Hydrocarbon Migration History Research Articles

Hydrocarbon charge and petroleum system evolution of the Montney Formation: A multidisciplinary case study of the Blueberry sub-play in Northeast British Columbia, Canada

Abstract The origin, timing, and evolution of hydrocarbons in the early Triassic Montney Formation siltstone has long been debated and is poorly understood. A proper understanding of the timing and processes involved in hydrocarbon emplacement forms an important part of in-situ fluid characterization. Presented here is a case study from northeastern British Columbia. This study integrates basin modeling, carbon isotope geochemistry, fluid inclusion microthermometry, organic and inorganic petrography, sedimentology, and stratigraphy to reconstruct the burial history and relative timing of geological events and mechanisms involved in developing the present-day Montney hydrocarbon system in the Blueberry sub-play. Petrography from whole core indicates that the organic material present is largely pyrobitumen. The lack of primary kerogen suggests that the original oil charge must have migrated into place prior to increasing thermal maturity and conversion to pyrobitumen at maximum burial. In addition, patterns in stable carbon isotope curves from extracted core fluids show a stratified oil column, indicating a lack of vertical migration that would have homogenized the hydrocarbons. Thin section petrography and facies analysis show a laminated fabric with strong permeability anisotropy suggesting preferential migration along bed-parallel permeability pathways, which would have prevented significant vertical mixing. Any interpretations about the origins of the Montney Formation hydrocarbons in this study area must satisfy these observations. Given the data available, the most likely interpretation is a bed-parallel eastern migration from a downdip source. Collective understanding of these datasets helps illustrate the processes involved in the evolution of the hydrocarbon system present in the Montney Formation. Enhanced understanding of the Montney hydrocarbon migration history and reservoir evolution is important for understanding the lateral and vertical variations in the producing gas-condensate-ratios across the Montney formation fairway.

Water Saturation Modeling Challenges in Oil-Down-to Wells: An Example from a Multidarcy North Sea Reservoir

Summary The initial water saturation in a reservoir is important for both hydrocarbon volume estimation and distribution of multiphase flow properties such as relative permeability. Often, a practical reservoir engineering approach is to relate relative permeability to flow property regions by binning of the initial water saturation. The rationale behind this approach is that initial water saturation is related to both the pore-throat radius distribution and the wettability of the rock, both of which affect relative permeability. However, pore-throat radius and wettability are usually not explicitly included in geomodel property modeling. Therefore, the saturation height model should not only capture an average hydrocarbon pore volume but also reflect the underlying mechanisms from hydrocarbon migration history and its impact on initial water saturation distribution. This work introduces and describes a new term, excess water, for more precise classification of saturation height model scenarios in reservoirs in which multiple mechanisms have interacted and caused a complex water saturation distribution. An example of the presence of transition zones related to drained local perched aquifers (excess water) in oil-down-to (ODT) wells is shown using a limited data set from a North Sea reservoir. The physical basis for drainage and imbibition transition zones connected to both regional and perched aquifers is given. The distribution of initial water saturation in reservoirs containing excess water is demonstrated through numerical modeling of oil migration over millions of years. Highly permeable reservoirs are more likely to have locally trapped water because of lower capillary forces. A static situation occurs in areas where the capillary forces cannot maintain a high enough water saturation for further water drainage. On the other hand, both high- and low-permeability reservoirs may have significant excess water because of ongoing dynamic effects. In both cases, long distances for water to drain laterally to a regional aquifer enhance the possibility for a dynamic excess water situation.

Recent magmatism drives hydrocarbon generation in north-east Java, Indonesia

Conventional studies of petroleum basins associate oil generation with the gradual burial of organic-rich sediments. These classical models rely on the interplay between pressure, temperature, and the time required for organic matter transformation to oil and gas. These processes usually occur over geological timescales, but may be accelerated by rapid reactions when carbon-rich sediments are exposed to migrating magmatic fluids. The spectacular Lusi eruption (north-east Java, Indonesia) is the surface expression of the present-day deep interaction between volcanic and sedimentary domains. Here we report the ongoing generation of large amounts of hydrocarbons induced by a recent magmatic intrusion from the neighbouring Arjuno-Welirang volcanic complex. We have investigated a unique suite of oil and clast samples, and developed a detailed conceptual model for the complex hydrocarbon migration history in this part of the basin by integrating multidisciplinary techniques. Our results show that palynology, organic petrology, and chlorite microthermometry are the most sensitive geothermometers for basins affected by recent magmatic activity. These findings further our understanding of the driving mechanisms fueling the world’s largest active mud eruption and provide a unique dataset to investigate modern hydrocarbon generation processes.

Back to the oil migration history for asphaltene flow assurance engineering in uneven asphaltene precipitating risk distributed oilfield

Abstract This work was motivated from inconsistent asphaltene onset pressure (AOP) measurement results in which AOPs could be detected from some samples but not from others, even fluid samples were collected from the unique carbonate oilfield. Our initial challenge, applying a general rule-of thumbs that has been widely used in the industry (based on compositional gradients and sampling horizons dependency), failed to provide understanding into the probable causes of the AOP result variations. Then, a multidisciplinary approach aiming for synergy between engineering and geoscience was developed to re-assess the uneven distribution of asphaltene precipitation risk. Finally, incorporating the geosciences aspect succeeded in explaining the correlation between the asphaltene precipitation risk distribution and hydrocarbon migration history. In support of this finding, numerical models that applied the Cubic Plus Association (CPA) equation of state (EoS), were generated by treating the geological heterogeneity as a variation of asphaltene content. The models reproduced asphaltene precipitation envelopes (APE) that matched the overall trend of the experimental AOP data. This work has reduced the uncertainty around understanding the asphaltene precipitation risk. It has also added useful discussion to the field of asphaltene flow assurance engineering from a potential cost saving perspective.

The influence of depositional processes on the porosity of chalk

Chalk constitutes challenging low-permeability reservoirs with porosity variations attributable to complex interactions between numerous processes. The influence of depositional processes, and thus the value of depositional models to predict porosity, is subject to continuing debate. In this study, a new approach is applied to investigate the influence of depositional and early post-depositional processes on chalk porosity, based on the 303 m thick Upper Cretaceous chalk succession in the Mona-1 core from the Danish North Sea. The influence of depositional processes on porosity is isolated by a mathematical correction of porosity data. Results confirm that mass-transport deposits are on average more porous than pelagites, whereas turbidites are less porous, given similar composition, burial history, and hydrocarbon migration history. The porosity variation between 12 chalk facies suggests that grain packing of the sediment in the consolidated state caused the facies-dependent porosity variation. Bioturbation caused a relatively tight grain packing compared with deposits that escaped bioturbation. Early plastic shear deformation of tightly packed bioturbated units resulted in dilative behaviour, which increased porosity, whereas more loosely packed units responded contractively, resulting in decreased porosity preservation. A firm understanding of chalk facies and thorough facies analyses are thus considered instrumental in chalk reservoir prediction.

Fluid migration history from analysis of filling fractures in a carbonate formation (lower cretaceous, middle Magdalena valley basin, Colombia)

The integration of Conventional Petrography, SEM, Rare Earth Element geochemistry (REE) and Fluid Inclusions analysis (FI), in the fracture fillings at the Rosablanca Formation (Middle Magdalena Valley basin), make it possible to relate opening and filling events in the veins with hydrocarbon migration processes.Petrographic and SEM data indicate that the veins are fracture filling structures, with three types of textures:1) Granular aggregates of calcite (GA); 2) Elongated granular aggregates of calcite (EGA); and 3) Fibrous aggregates of calcite and dolomite (FA). The textural relationship suggests that GA must have been formed in an environment of widespread extension of the basin, while EGA and FA must have been formed in a compressive environment.
 The geochemical analyses of REE carried out in the dominant fill of the veins (GA) indicate that these fillings must have been formed in a closed system (intraformational fluid movement) for the drilling well Alfa-1, while in the drilling wells Alfa-2 and Alfa 3, these fills (GA) must have been formed in a characteristic environment of open system (transformational fluid movement). Two pulses of hydrocarbon migration were identified through the study of fluid inclusions: In the first event, light hydrocarbons and aqueous fluids (H2O-NaCl-CaCl2) migrated trough the primary porosity and fractures at temperatures between 60ºC- 90ºC. In the second event, light hydrocarbons associated with aqueous fluids (H2O-NaCl-CaCl2) migrated through fractures at temperatures between 70ºC - 120ºC. Data obtained in this investigation will strengthen the knowledge about the hydrocarbon migration history and entrapment in the Middle Magdalena Valley basin (VMM) particularly in the lower Cretaceous age reservoirs.

Quantitative fluorescence techniques for detecting residual oils and reconstructing hydrocarbon charge history

Two new fluorescence techniques, quantitative grain fluorescence (QGF) and quantitative grain fluorescence on Extract (QGF-E), can detect palaeo-oil zones and current residual oil zones in petroleum wells, respectively. QGF and QGF-E measure the fluorescence emission spectra of trace fluorescence from reservoir grains and their extracts. QGF is measured on dry, disaggregated reservoir grains after a cleaning procedure involving solvent, hydrogen peroxide and acid; whereas QGF-E is measured on the solvent extract from the QGF cleaned grains. Palaeo-oil zones have distinct QGF spectra with spectral peaks between 375 and 475 nm and elevated fluorescence intensities compared with spectra for rocks that have always been water saturated. Current and residual oil zones have distinct QGF-E spectra with spectral peaks at around 370 nm and elevated QGF-E intensities compared with that for current water zones. Both QGF and QGF-E responses increase upwards from the palaeo-oil–water and residual oil–water contacts, respectively. An oil producing well from Timor Sea, NW Australia was investigated in detail using the QGF and QGF-E techniques to illustrate how they can be used to reconstruct hydrocarbon migration history.

Archaean oil migration in the Witwatersrand Basin of South Africa

Abstract: The Late Archaean Witwatersrand Supergroup of South Africa hosts the largest known gold-uranium-pyrite ore deposits. Oil preserved in fluid inclusions in quartz grains in siliciclastic sedimentary rocks of that supergroup implies that hydrocarbon generation and migration occurred during the Archaean, and may have been involved in mineralization processes. Through reference to Phanerozoic analogues, oil-bearing fluid inclusions entrapped in healed microfractures in detrital quartz grains and in early syntaxial quartz-overgrowths imply, that the onset of oil migration coincided with early to intermediate stages of burial, while intra-granular porosity was still preserved. Multiple generations of oil migration are indicated by: (i) oil inclusions within early diagenetic cements at different levels in the stratigraphic succession; (ii) more than one type of oil in entrapment sites; (iii) oil entrapment in multiple stages of the quartz paragenetic sequence. Oil generation and migration are considered to have occurred throughout, and for some considerable time after, development of the Witwatersrand Basin, consistent with progressive burial and kerogen maturation in more than one tectonic regime. Oil-bearing fluid inclusions within detrital sandstone fragments suggest that oil migration also occurred in a sedimentary succession on the Kaapvaal Craton prior to 2.9 Ga. Oil in the Witwatersrand Supergroup was most likely derived from multiple source areas, with the principal source probably being shales within the lower Witwatersrand Supergroup. The hydrocarbon migration history of the basin has important implications for understanding the textural relationship between gold, bituminized oil and uraninite in the giant gold-uranium-pyrite ore deposits.

3-D Visualization and Isochore Analysis of Extensional Diapirs Overprinted by Compression

Palinspastic restorations elucidate geologic and hydrocarbon-migration histories in salt provinces; however, salt dissolution and salt flow in and out of the section plane make it difficult to determine the shape of salt bodies before deformation, which hampers accurate restorations. Three-dimensional computer visualization of a physical model and analysis of isochores provide clues to the original shape of allochthonous salt bodies that were emplaced during extension and later compressed.

Hydrocarbon migration history, West of Shetland: integrated fluid inclusion and fission track studies

In sandstone reservoir rocks in the vicinity of the Rona Ridge, West of Shetland, there is evidence for former episodes of hydrocarbon migration in addition to the episodes responsible for current accumulations. An integrated study of fluid inclusion microthermometry and apatite fission track analysis (AFTA) has helped to clarify the history of fluid migration in the region. The Upper Jurassic Rona Sandstone contains both hydrocarbon and aqueous fluid inclusions. Hydrocarbons occur in trails of secondary inclusions through detrital grains, and as primary inclusions in quartz overgrowths and authigenic feldspars. This indicates at least 2 phases of migration before the presently trapped oil entered the rock: fluorescence colours indicate that they are of distinct compositions. Associated aqueous inclusions yield minimum trapping temperatures which indicate that the earliest hydrocarbons were associated with a phase of hot fluid migration, and that cooler conditions pertained during later migration. AFTA data provide independent evidence for a passage of hot fluid early in the history of the rock, which may be related to Late Jurassic–Early Cretaceous rifting. AFTA data also suggest a second episode of heating and cooling in the Tertiary following uplift, which may have been responsible for a later stage of hydrocarbon generation and migration. The results reflect repeated expulsion of fluids from deep basinal areas onto adjacent topographic highs, throughout the late Mesozoic to Recent.

Dating and duration of hot fluid flow events determined using AFTA® and vitrinite reflectance-based thermal history reconstruction

Abstract Heating due to lateral introduction of hot fluids is becoming an increasingly recognized feature of the thermal histories of sedimentary basins. In some basins, heating by fluids may have an important effect on hydrocarbon source rock maturation history, so that quantification of the magnitude and timing of heating become essential elements in hydrocarbon prospectivity. In other cases, determining the time of fluid heating in a reservoir may provide a key constraint on hydrocarbon migration history. Examples are presented using AFTA apatite fission track analysis and vitrinite reflectance (VR) data to identify and quantify fluid heating in well sequences from several regions. In the West of Shetland region, in the vicinity of the Rona Ridge, non-linear palaeotemperature profiles defined by AFTA and VR results provide evidence of local heating shallow in the section. AFTA timing constraints suggest introduction of heated fluids produced by nearby Tertiary intrusive activity, although the time constraints are broad because of the low maximum palaeotemperatures involved ( R 0 max < 0.6%). In a well from Asia, transient maximum palaeotemperatures > 120°C resulted in R 0 max > 0.6% in an Eocene section, with AFTA constraining the fluid flow event responsible for the early to mid Miocene (25 to 10 Ma). On the North West Shelf of Australia transient fluid flow associated with hydrocarbon leakage, and possibly charge, has been previously identified by a combination of AFTA, VR and fluid inclusion homogenization temperature ( T h ) results. In the East Swan-2 well, a fracture inclusion in quartz from shallow Eocene sandstones gives a minimum T h value of 88°C, c. 40°C higher than the present temperature. AFTA and VR data show no direct evidence of sustained heating at such a temperature, and can only be reconciled if the duration of heating was c. 20 000 years. The results are consistent with this event being associated with passage of a hot brine and hydrocarbon fluid (O’Brien and Woods, 1995). These case studies demonstrate that a combination of thermal history tools can be used to identify and quantify the thermal effect of fluid flow, potentially allowing much tighter constraints on hydrocarbon generation and migration histories.

Newark Rift System: A Potentially Prolific Hydrocarbon Province: ABSTRACT

Many oil tests in the Newark rift system have been encouraging. The data from these tests combined with data collected previously indicate that the geologic and geochemical criteria required to produce significant quantities of hydrocarbons have been met in several of the basins. Most of the wells drilled heretofore were not positioned using specific geologic or geophysical data. In fact, the industry only recently recognized the play as viable and has applied geophysical techniques to the search for potential hydrocarbon-bearing structural or stratigraphic traps. This activity has partially revealed the geologic processes involved in the development of the basins. The Sanford basin of North Carolina, for example, is a simple half graben, whereas the Richmond basin of Virginia seems to be more complex structurally and may have been affected more by wrench tectonics, producing structures similar to those found in the lake basins of the East Africa rift system. Each basin's hydrocarbon migration history, however, cannot be fully documented at this embryonic stage of exploration. It is, therefore, necessary to continue to build the geophysical, geological, and geochemical data bases until a well-substantiated model of the migration history can be established. The migration history together with the tectonic evolution of the basin enhances the chances of finding where hydrocarbons are presently trapped. Currently, prospects are being evaluated in several basins. There is a reasonable chance that reserves will be found. At the very least, the wells will aid the exploration effort and refine the exploration theories. End_of_Article - Last_Page 1452------------

THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION

The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.

ON THE THEORY OF GROWTH FAULTING*: A GEOMECHANICAL DELTA MODEL BASED ON GRAVITY SLIDING

A geomechanical delta model is presented that explains and permits quantitative reproduction of the main features associated with growth faulting. The model is based on a soil‐plasticity analysis of gravity sliding of overpressured clays and silts on very gentle delta slopes. In this analysis, the packets involved in gravity sliding —called ‘units’—are well quantified. The delta body may behave as a stack of such units (‘multi‐unit’ delta model), which can behave differently depending on such parameters as sedimentation rates, changes in lithology and compactional behaviour. Two prominent and essentially different structural expressions of the model are discussed: (a) the regularly spaced growth‐fault pattern, without recognisable toe regions; (b) the complete slide structure with a well‐developed toe region. The shapes of the roll‐over structures (particularly the positions of the crests), the thickening of the layers near the growth faults, antithetic faulting and horsetailing of growth faults can be derived from the model without the need to invoke any deeper seated mechanism in the substratum. The basic assumptions of this geomechanical model are supported by observations in Ireland and examples from literature. It may contribute to the reconstruction of the hydrocarbon migration history in a delta by accounting for the synsedimentary development of stresses and fault structures that may control hydrocarbon migration. Recently, geomechanical aspects came in focus again for the assessment of seismic amplitude anomalies in the search for hydrocarbons (Crans and Berkhout, 1979).