oil migration parameters derived from the distribution of organic nitrogen compounds, several geochemical parameters based on the ratios of 4,6-/1,4-, 4,6-/3,6- and 4,6-/2,7-dimethyldibenzothiophenes (DMDBTs) were proposed to indicate the oil migration direction. The conclusions on oil migration obtained from organic nitrogen compounds and DMDBTs were in good agreement and further supported by other geological evidence. An oil migration model for the region was developed by combining the geochemical data with the geological information.

Progress in fault seal and petroleum migration evaluation

The method incorporating fault properties into petroleum migration models, which employs shale gouge ratio (SGR) as the fault sealing capacity indicator and ray-tracing as the migration algorithm, has provided a means to quantify the role of faults in petroleum migration. Recent applications of the method, however, reveal extremely large uncertainties in fault properties and difficulty in predicting petroleum migration across or through faults. More robust approaches are needed to make reliable predictions.

Petroleum migration in the Bight Basin: a fluid inclusion approach to constraining source, composition and timing

The Bight Basin in southern Australia is a vast under-explored offshore area with promise of, but as of yet, limited proof for hydrocarbons. Fluid inclusions (FIs) offer a unique method to test for petroleum migration, composition and timing, which would otherwise remain hidden in the rocks, and more direct evidence to calibrate basin models. A reconnaissance-scale FI study, using CSIRO’s Grain with Oil Inclusion (GOI™) technique, was undertaken to detect liquid hydrocarbons in Jurassic to Cretaceous sandstones. Oil-bearing, and in some cases gas-rich, inclusions were detected at low abundance, and their presence provides proof of oil generation and migration in the Ceduna Sub-basin. Geochemical fingerprinting of FI oil was undertaken using the Molecular Composition of oil Inclusions (MCI) technique on an intra-Coniacian interval in Gnarlyknots-1A and a Cenomanian interval in Greenly-1. The results show differences in the type of organic matter input, with algal co-sourcing significant for the central Ceduna Sub-basin. The timing of oil migration from pressure-temperature (PT) reconstructions was interpreted in Gnarlyknots-1A, Greenly-1, Duntroon-1 and Potoroo-1. The results indicate oil charge during the Late Cretaceous in the basin depocentres, explained by sediment loading of the Upper Cretaceous succession by the Hammerhead Supersequence and oil, gas-condensate and gas charge to the depocentres and basin margins during the Miocene. The Great Australian Bight Research Program is a collaboration between BP, CSIRO, the South Australian Research and Development Institute (SARDI), the University of Adelaide and Flinders University. The Program aims to provide a whole-of-system understanding of the environmental, economic and social values of the region, providing an information source for all to use.

Characterization of Origin and Evolution of Formation Water in Buried Hill of Jizhong Depression, China, Using Multivariate Statistical Analysis of Geochemical Data

Groundwater samples from buried hill of Jizhong Depression were evaluated using two statistical analyses: hierarchical cluster analysis (HCA) and principal component analysis (PCA). The samples were classified into four clusters, C1–C4, in HCA and the hydrochemical types of C1–C4 are HCO3-Na, Cl·HCO3-Na, Cl-Na, and Cl-Na·Ca. From C1 to C2, C3, and C4, the water-rock interaction becomes increasingly intensive, and rNa/rCl gets lower while total dissolved solids and r(Cl-Na)/rMg get higher. Three components of PCA explain 86.87% of the variance. Component1 (PC1), characterized by highly positive loadings in Na+ and Cl−, is related to evaporation concentration. Component2 (PC2) is defined by highly positive loading in HCO3- and is related to influence of atmospheric water. With high positive loadings in Ca2+ and high negative loadings in Na+ and SO42-, component3 (PC3) suggests plagioclase albitization. The combination of HCA and PCA within the hydrogeological contexts allowed the division of study area into five dynamic areas. From recharge area to discharge area, the influence of atmospheric water gets weaker and water-rock interactions such as evaporation concentration and plagioclase albitization become intensive. Therefore groundwater in buried hill showed paths of hydrochemical evolution, from C1, to C2, C3, and C4. Buried hill reservoir in Jizhong Depression is mainly distributed in hydrodynamic blocking and discharge area; therefore the two regions can be the favorable areas for petroleum migration.

CO2 storage in Residual Oil Zones: Field-scale modeling and assessment

Residual Oil Zones (ROZs) are formed as the result of secondary tectonic activities which trigger extensive oil remobilization after the primary petroleum migration. The ROZs are attractive targets for CO2 Enhanced Oil Recovery (CO2-EOR) and storage: first, because in many cases, the thickness of the ROZ ensures an overall recoverable volume of oil comparable to that of the Main Pay Zone (MPZ) and second, because the ROZ has favorable containment and capacity for large-scale and long-term EOR-storage projects. This study investigates one of the underlying theories of the ROZ formation, called the Altered Hydrodynamic Flow Fields (AHFF). The impact of the AHFF process on the formation of ROZs is specifically investigated using a field-scale simulation model for a Permian Basin San Andres reservoir. The simulation model is tuned and verified by validating the ROZ's characteristics, such as the thickness of the ROZ, the shape of the saturation profile, and the tilt of the OWC. The tuned Permian Basin San Andres reservoir model is used to simulate the primary recovery and the secondary waterflooding phases in the MPZ. Depending on the CO2 availability and ROZ development strategy, six different development scenarios are specified beyond the waterflooding phase. The corresponding simulations are performed to find the optimum EOR-storage strategies for the MPZ-ROZ through the extensive comparison of key performance parameters, including the cumulative oil recovery, CO2 storage and, net CO2 utilization. The results confirm the technical viability of CO2-EOR and storage in the ROZ. The most favorable expansion strategy in terms of oil production and CO2 storage is the simultaneous development of the MPZ and the ROZ from the beginning of EOR-storage process. Most importantly, the study demonstrates that the volume of the utilized CO2 has a substantial effect on the success of the EOR-storage. While other expansion strategies such as sequential development also provide reasonable oil production response and CO2 storage potential, early project expansion into the ROZ without sufficient investment in CO2 resources is shown to be detrimental to the economics of the project. Finally, several important technical considerations for CO2 storage are qualitatively discussed, including assessment of the ROZ storage capacity, saltwater disposal requirements, and reduced risk of CO2 leakage in the ROZ.

Pore and pore network evolution of Upper Cretaceous Boquillas (Eagle Ford–equivalent) mudrocks: Results from gold tube pyrolysis experiments

Low-maturity Boquillas Formation (Eagle Ford Formation–equivalent) organic-lean calcareous mudrock samples collected from outcrop were heated in gold tubes under confining pressure to investigate the evolution of organic matter (OM) pores and mineral pores. The majority of OM in the Boquillas samples was migrated petroleum (bitumen) based on evidence from geochemical analyses, solvent extraction, and scanning electron microscopy (SEM) petrography. The SEM images showed several diagenetic events—including framboidal pyrite precipitation and euhedral calcite, quartz, kaolinite, and chlorite cementation—that were all interpreted to have occurred prior to petroleum expulsion and pore-scale to bed-scale petroleum (bitumen) migration. Two major pore types were present prior to heating: primary mineral pores and modified mineral pores with migrated relic OM. From heating experiments, pores were found to be associated with stages of OM maturation. During the bitumen generation stage, modified mineral pores were dominant, and primary interparticle and intraparticle pores were present. During the oil generation stage, modified mineral pores with isopachous OM rim were observed to be the most abundant pore type. During the gas generation stage, both modified mineral pores and nanometer-sized spongy OM pores were predominant. We interpreted the occurrence of modified mineral pores to be the result of (1) oil and gas filled or partially filled voids that developed during petroleum migration and water expulsion; (2) voids after removing of oil, gas, and water during sample preparation; and (3) trapping of water molecules. The formation of these nanopores was interpreted to be related to gas generation and structural rearrangement of OM.

Origin and evolution of formation water from the Ordovician carbonate reservoir in the Tazhong area, Tarim Basin, NW China

Chemistry, H, O and Sr isotopes of formation waters were determined from the Ordovician carbonate reservoirs in the Tazhong area, Tarim basin. The aim is to elucidate their origin and migration and their alteration by thermochemical sulfate reduction (TSR) and water-rock interactions. The waters were originated from evaporated seawater, and are enriched in Ca and Sr, and depleted in Mg and SO4 compared with the seawater evaporation trajectory (SET), thus are considered to result from dolomitization, anhydrite dissolution and in situ TSR. δ18O values show positive shift due to water-rock interactions, and δD values show negative shift with increasing TSR extents or total thiaadamantanes concentrations of the associated oils, likely resulting from hydrogen isotope exchange with TSR-H2S. However, the δD-δ18O relationship was mainly controlled by the mixing with paleo-meteoric water with δD of −50‰ and δ18O of −7.5‰. Paleo-meteoric water may have leached the Silurian siliciclastic rocks and thus has 87Sr/86Sr up to 0.715. Upper Ordovician (O3l) formation water shows more negative δD and δ18O values, higher 87Sr /86Sr ratios and lower total dissolved solids (TDS) than the O1–2y water, which may have resulted from mixing of paleo-meteoric water. Lower Ordovician (O1–2y) formation water shows 87Sr /86Sr ratio of 0.7095–0.7105, TDS from 160 to 240g/l, and Sr concentrations from 300 to 1000mg/L, which may have resulted from mixing with hydrothermal fluid up-migrated from Ediacaran and Lower Cambrian siliciclastic rocks. Significant mixings with paleo-meteoric water and hydrothermal fluid occurred at paleo-highland at the east of No.1 Fault-Slope Zone and active faulting zone near No.10 Structural Belt, respectively. Hydrothermal fluid and oils probably shared similar migration pathways in No.10 Structural Belt. Formation water geochemistry may thus provide clues to constraint on petroleum migration.

Remobilization of deep basin brine during exhumation of the Illizi Basin, Algeria

Understanding the processes that drive fluid flow in sedimentary basins has important implications for models of metallic ore and petroleum migration and accumulation in the subsurface. Potential drive mechanisms include gravity-driven flow, compaction-driven flow, and density-driven convection. In this study, we demonstrate that the brine hosted in Ordovician sandstone in the Illizi Basin in Algeria is genetically linked to Triassic-Liassic evaporites deposited >400 km to the north in the Berkine Basin. This observation confirms that long distance, lateral, brine migration has occurred within the basin in the past. We assess the hydrogeologic record preserved in aqueous fluid inclusions within the Ordovician sandstone, document a marked increase in formation water salinity during cooling and exhumation, and evaluate the drive mechanisms for late-stage remobilization of deep brines within the basin. It is hypothesized that the release of overpressure during exhumation of the Illizi Basin may have been a critical contributor to updip fluid flux. This model could be applicable to other exhumed basins worldwide.