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

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

Hydrocarbon Retention and the Case for Vertical Migration

Complex hydrocarbon charging and distribution in which reservoirs are filled by oil and gas phases with different densities and genetic types inter-fingering within the basin, are common phenomena, and often attributed to vertical migration. This paper discusses the factors that control vertical hydrocarbon migration and presents modelling of the hydrocarbon charging and entrapment history in a tertiary basin in Southeast Asia as a case study. According to the Young-Laplace flow theory of the secondary hydrocarbon migration mechanics, migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. In this study, the invasion percolation simulation algorithm, based on the Young-Laplace flow, was used. During the simulation, three-dimensional (3D) seismic data were used as the high-resolution base grid for migration to capture the effect of both structure and facies heterogeneities on fluid flow. A model of an unfaulted system was presented to make the case. In the study area there is inter-fingering between oil and gas across different formations; most oils are trapped in the deeper formation, oil and gas inter-fingering occurs in the middle formation, and the upper formation contains mostly gas. This arrangement is possible because of the interplay between the expelled fluid buoyancy and relatively weak intra-formational seals within the basin. The modeling results were then calibrated to known accumulations or fluid presence in wells. In a basin dominated by a vertical migration regime, hydrocarbons are prevented from travelling far from the kitchen, thus decreasing prospectivity away from the kitchen. Through a case study, this paper helps to understand the factors that influence hydrocarbon retention and migration that control fluid distribution within a basin. Eventually the study helps geologists to understand prospectivity risking related to hydrocarbon charging, which is one of the main risks in exploration especially in mature basins.

Using Basin Modelling to Understand Injected CO2 Migration and Trapping Mechanisms: A Case Study from the Sleipner CO2 Storage Operation

CO2 migration and trapping in saline aquifers involves the injection of a non-wetting fluid that displaces the in-situ brine, a process that is often termed ‘drainage’ in reservoir flow dynamics. With respect to simulation, however, this process is more typical of regional basin modelling and percolating hydrocarbon migration. In this study, we applied the invasion percolation method commonly used in hydrocarbon migration modelling to the CO2 injection operation at the Sleipner storage site. We applied a CO2 migration model that was simulated using a modified invasion percolation algorithm, based upon the Young-Laplace principle of fluid flow. This algorithm assumes that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy (driving) and capillary (restrictive) forces. Entrapment occurs when rock capillary threshold pressure exceeds fluid buoyancy pressure. Leaking occurs when fluid buoyancy pressure exceeds rock capillary threshold pressure. This is now widely understood to be an accurate description of basin-scale hydrocarbon migration and reservoir filling. The geological and geophysical analysis of the Sleipner CO2 plume anatomy, as observed from the seismic data, suggested that the distribution of CO2 was strongly affected by the geological heterogeneity of the storage formation. In the simulation model, the geological heterogeneity were honored by taking the original resolution of the seismic volume as the base grid. The model was then run at an ultra-fast simulation time in a matter of seconds or minutes per realization, which allowed multiple scenarios to be performed for uncertainty analysis. It was then calibrated to the CO2 plume distribution observed on seismic, and achieved an accurate match. The paper establishes that the physical principle of CO2 flow dynamics follows the Young-Laplace flow physics. It is then argued that this method is most suitable for the regional site screening and characterization, as well as for site-specific injectivity and containment analysis in saline aquifers.

The Influence of Faulting on Hydrocarbon Migration in the Kupe Area, South Taranaki Basin, New Zealand

<p>Faults play an important role in petroleum systems as both barriers and conduits to the flow of hydrocarbons. An understanding of the relationship between fluid and gas migration and accumulation, and faulting is often required during hydrocarbon exploration and production, and CO2 storage. While methods for predicting across-fault flow are well advanced (e.g. Yielding et al., 1997; Manzocchi et al., 1999), current geomechanical and geometrical methods for predicting the locations of up-fault (up-dip) hydrocarbon migration (and leakage) are relatively untested. This thesis investigates the relationships between up-sequence gas migration in the form of gas chimneys and Pliocene to Recent normal faults in the Kupe Area, South Taranaki Basin. It undertakes studies of the Kupe Area’s structural development, examines spatial relationships between faults and gas chimneys, tests current geomechanical and geometrical models to predict up-dip gas flow in faults, and investigates the outcrop expression of fault structure below seismic reflection data resolution and gas flux rates at an onshore site of fault-related gas leakage. Data for this study are provided by highquality 2D and 3D seismic reflection lines (tied to stratigraphy in fifteen wells), and outcrop of Miocene and Oligocene strata in coastal cliff sections, together with methane concentration and flux measurements. Structural development in the Kupe Area was complex and provides a near complete record of deformation since the Late Cretaceous (~85 Ma). Basin strata up to 9 km thick record four main periods of deformation that reflect changing plate boundary configurations. Fault reactivation was common in the Kupe Area, with the locations and orientations of pre-existing faults strongly influencing the locations and geometries of younger faults and folds. Pliocene to Recent normal faults are highly segmented with low strain, consistent with an immature fault system in which fault lengths were established rapidly and subsequent fault growth was mainly achieved by accumulation of displacement. Plio-Pleistocene to Recent reactivation of Cretaceous rift faults provides conduits for gas migration from below the regional top seal in the Kupe Area into shallow strata and results in up-dip gas migration within the Plio-Pleistocene to Recent fault zones. These late-stage normal faults (younger than 4 Ma) are shown to have a strong spatial relationship with gas chimneys suggesting that fault zones are capable of producing channelised pathways for up-dip hydrocarbon migration. Fifteen of seventeen gas iii chimneys within the study area are rooted within fault zones. All of these fifteen faultrelated gas chimneys occur at geometrical complexities in fault structure (i.e. relay zones, lateral fault tips or fault intersections). Geometrical complexities are associated with locally high throw gradients which are inferred to be accompanied by off-fault strain in the form of fractures and/or bedding rotation. Three geomechanical modelling techniques (Slip Tendency, Dilation Tendency and Fracture Stability) for predicting the locations of up-fault hydrocarbon flow (leakage) are tested using the spatial distribution of gas chimneys and Pliocene to Recent normal faults in the Kupe Area. Slip Tendency, Dilation Tendency and Fracture Stability data for all of the faults analysed predict comparable likelihoods of gas migration on chimney and non-chimney sections of the fault surfaces and therefore do not provide a robust basis for predicting where on fault surfaces channelised up-dip gas flow will occur. Field-based observations of faults show that fractures observed in outcrop and below seismic reflection data resolution are localised around bends, steps and intersections of faults and show evidence of fluid flow post fault activity. In north Taranaki these fault complexities are present in a lateral equivalent to the Otaraoa top seal and, if present in the Kupe Area, are also likely to induce up-sequence gas migration through fracture networks. Methane concentrations measured at one site (Bristol Road Quarry) along the Inglewood Fault suggest that gas flux rates up faults may not be uniform over time. Based on the measured gas flux rates gas chimneys in the Kupe Area may form in association with gas migration in a series of discrete events lasting from days to years, with possible gas flows at the seabed of ~930 ft3 per chimney per day or 0.34 million ft3 per year.</p>

The Influence of Faulting on Hydrocarbon Migration in the Kupe Area, South Taranaki Basin, New Zealand

<p>Faults play an important role in petroleum systems as both barriers and conduits to the flow of hydrocarbons. An understanding of the relationship between fluid and gas migration and accumulation, and faulting is often required during hydrocarbon exploration and production, and CO2 storage. While methods for predicting across-fault flow are well advanced (e.g. Yielding et al., 1997; Manzocchi et al., 1999), current geomechanical and geometrical methods for predicting the locations of up-fault (up-dip) hydrocarbon migration (and leakage) are relatively untested. This thesis investigates the relationships between up-sequence gas migration in the form of gas chimneys and Pliocene to Recent normal faults in the Kupe Area, South Taranaki Basin. It undertakes studies of the Kupe Area’s structural development, examines spatial relationships between faults and gas chimneys, tests current geomechanical and geometrical models to predict up-dip gas flow in faults, and investigates the outcrop expression of fault structure below seismic reflection data resolution and gas flux rates at an onshore site of fault-related gas leakage. Data for this study are provided by highquality 2D and 3D seismic reflection lines (tied to stratigraphy in fifteen wells), and outcrop of Miocene and Oligocene strata in coastal cliff sections, together with methane concentration and flux measurements. Structural development in the Kupe Area was complex and provides a near complete record of deformation since the Late Cretaceous (~85 Ma). Basin strata up to 9 km thick record four main periods of deformation that reflect changing plate boundary configurations. Fault reactivation was common in the Kupe Area, with the locations and orientations of pre-existing faults strongly influencing the locations and geometries of younger faults and folds. Pliocene to Recent normal faults are highly segmented with low strain, consistent with an immature fault system in which fault lengths were established rapidly and subsequent fault growth was mainly achieved by accumulation of displacement. Plio-Pleistocene to Recent reactivation of Cretaceous rift faults provides conduits for gas migration from below the regional top seal in the Kupe Area into shallow strata and results in up-dip gas migration within the Plio-Pleistocene to Recent fault zones. These late-stage normal faults (younger than 4 Ma) are shown to have a strong spatial relationship with gas chimneys suggesting that fault zones are capable of producing channelised pathways for up-dip hydrocarbon migration. Fifteen of seventeen gas iii chimneys within the study area are rooted within fault zones. All of these fifteen faultrelated gas chimneys occur at geometrical complexities in fault structure (i.e. relay zones, lateral fault tips or fault intersections). Geometrical complexities are associated with locally high throw gradients which are inferred to be accompanied by off-fault strain in the form of fractures and/or bedding rotation. Three geomechanical modelling techniques (Slip Tendency, Dilation Tendency and Fracture Stability) for predicting the locations of up-fault hydrocarbon flow (leakage) are tested using the spatial distribution of gas chimneys and Pliocene to Recent normal faults in the Kupe Area. Slip Tendency, Dilation Tendency and Fracture Stability data for all of the faults analysed predict comparable likelihoods of gas migration on chimney and non-chimney sections of the fault surfaces and therefore do not provide a robust basis for predicting where on fault surfaces channelised up-dip gas flow will occur. Field-based observations of faults show that fractures observed in outcrop and below seismic reflection data resolution are localised around bends, steps and intersections of faults and show evidence of fluid flow post fault activity. In north Taranaki these fault complexities are present in a lateral equivalent to the Otaraoa top seal and, if present in the Kupe Area, are also likely to induce up-sequence gas migration through fracture networks. Methane concentrations measured at one site (Bristol Road Quarry) along the Inglewood Fault suggest that gas flux rates up faults may not be uniform over time. Based on the measured gas flux rates gas chimneys in the Kupe Area may form in association with gas migration in a series of discrete events lasting from days to years, with possible gas flows at the seabed of ~930 ft3 per chimney per day or 0.34 million ft3 per year.</p>