Xiaorong Luo

Overpressuring mechanisms in the Yinggehai Basin, South China Sea

Yinggehai Basin is an elongate Cenozoic rift basin on the northwestern margin of the South China Sea continental shelf. Its thick (17 km) basin fill is characterized by high geothermal gradient and high overpressure. Overpressure associated with nonequilibrium compaction mainly occurs at depths more than 2800 m at the basin center and more than 4000 m at the basin margin because the shallow-buried Neogene and Quaternary strata lack effective seals. This regional overpressure distribution, however, is disrupted at basin center where high overpressure occurs in permeable formations at a depth as shallow as 1400 m on top of a series of deep-seated faults and fractures. We studied the processes and mechanisms of overpressuring via numerical modeling that couples basin filling, sediment compaction, and thermal and pressure fields to approach the origin of the shallow high overpressure. Model results indicated that an increase of fluid volume due to natural-gas generation by organic cracking is not large enough to generate the overpressure because of the limited amount of organic matter. The shallow overpressure has probably been generated allogenically. Deep open faults have served as vertical hydraulic conduits and channeled the deep high pressure into shallow permeable formations.

Overpressure generation and evolution in a compressional tectonic setting, the southern margin of Junggar Basin, northwestern China

Overpressure is widespread in the southern margin of the Junggar Basin, northwestern China. Pressure measurements in drillstem tests and repeated formation tests and estimates from wire-line logs indicate contrasting overpressure values between permeable sandstones and adjacent low-permeability mudrocks. In addition, excess pressure differs among anticlines with similar depth, lithologies, and geologic age, indicating significant lateral changes of overpressure. Major factors controlling overpressure generation and distribution include rapid sediment deposition, pressure compartmentalization by thick mudrocks, tectonic stress, faulting, and folding. Clay transformation and hydrocarbon generation are believed to be insignificant in overpressure generation in the southern Junggar Basin. Numerical modeling of pressure generation and evolution suggests that faulting and stratal tilting associated with folding are the most significant factors in the overpressure generation of a permeable sandstone. The extremely high overpressure (pressure coefficient up to 2.43) may have been caused by hydraulic adjustment within permeable sandstones associated with structural deformation caused by post-Miocene intense tectonic activities.

Elastoplastic deformation of porous media applied to the modelling of compaction at basin scale

Abstract For simulation and modelling of coupled phenomena occurring during basin evolution, the mechanical aspects of rock deformation are generally restricted to vertical compaction characterized by a simple relation between the effective vertical stress and the rock porosity. Elasto-plasticity leads to a more general formulation which, in principle, allows for the calculation of horizontal deformation and stress field. Various aspects of this application of continuum mechanics to the compaction of sedimentary rocks at basin scale are presented. Firstly, the problems of mechanical deformation and of fluid flow—or pressure evolution—are shown to be intimately coupled through the effective stress concept. The elasto-plastic Cam-Clay rheology is recalled as a satisfactory approach of the stress-strain relationship for fine-grained sediments. This gives the complete bases for numerical modelling of the hydro-mechanical problems related to sedimentary basin evolution. Secondly, two numerical codes which are of standard use in civil engineering problems are tentatively applied to basin modelling. The first code (CESAR) is a finite element one which fully takes into account the hydro-mechanical couplings. The slow sedimentation process, whereby the geological structure is progressively built, can be accounted for by incremental deposition of layers. In practice the computation is so time-consuming that only restricted simulation on existing sedimentary structure can be seriously considered. A second computer code (FLAC) based on finite difference method is then applied. Some special development makes it possible to account for the geometrical evolution (build-up) of a basin and some cases studies are presented to show the importance of lateral deformation during the development of a margin-type basin. However these possibilities were obtained at the expense of a fixed fluid pressure field and we did not succeed in coupling the hydraulical and mechanical computations. Thirdly, a simple incremental mechanical model is proposed for completely solving the coupled hydro-mechanical problem in the case of progressive sedimentation. A numerical solution is obtained in the 1-D case and gives results which are consistent with some published ones. Since it is 1-D, this solution offers only a few advantageous features at present. However generalization to several dimensions can be imagined.

Simulation and characterization of pathway heterogeneity of secondary hydrocarbon migration

Carriers are important links between sources and traps for hydrocarbon migration and accumulation in a petroleum system. Oil and gas commonly migrate along narrow and irregular pathways in porous media, even in macroscopically homogeneous media. A migration simulator based on the invasion-percolation theory, which couples the buoyancy of a hydrocarbon column as the driving force with capillary pressure as the resisting force, satisfactorily explains migration processes in heterogeneous media. In macroscopically homogeneous carriers, migration pathways are generally perpendicular to equipotential lines, but locally, the pathways can be irregular because of the influence of microscopic heterogeneity. The degree of irregularity of these pathways depends on the difference between competing driving and resisting forces. When numerous pathways form in a migration-accumulation system, the flux of migrating hydrocarbons may vary among these pathways. In macroscopically heterogeneous carriers, the irregularity of migration pathways is exacerbated. When the driving force is relatively weak, hydrocarbons tend to migrate in carriers where the hydraulic conductivity is relatively large. These pathways differ from those predicted only on the basis of flow potential. Simulation of the migration process in the Middle Jurassic carrier beds of the Paris Basin demonstrates the characteristics of the migration simulator in the analysis of migration pathway heterogeneity. Results are comparable to or superior to those achieved with previous simulation approaches.

Natural hydraulic cracking: numerical model and sensitivity study

Abstract Natural hydrofracturing caused by overpressure plays an important role in geopressure evolution and hydrocarbon migration in petroliferous basins. Its mechanism is quite well understood in the case of artificial hydraulic fracturing triggered by high-pressure fluid injection in a well. This is not so for natural hydraulic fracturing which is assumed to initiate as micro-cracks with large influence on the permeability of the medium. The mechanism of natural hydraulic cracking, triggered by increasing pore pressure during geological periods, is studied using a fracturing model coupled to the physical processes occurring during basin evolution. In this model, the hydraulic cracking threshold is assumed to lie between the classical failure limit and the beginning of dilatancy. Fluid pressure evolution is calculated iteratively in order to allow dynamic adjustment of permeability so that the fracturing limit is always preserved. The increase of permeability is interpreted on the basis of equivalent fractures. It is found that fracturing is very efficient to keep a stress level at the rock’s hydraulic cracking limit: a fracture permeability one order of magnitude larger than the intrinsic permeability of the rock would be enough. Observations reported from actual basins and model results strongly suggest that natural hydraulic cracking occurs continuously to keep the pressure at the fracturing limit under relaxed stress conditions.

Quantitative evaluation of synsedimentary fault opening and sealing properties using hydrocarbon connection probability assessment

Hydraulic behaviors of faults in sedimentary basins have been paid close attention in studies of hydrocarbon migration and accumulation because of their important functions in basin hydraulic circulations. In previous studies, however, the function of faults in hydrocarbon migration is characterized by the sealing capacity of faults. In fact, sealing is only an impressive and time-dependent aspect of the hydraulic behavior of faults, which may act as seals during some periods and as pathways some time later. Therefore, in hydrocarbon migration studies, sealing indices may successfully be used in some cases but not in others. In this article, we introduce an empirical method (termed the fault-connectivity probability method) for assessing the hydraulic connecting capacity of a fault for hydrocarbon migration over geological time scales. The method is based on the recognition that observable hydrocarbon in reservoirs should result from the opening and closing behavior of the fault during the entire process of hydrocarbon migration. In practice, the cumulative petroleum migration through a segment of the fault zone is identified by the presence (or not) of hydrocarbon-bearing layers on both sides of the segment. Data from the Chengbei step-fault zone (CSFZ) in the Qikou depression, Bohai Bay Basin, northeast China, were used to develop this method. Fluid pressure in mudstones, normal stress perpendicular to fault plane, and shale gouge ratio are identified as the key factors representing fault-seal capacity. They are combined to define a nondimensional fault opening index (FOI). The values of FOI are calculated from the measured values of the key factors, and the relationship between FOI and fault-connectivity probability on any fault segment is established through statistical analysis. Based on the data from the CSFZ, when the FOI is less than 0.75, the fault-connectivity probability is 0; when FOI ranges from 0.75 to 3.25, the corresponding fault-connectivity probability increases from 0 to 1 following a quadratic polynomial relationship; when FOI is greater than 3.25, the fault-connectivity probability is 1. The values of fault-connectivity probability can be contoured on a fault plane to characterize the variations of hydraulic connective capacity on the fault plane. The applicability of this concept for other oil fields (in particular, the quantitative relationship between FOI and fault-connectivity probability) has still to be ascertained.

An experimental study of secondary oil migration in a three-dimensional tilted porous medium

A three-dimensional physical experiment was conducted to study secondary oil migration under an impermeable inclined cap. Light-colored oil was released continuously at a slow rate of about 0.1 mL/min from a point at the base of an initially water-saturated porous model. With buoyancy as a primary driving force, a vertical cylindrical shape of an oil migration pathway was observed first, and then a layer-shaped lateral migration pathway was observed beneath the top inclined sealing plate once the oil cluster had reached the top cap. Magnetic resonance imaging was used to observe the migration processes—for example, morphology of the migration pathway, intermittency of oil bubbles, and variation of oil saturation within the migration paths. Results show that the snap-off phenomenon (related to fast local imbibition processes) occurred more commonly during vertical migration than it did during lateral migration. The lateral migration pathway that parallels to the top inclined cap has a typical vertical thickness of 2 to 4 cm (0.8–1.6 in.) (i.e., roughly 40–80 pores). This thickness is consistent with the prediction derived from scaling laws related to pore size and Bond number. Along the lateral migration direction, the sectional area and the horizontal width of the migration pathway fluctuate significantly, although the average oil saturation along the pathway remains almost the same. After stopping the initial oil injection, the sectional area of the migration pathway shrinks significantly. Therefore, we believe that this significant shrinking of the migration pathway is the main reason why only a relatively small volume of oil and gas has been lost during secondary migration.

Dynamics of hydrocarbon accumulation in the west section of the northern margin of the Qaidam Basin, NW China

Abstract Studies were conducted on the dynamic processes of hydrocarbon migration and accumulation in the west part of the northern margin of the Qaidam Basin, based on previous studies on basin evolution and hydrocarbon system. Based on the dynamics of petroleum accumulation, basin analysis and the numerical stimulation method were applied to reconstruct the basin evolution. Simulation analysis of petroleum accumulation in the main reservoir-forming stages were conducted in the light of source rock properties in different stages, fluid potential field and seepage property distribution of carrier beds. Controlling factors of reservoir formation in the northern margin of the Qaidam Basin were summarized. Studies showed that the Miocene is the main period of oil generation for the Jurassic source rocks in the studied area. The oil generation and migration volume were large. However, Saishiteng Sag was just on the slope in the northern part of Yiliping Sag. Structural traps were distributed at the margin of the basin. There was abundant oil migration to the north margin and a dissipation of the oil there during the later strong tectonic activities. During the late reservoir formation stage after the Pliocene, the source rocks generated mainly gas and not oil, and structural traps were well developed and provided good conditions for the natural gas reservoir formation. Deep structural traps in the basins were conducive to the formation of a large-scale low-permeability gas reservoir.

Identification and distribution of fractures in the Zhangjiatan shale of the Mesozoic Yanchang Formation in Ordos Basin

AbstractThe natural fractures in mud or shale directly affect the quality and efficiency of shale gas reservoirs, and fracture identification and prediction play an important role in drilling shale gas wells and making plans for reservoir stimulation. We adopted ant tracking technology for 3D poststack reflective seismic waves to identify the size and distribution of high-angle structural fractures in the Zhangjiatan shale of the Yanchang Formation in the Ordos Basin, which is a typical continental shale. The parameters for ant tracking fractures are extracted from the investigation on outcrop, cores, and image logs. The prestack seismic diffractive wave imaging technique for the super-resolution identification of mid- and small-scale breakpoints can be used as the constraint conditions for ant tracking. The identified result of high-angle fractures was validated by the image logging and drilling gas logging results. The geologic and logging data indicate that the Zhangjiatan shale is mainly characterized...

Diagenesis and Fluid Flow Variability of Structural Heterogeneity Units in Tight Sandstone Carrier Beds of Dibei, Eastern Kuqa Depression

Tight sand gas plays an important role in the supply of natural gas production. It has significance for predicting sweet spots to recognize the characteristics and forming of heterogeneity in tight sandstone carrier beds. Heterogeneity responsible for spatial structure, such as the combination and distribution of relatively homogeneous rock layers, is basically established by deposition and eodiagenesis that collectively affect the mesogenesis. We have investigated the structural heterogeneity units by petrofacies in tight sandstone carrier beds of Dibei, eastern Kuqa Depression, according to core, logging, and micropetrology. There are four types of main petrofacies, that is, tight compacted, tight carbonate-cemented, gas-bearing, and water-bearing sandstones. The brine-rock-hydrocarbon diagenesis changes of different heterogeneity structural units have been determined according to the pore bitumen, hydrocarbon inclusions, and quantitative grain fluorescence. Ductile grains or eogenetic calcite cements destroy the reservoir quality of tight compacted or tight carbonate-cemented sandstones. Rigid grains can resist mechanical compaction and oil emplacement before gas charging can inhibit diagenesis to preserve reservoir property of other sandstones. We propose that there is an inheritance relationship between the late gas and early oil migration pathways, which implies that the sweet spots develop in the reservoirs that experienced early oil emplacement.