Likuan Zhang

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.

A quantitative method for characterizing transport capability of compound hydrocarbon carrier system

The occurrence of hydrocarbon migration in petroliferous basins depends on the balance of driving force and resistance of carriers, which restricts mostly the quantity and positions of hydrocarbon accumulation. The driving forces of hydrocarbon migration have been quantitatively studied, whereas the migration pathways and carriers were only qualitatively discussed up to now. Establishing a compound hydrocarbon carrier system and quantitatively characterizing its transport capability are significant for understanding the dynamic process of hydrocarbon migration and revealing the hydrocarbon accumulation characteristics. It has become an innovatory trend and also a difficult topic in study of hydrocarbon migration. In this article, a method is described for using displacement pressure to quantitatively characterize the transport capability of the compound carrier system, which composed of sandstone carriers, unconformities and faults. When the weathered and leached zone rarely developed, the basal conglomerate or transgressive sandstone of unconformities can be treated as part of sandstone carriers. An empirical relationship among core porosity, air permeability, and the pore aperture radius corresponding to a mercury saturation of 10% (r10) can be obtained by multiple regression. Using porosity and permeability inversed by seismic data, the displacement pressure of sandstone carriers can be calculated by the empirical relationship and Washburn Equation. Displacement pressure of fault plane can be estimated by the regression formula between fault opening index (FOI) and hydrocarbon column height it can support. This method is applied in the eastern part of south slope in Dongying (东营) depression, Bohai (渤海) Bay Basin, China, to quantitatively characterize the transport capability of the compound carrier system of Shahejie (沙河街) Formation. The results have good agreement with data from drilling wells. This method may be a step further in study of compound hydrocarbon carrier system in petroliferous basins. It may provide the basis of coupling expulsion quantity, migration driving force and hydrocarbon carrier system to simulate hydrocarbon migration and accumulation. Therefore this will help predict hydrocarbon migration pathways and the locations of hydrocarbon accumulation.

An experimental study of oil secondary migration in a three dimensional porous space

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.

Study on the distribution of extractable organic matter in pores of lacustrine shale: An example of Zhangjiatan Shale from the Upper Triassic Yanchang Formation, Ordos Basin, China

AbstractShale oil and gas have been discovered in the lacustrine Zhangjiatan Shale in the southern Ordos Basin, China. To study the distribution of extractable organic matter (EOM) in the Zhangjiatan Shale (Ro ranges from 1.25% to 1.28%), geochemical characterization of core samples of different lithologies, scanning electron microscope observations, low-pressure N2 and CO2 adsorption, and helium pycnometry were conducted. The content and saturation of the EOM in the pores were quantitatively characterized. The results show that the distribution of the EOM in the shale interval is heterogeneous. In general, the shale layers have a higher EOM content and saturation than siltstone layers. The total organic content and the original storage capacity control the EOM content in the shale layers. For the siltstone layers, the EOM content is mainly determined by the original storage capacity. On average, 75% of the EOM occurs in the mesopores, followed by 14% in the macropores, and 11% in the micropores. The EOM ...

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.

Diagenetic Heterogeneity of Deep Sandstones and Its Relationship to Oil Emplacement: A Case Study from the Middle Jurassic Toutunhe Formation in the Fukang Sag, Central Junggar Basin (NW China)

The Middle Jurassic Toutunhe Formation at depths of approximately 4000–6000 m has increasingly come into focus as a current deep reservoir target in the central Junggar Basin (NW China). Based on petrography, SEM, stable isotopes, and fluid inclusion analyses, the goals of this study were to investigate the effect of depositional lithofacies on sandstone diagenetic heterogeneity and to examine the relationship between diagenetic evolution and oil charge within a heterogeneous reservoir. Grain size controls the overall abundance of cement and porosity and reservoir properties through its effect on ductile lithic sand grains and hence on mechanical compaction. Early diagenetic calcite cement is an exception to this trend. Ductile lithic-rich, very fine-grained sandstones featured compaction of easily deformed, clay-rich grains, resulting in a very rapid loss of porosity during burial. In contrast, dissolution and cementation occurred as well as ductile compaction in the fine-grained sandstones. Two episodes of oil charge occurred in the relatively coarser-grained sandstone lithofacies. Diagenesis progressed alternately with oil emplacement, and some diagenetic alterations and oil charge occurred simultaneously. Ductile lithic-rich, highly compacted sandstones and tightly calcite-cemented sandstones can create permeability barriers embedded in permeable reservoir sandstones, probably resulting in heterogeneous flow.

Geometry, kinematics and dynamic characteristics of a compound transfer zone: the Dongying anticline, Bohai Bay Basin, eastern China

Abstract The Dongying anticline is an E-W striking complex fault-bounded block unit which located in the central Dongying Depression, Bohai Bay Basin. The anticline covers an area of approximately 12 km2. The overlying succession, which is mainly composed of Tertiary strata, is cut by normal faults with opposing dips. In terms of the general structure, the study area is located in a compound transfer zone with major bounding faults to the west (Ying 1 fault) and east (Ying -8 and -31 faults). Using three-dimensional seismic data, wireline log and checkshot data, the geometries and kinematics of faults in the transfer zone were studied, and fault displacements were calculated. The results show that when activity on the Ying 1 fault diminished, displacement was transferred to the Ying -8, Ying -31 and secondary faults so that total displacement increased. Dynamic analysis shows that the stress fields in the transfer zone were complex: the northern portion was a left-lateral extensional shear zone, and the southern portion was a right-lateral extensional shear zone. A model of potential hydrocarbon traps in the Dongying transfer zone was constructed based on the above data combined with the observed reservoir rock distribution and the sealing characteristics of the faults. The hydrocarbons were mainly expulsed from Minfeng Sag during deposition periods of Neogene Guantao and Minghuazhen Formations, and migrated along major faults from source kitchens to reservoirs. The secondary faults acted as barriers, resulting in the formation of fault-bound compartments. The high points of the anticline and well-sealed traps near secondary faults are potential targets. This paper provides a reservoir formation model of the low-order transfer zone and can be applied to the hydrocarbon exploration in transfer zones, especially the complex fault block oilfields in eastern China.

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

Characterization of Fault Opening for Hydrocarbon Migration

In order to characterize the sealing capacity of faults during hydrocarbon migration most studies use sealing indexes based on one or two parameters. However, these indexes, may successfully used in some areas but not in others, since fault sealing is the consequence of many geological processes that cannot be simply described by so few factors. We present an empirical method (termed fault-connectivity probability method) for assessing the long-term sealing capacity of a fault for hydrocarbon migration. This method is based on the observational evidence of the opening or closing behavior of the fault during the entire process of hydrocarbon migration. In practice, petroleum leakage through an element of fault is identified by the existence (or not) of hydrocarbon-bearing layers on both sides of this element. The data from the Wangjiagang Oil Field in the South Slope of the Dongying Depression in the Jiyang Sub-basin in Bohai Bay Basin, NE China, are used to develop this method. Fluid pressure in mud-rocks, normal stress perpendicular to fault plane, and clay smear are identified as the key factors representing fault seal capacity. They are combined to compose a non-dimensional Fault Opening Index, FOI. The values of FOI are calculated from the key factors measured on elements, and the relationship between FOI and fault-opening probability on any an element is established through a statistical analysis: when FOI is 3.5, the fault-opening probability is 1. Then, the values of fault-opening probability can be contoured on a fault plane, to characterize the variations of seal capacity on the fault plane.