Mahu Depression Research Articles

Identification of Milankovitch sedimentary cycle in Fengcheng Formation, Mahu depression: a case study of well Maye 1

The sedimentary cycle of Fengcheng Formation in Junggar Basin changes rapidly and is difficult to identify. The low classification accuracy of high-frequency fine-grained sedimentary cycles restricts the exploration of unconventional shale oil and gas. Full-interval coring of well Maye 1 provides a solid foundation for small-layer research. In this paper, the high-frequency sedimentary cycle of Milan kovitch in Fengcheng Formation is studied by means of spectral analysis and wavelet transform, and the shale sweet spot is identified. The long period of eccentricity of 405ka, short period of eccentricity of 100ka and long period of axis slope of 42736a can be used as semi-quantitative basis for the classification of the fourth, fifth and sixth sequences. The Fengcheng Formation can be divided into 2 quaternary sequence cycles, 9 quaternary sequence cycles and 16 quaternary sequence cycles. A long period of eccentricity of 405ka can identify large-scale lake recessional and recessional, and there is a maximum lake flooding surface in the middle of the second Fengcheng Formation, which corresponds to high abundance of organic matter and high hydrocarbon generation potential. The 100ka short period eccentricity can identify the sweet spot layer, and there are 8 sweet spots in the well Maye 1, which is consistent with the results of nuclear magnetic interpretation. The research results provide a semi-quantitative basis for the classification of high-frequency sedimentary cycles and the identification of sweet spots of Fengcheng Formation in Mahu Sag, Junggar Basin.

Geochemical Characteristic and Source Correlation of Biodegraded Oils from the Western Halaalate Area of Junggar Basin

The relationship between biodegraded oil and its source has long been a complex and contentious topic. The Western Halaalate area is located in the Piedmont area on the northwest margin of the Junggar Basin. Source rocks of the Fengcheng Formation exist both locally and in the nearby Mahu Depression. In order to determine the source of biodegraded crude oil in this area, the molecular marker characteristics of biodegraded crude oil were analyzed by gas chromatography-mass spectrometry. The results showed that the vitrinite reflectance (Ro) of source rocks of the Permian Fengcheng Formation in the nearby Mahu Depression is greater than 1.3% and has entered a high mature stage of condensate oil and moisture gas; the source rock of Permian Fengcheng Formation in Western Halaalate area is in a mature stage with Ro of 0.79%~1.13%. The ascending configuration of tricyclic terpenes C20-C21-C23 for the crude oil samples found in the Carboniferous strata of the Western Halaalate Area is consistent with the characteristics of the Fengcheng Formation source rocks, which are present in both the Western Halaalate Area and the nearby Mahu Depression. Chromatography spectrometry examination shows that crude oils have undergone a varying degree of biodegradation. The Carboniferous oil was originated from the in situ Fengcheng Formation source rocks based on the application of molecular markers resistant to biodegradation, such as maturity parameters, salinity parameters, the new gammacerane index, and aromatic hydrocarbon parameters, combined with the analysis of hydrocarbon migration pathway. In addition, the oil biodegradation alteration rules in the Western Halaalate area were clarified, which advances regional knowledge of the relationship between biodegraded oil and source rocks.

Effect of Ancient Salinity on the Distribution and Composition of Tricyclic Terpane in Hydrocarbon Source Rocks in the Mahu Depression

Ma2 and Ma3 hydrocarbon source rock samples from the Fengcheng Formation in well Maye 1, Mahu Depression, Junggar Basin, were studied using conventional geochemical analysis methods and saturated hydrocarbon gas chromatography–mass spectrometry. The distribution patterns, abundance, relative content, and ratios of different carbon compounds of tricyclic terpane in hydrocarbon source rocks from fresh-to-mildly-saline (type I), moderately saline (type II), and saline (type III) water environments significantly differed. The C28–C29TT/C30H and C19–C29TT/C30H ratios were the lowest in the type I hydrocarbon source rock. The relative ratios of C23TT/C21TT, C25TT/C24TT, C28TT/C26TT, (C23–C26TT)/(C19–C22TT), and (C28–C29TT)/(C19–C22TT) gradually increased with the increase in the salinity of the hydrocarbon source rock. The percentage of low-carbon tricyclic terpanes gradually decreased to 28%, whereas those of the medium- and high-carbon tricyclic terpanes increased to 52% and 20%, respectively. The differences in triterpane types of different hydrocarbon source rocks were mainly controlled by the depositional environment. The primary factor that controlled the distribution pattern; relative abundance, especially the high carbon tricyclic terpane content; and differences in the relative ratio of different carbon compounds in different hydrocarbon source rocks was the salinity of the ancient waterbody during deposition.

Microscopic pore-throat classification and reservoir grading evaluation of the Fengcheng formation in shale oil reservoir

Different basins in China have proposed various reservoir grading standards for shale oil. Based on a comprehensive understanding of the basic characteristics of the shale oil reservoir in the Mahu Depression, this paper uses data from high-pressure mercury injection, physical properties, nuclear magnetic resonance, depletion development, and CO2 displacement development tests to analyze the microscopic pore structure features of the Fengcheng Formation shale oil reservoir. On this basis, the classification boundaries of the pore throats in the shale oil reservoir were analyzed, and a reservoir grading standard suitable for the Fengcheng Formation shale was proposed: large pore throats (greater than 1000 nm), medium pore throats(100∼1000 nm), small pore throats (20∼100 nm), and ultra-small pore throats (less than 20 nm). The medium pore throat is the lower limit for depletion development, the small pore throat is the lower limit under CO2 displacement conditions, and the ultra-small pore throat cannot be utilized under current conditions. The classification effect of the shale oil reservoir is verified using the production characteristics of Well MY1, the liquid production profile, and the results of geological "sweet spots" studies. The results show that the classification scheme for the microscopic pore throats of the Fengcheng Formation shale oil is reliable and feasible.

The Reservoir Sensitivity of Triassic Baikouquan Formation in Mahu Depression

The Triassic Baikouquan Formation in the slope area of the Mahu Depression is the largest glutenite reservoir in the Junggar Basin, with low porosity and permeability; however, its physical properties are poor, the distribution of oil and gas is quite different, and the output fluctuates greatly. It is of great guiding significance to study the sensitivity characteristics of the reservoir for oil and gas development and productivity design. In this paper, the reservoir of the Triassic Baikouquan Formation in the Mahu Depression of Junggar Basin is taken as the research object, and the geological characteristics, pore structure characteristics and clay mineral characteristics of the reservoir are investigated through the use of X-ray diffraction and scanning electron microscope; moreover, the sensitivity of velocity, water, salt and stress of the reservoir are studied through the use of a sensitive flow test. The research results show that the lithology of the reservoir is mainly glutenite, composed of tuff and metamorphic mudstone, and the minerals are mainly Yimeng mixed-layer clay minerals, with fine particle size, average porosity of 10.5% and an average permeability of 9 × 10−4 μ m2, forming pore structures such as dissolved pores, cemented pores and intergranular gaps, which belong to the poor pore structure reservoir with low porosity and low permeability. The velocity-sensitive damage rate of reservoirs in the study area is between 4 and 46, and the reservoirs are moderately weak and poor in velocity sensitivity. The damage rate of the reservoirs’ water sensitivity in the study area is between 36 and 58, which can be defined as medium–weak and medium–strong water sensitivity. The reservoir in the study area contains clay minerals in a Yimeng mixed layer, which easily hydrate and swell, and the clay minerals in different parts of the Yimeng mixed layer are different, resulting in great differences in salt sensitivity at different depths. The maximum permeability damage rate of the reservoir is 80%, the irreversible permeability damage rate is 20%, and the stress sensitivity is weak. The research results provide theoretical data support for adopting targeted reservoir protection measures in the process of oil and gas exploration, development and construction.

Establishment and Application of a New Parameter Model for Quantitative Characterization of the Heterogeneity of Thick, Coarse-Grained Clastic Reservoirs: A Case Study of the Badaowan Formation in the Western Slope of the Mahu Depression, Junggar Basin, China

The rock composition of thick-layer, coarse-grained clastic reservoirs is complex. There are large variations in granularity and poor selectivity. Reservoirs of thick-layer, coarse-grained clastic rocks are extremely heterogeneous. Current conventional parameters for quantitative characterization of reservoir heterogeneity, such as the calculation values of the permeability variation coefficient, the permeability rush coefficient, and the permeability contrast, are unbounded, have different representation angles, and the quantification degree of the characterization method is not high. This study takes the thick layer of the coarse-clastic rock reservoir developed in the western slope of the Badaowan Formation in the Mahu Depression of the Junggar Basin as an example. Through core observation, microscopic characteristics, and analysis of laboratory data, a new quantitative characterization parameter of heterogeneity is proposed, and a reservoir interpretation parameter model is established. The results were as follows. (1) The pore development of the thick, coarse-grained clastic rock reservoir is complicated, the sorting and pore structure are poor, the reservoir heterogeneity is strong, and the permeability has double peaks. (2) We propose a new parameter to evaluate reservoir heterogeneity: the fluctuation a coefficient. This essentially compares the average permeability of two adjacent layer sites with the average permeability. The fluctuation coefficient can reflect the fluctuations in permeability, and the larger the fluctuation coefficient, the stronger the heterogeneity. In addition, it has the advantages of a clear characterization target, bounded calculation data, and the same characterization angle, etc., thereby realizing the quantitative characterization of the macro degree of reservoir heterogeneity under a unified standard. (3) This parameter was used to evaluate the reservoir heterogeneity of the Badaowan Formation in the western slope of the Mahu Depression. Most wells in the study area had a fluctuation coefficient of about 0.3, but others ranged between 0.2 and 0.6. It is concluded that the larger the fluctuation coefficient of the study area, the better the oil content because these types of reservoirs have strong heterogeneity. The fluctuation coefficient can effectively reflect the strength of the heterogeneity and can also provide a reference for further reservoir enrichment research.

Sedimentary Microfacies and Sand Body Characteristics at Segment 2 of the Sangonghe Formation in Oilfield A on the South Slope District of the Mahu Depression

The South Slope District of the Mahu Depression in the Junggar Basin, a major favorable zone for middle and superficial oil–gas exploration, has experienced industrial gas flow. However, research on the sedimentary microfacies characteristics of Segment 2 of the Sangonghe Formation, the main oil-bearing formation, remains lacking. In this study, the rock type, sedimentary tectonics, and sedimentary microfacies of Segment 2 of the Jurassic Sangonghe Formation in the South Slope District of the Mahu Depression were thoroughly investigated through 3D seismic, rock core, and logging data. Moreover, the sedimentary modes and distribution characteristics of the sand bodies in the study area were further analyzed. Results showed that subfacies at the front edge of the braided river delta are developed at Segment 2 of the Sangonghe Formation, which can be further divided into four microfacies types, namely, underwater distributary channel, sheet sand, estuary dam, and interdistributary bay. The estuary dam is only developed at local positions in the work area. The vertical evolutionary laws from Segment 2 of the Sangonghe Formation to Segment 3 of the Sangonghe Formation are explicit and manifest as retrogradation from the subfacies at the front edge of the braided river delta to the prodelta. The sand bodies formed by frequent swings of the underwater distributary channels are the main reservoir bodies, and the lithology is mainly fine-grained feldspar lithic sandstone, and sedimentary tectonics have diverse forms. On the basis of deposition microphase analysis, the sand bodies’ planar distribution characteristics under phase-controlled conditions were analyzed using a seismic model inversion technology to provide theoretical guidance for oilfield expansion, exploration, and exploitation.

Hydraulic fractures evaluation of the glutenite and the effects of gravel heterogeneity based on cores

A demonstration area was established on the north slope of the Mahu Depression, Junggar Basin, NW China to carry out the hydrofracturing experiment and a cored well was designed to investigate hydraulic fractures. 345 fractures, comprising HFs, natural fractures, core-handling fractures, and drilling-induced fractures, were harvested from four continuous cores of about 323.19 m that contained mudstone, sandstone, and conglomerate. The lithology of the core is dominated by the conglomerate, which is characterized by coarse gravel size, poor sorting, and gravel support. Firstly, this paper identifies different fractures by integrating the core observation, imaging logs, and CT scans. The HF in the glutenite reservoir was divided into penetrating-gravel fractures and bypassing-gravel fractures based on the fracture propagation path and fracture surface geometry. Secondly, the occurrence and density of HFs were characterized, respectively. The HF has a dip of 80–90° and two trends of 0°–20° and 160°–220°. The fracture density presents strong heterogeneity over depth and the number of penetrating-gravel fractures is nearly twice of that bypassing-gravel fractures. Besides, no significant proppants were observed on the fracture surface, while it was identified in the rock debris. Thirdly, the gravel size and orientation were selected to investigate the impact of gravel heterogeneity on HFs. The result showed that the larger gravel size and greater acute angle between gravel orientation and HFs propagation orientation are conducive to the development of penetrating-gravel fractures. Finally, the impact of fractured wells on HFs was studied. The fracture density is closely related to the distance between fractures and the perforation site, Cluster spacing, and slickwater. Higher fracture density is a result of closer spacing between HFs and the perforation site, smaller cluster spacing, and a higher percentage of slickwater. The insight of this paper is expected to provide some references for the hydrofracturing operation in oilfields and current experimental and numerical investigation.

Organic geochemical characteristics of the Permian source rocks in Mahu Depression, Junggar Basin: depositional environment significance

Organic geochemical characteristics of the Permian source rocks in Mahu Depression, Junggar Basin: depositional environment significance

Origin of Shallow Jurassic Heavy Oils in the Northwestern Margin of the Junggar Basin, NW China: Constraints from Molecular, Isotopic and Elemental Geochemistry

AbstractOil group separation, gas chromatography–mass spectrometry analysis of saturated hydrocarbons, carbon isotope analysis of fractions and tests on trace elements were all carried out to determine the origin of shallow Jurassic heavy oils in the northwestern margin of the Junggar Basin, northwestern China. Results showed that all the crude oils had been subjected to different degrees of biodegradation, on an order ranging from PM 6 to 9, which yielded many unresolved complex mixtures (UCM) and formed a huge spike in the mass chromatogram (M/Z = 85). Two heavy oils from the Karamay area underwent slight biodegradation, characterized by the consistent ratios of biomarker parameters. C21/C23 and C23/H of the two samples were 0.81 and 0.85, while G/H, C27/C29 and C28/C29 were 0.38 and 0.40, 0.16 and 0.27, 0.87 and 0.86, respectively. The isomerization parameters of terpane and steranes were 0.50–0.53, and 0.48–0.49, respectively. The above geochemical indices indicated that the crude oils in the study area were in the marginally mature stage. The parent materials were a mixture, consisting of bacteria, algae and some higher plants, formed under reducing depositional conditions, which is in agreement with the source rocks of the Fengcheng Formation in the Mahu depression. The carbon isotopic compositions of saturated hydrocarbon, aromatic hydrocarbon, NSO and asphaltene were –31‰– to –30.3‰, –29.5‰ to –29.03‰, –29.4‰ to –28.78‰ and –28.62‰ to –28.61‰, respectively. These findings are in agreement with the light carbon isotope of kerogen from the lower Permian Fengcheng Formation. Furthermore, V/Ni and Cr/Mo of all the crude oils were 0.01 to 0.032, 0.837 to 10.649, which is in good agreement with the ratios of the corresponding elements of the extracts from the Fengcheng Fm. carbonate source rock. As a result, a two–stage formation model was established: (1) the oil generated from the carbonate source rocks of the Fengcheng Formation migrated to the Carboniferous, Permian and Triassic traps during the Late Triassic, forming the primary oil reservoirs; (2) during the Late Jurassic period, the intense tectonic activity of Yanshan Episode II resulted in the readjustment of early deep primary reservoirs, the escaped oils gradually migrating to the shallow Jurassic reservoir through cross‐cutting faults, unconformities and sand body layers. The oils then finally formed secondary heavy oil reservoirs, due to long–term biodegradation in the later stage. Therefore, joint methods of organic, isotopic and element geochemistry should be extensively applied in order to confirm the source of biodegradation oils.

Geochemistry of Formation Water and Its Implications for Petroleum Source Rocks in the Fengcheng Formation, Mahu Depression, Xinjiang, China

Geochemical properties of formation water reflect the sedimentary environments and the sealing conditions of the formation, which are of great significance for oil and gas exploration. In this research, the formation waters in the deep Permian Fengcheng Formation in the Mahu Depression were studied by analysis of chemical composition, stable isotopes, and the homogenization temperatures and salinities of fluid inclusions. The results show that the formation water is NaHCO3-type with high salinity, high HCO3-, low concentrations of Ca2+ and Mg2+ and high pH. The overall sealing of the formation is well maintained. Na2SO4-type water was found in some places with poor preservation of oil and gas. The fluid geochemistry and alkaline mineral distribution in the strata, which are dominated by deep fine-grain mixed deposits, indicate that the main body of the Fengcheng Formation was deposited in an alkaline lake sedimentary environment. The isotopic signatures are characterized by high δ13C, negative δ18O, and light strontium and heavy boron isotopes in the strata near the deep fault zone, which indicate that the Fengcheng formation may have been affected by deep hydrothermal fluids. From the first member to the third member of the formation, the salinity first increases and then decreases. This low-high-low trend corresponds to the initial stage of alkaline lake development followed by strong alkali formation and a final stage of water retreat. The coincidence between the spatial distribution of alkaline minerals, high-salinity formation water and source rocks indicates that the alkaline lake environment can form high-quality source rocks with good petroleum generation capacity.

Investigation on the influence factors for the fracturing effect in fractured tight reservoirs using the numerical simulation.

Taking the fractured tight reservoir of the Fengcheng Formation in Mahu Depression as the research object, the RFPA software, a numerical simulation platform of real fracture process, was used to study the fracture propagation laws in fractured tight reservoirs during the fracturing process. On this basis, the influences of different factors on the fracture propagation laws in the fractured tight reservoirs were investigated, the influences of various factors on fracture propagation were quantitatively analyzed by the gray correlation method, and then the fractability calculation model for evaluating the fracturing effects was obtained by the analytic hierarchy process method. The results show that when the fracture angle is less than 70°, the natural fracture controls the hydraulic fracture propagation direction, whereas when the fracture angle is greater than 70°, the maximum horizontal principal stress controls the hydraulic fracture propagation direction. With the increase of the fracture angle, the hydraulic fracturing area firstly decreases and then increases, whereas with the increase of the fracture density, the hydraulic fracturing area gradually increases. The hydraulic fracturing area increases as the fracture compressive strength, tensile strength and elastic modulus reduction factor increase, whereas the hydraulic fracturing area decreases as the fracture Poisson's ratio reduction factor increases. Based on the gray correlation method, the ranking of the fracturing effect is clarified as fracture density > horizontal stress difference > fracture angle > elastic modulus > compressive strength > tensile strength > Poisson's ratio. Using the analytic hierarchy process, a model for calculating the reservoir fractability index is established, and has a good positive correlation with the dimensionless fracturing area.

Characterization of Glutenite Reservoir based on Digital Core Technology: A Case Study of Upper Wuerhe Formation in Mahu Depression?

Characterization of Glutenite Reservoir based on Digital Core Technology: A Case Study of Upper Wuerhe Formation in Mahu Depression?

Prediction of glutenite reservoirs using an adaptive Bayesian seismic inversion in the slope zone of Mahu Depression in Junggar Basin, NW China

The slope zone of Mahu Depression in Junggar Basin contains the largest glutenite oilfield discovered over the world so far. However, because of the mechanism of near-source sedimentation and rapid facies transition, the glutenite reservoirs are strongly heterogeneous which makes it difficult to be discriminated directly from seismic data. To characterize the lateral variation and improve the vertical resolution of glutenite reservoirs, we develop an adaptive impedance inversion method based on the Bayesian theory. In this method, an automatically adjusted damping factor is derived to obtain the best balance between the vertical resolution and the inversion stability according to the noise level. And the trace-by-trace recursive inversion strategy, which uses the inversion result of the previous adjacent trace as the initial model for the next, is adopted to ensure the lateral variation. Synthetic data tests on 1-D and 2-D models verify the adaptive ability and the high resolution advantage of the introduced method. Real data application results in Mahu Oilfield shows that the prediction results of glutenite reservoir have distinct lateral variation and high vertical resolution, with good agreement with the actual drilling and sedimentary trend, which indicates a good application prospect in the heterogeneous glutenite reservoir exploration.

Three-dimensional in-situ stress modeling of tight conglomerate reservoirs: A case study of Triassic Baikouquan formation in the Mahu depression, Xinjiang Oilfield

As a tight conglomerate reservoir, the Baikouquan formation reservoir in the Mahu depression is vital heterogeneous. The development model of unconventional oil and gas fields such as shale gas is copied in the early development process. Advanced horizontal wells and volumetric fracturing technologies are adopted, with high development costs and low economic benefits. During the development of tight conglomerate reservoirs, there are typical problems such as underdeveloped natural fractures, complex fracture formation mechanisms during fracturing, and serious interlayer channeling in fractured wells. Practical results show that the adequate characterization of in-situ stress distribution plays a decisive role in the scientific and efficient development of tight conglomerate reservoirs. To accurately characterize the three-dimensional in-situ stress distribution law of conglomerate reservoirs, the paper selects the Mahu 131 demonstration well area. The mechanical parameters of the demonstration area are finely described through a series of core tests, well-drilled logging data, and seismic inversion data. As a result, the spatial distribution of essential parameters of the demonstration area has been established, such as the three-dimensional elastic modulus attribute volume and the three-dimensional Poisson’s ratio attribute volume. Further, an advanced finite element simulator and large-scale parallel computing technology establish the test area’s high-precision three-dimensional stress field model. Based on enormous fracturing data, microseismic data, and production data, quality control and correction of the three-dimensional stress field model are carried out. The results show that the established geomechanical model accurately reflects the direction, magnitude, and heterogeneity of the in-situ stress in the demonstration area. Through the three-dimensional minimum in-situ stress distribution, the three-dimensional horizontal stress difference distribution, the lithology characteristics of conglomerate, rock mechanical properties, and other factors in the test area, it is believed that the difference in interlayer stress is the main reason for the interlayer channeling of fracturing. According to the established high-precision in-situ stress model and the rational fracturing construction process, it can actively strengthen or weaken the instantaneous and local stress field and pressure field, from near field to far-field, and promote the expansion of hydraulic fractures in the desired manner.

Pore Structure and Movable Fluid Characteristics of Typical Sedimentary Lithofacies in a Tight Conglomerate Reservoir, Mahu Depression, Northwest China

The pore structure and movable fluid characteristics of tight conglomerate reservoirs are complex, which are greatly different from conventional reservoirs. The depositional mechanism is the fundamental factor controlling the physical properties of conglomerate reservoirs. However, there is a lack of systematic research on the pore structure and movable fluid characteristics of conglomerate reservoirs with typical sedimentary facies. This paper investigates the pore structure and movable fluid characteristics of conglomerate of different sedimentary facies based on various experiments. Casting thin sections, X-ray diffraction, scanning electron microscopy, high-pressure mercury injection, and nuclear magnetic resonance experiments were conducted on 32 conglomerates samples from the Mahu Sag, Junggar Basin, China. The quality classification method of tight conglomerate reservoirs is established. The results show that the conglomerate can be divided into three sedimentary facies; traction flow conglomerate (TFC) and pebbled sandstone (PSS) mainly develop intergranular pores and dissolved pores; and the pore diameter curves are mainly a double peak, single peak, and flat peak. Gravity flow conglomerate (GFC) mainly develops dissolved pores and interstitial micropores, and the pore diameter curve is mainly a single peak. PSS includes pebbled gritty sandstone (P(G)SS) and pebbled fine sandstone (P(F)SS). TFC and P(G)SS are favorable class I reservoirs, while GFC and P(F)SS are nonfavorable class II reservoirs. A new parameter, the ratio of the major axis to the minor axis of the pore outer ellipse (axial ratio), is proposed to quantitatively describe the compaction effect. The average axial ratios of the three lithofacies are 3.04, 3.98, and 8.78, respectively, indicating that the compaction is intensified and the pore structure becomes worse. By analyzing the correlation between pore structure parameters and permeability, it is found that the main controlling factors of permeability of GFC and TFC are sorting and connectivity, respectively, and the main flow radius is the most suitable parameter to describe permeability. A linear spectral decomposition method was used to establish a new quantitative calculation method of movable fluid saturation for different types of pores, and the results show that the movable fluid saturation of intergranular pores is the highest (average: 65.43%), and the movable fluid saturation of TFC and P(G)SS with more intergranular pores is the highest. Movable fluid saturation is inversely proportional to the content of I/S and the compaction rate and positively proportional to the content of quartz and feldspar and the cementation rate. The fluid mobility of water-wet samples is weaker. The research results provide theoretical support for the identification of favorable reservoirs and the cognition of a development mechanism.

Oilfield Water and Favorable Petroleum Exploration Targets for the Triassic Baikouquan Formation in the Slope of Mahu Depression, Junggar Basin

In this paper, we attempt to clarify the relationships between oilfield water and hydrocarbon distribution of the Triassic Baikouquan Formation, in the slope zone of Mahu depression, Junggar Basin, NW China, based on oilfield water mineralization degrees, diagenesis analysis, formation pressure coefficients, burial history, and thermal evolution processes. The results show that the study area can be divided into four zones according to the mineralization degrees, that is, (1) zone I: NaHCO3 + Na2SO4 type water with residual intergranular pores, porosity usually higher than 10%. The strata of zone I are generally buried shallow and influenced by leaching from atmospheric precipitation. This area contains normal edge and bottom water and has normal formation pressure coefficients (average 1.12); (2) zone II: CaCl2 type water with mainly compaction diagenesis, porosity usually less than 7% and high formation pressure coefficients (average 1.41); (3) zone III: NaHCO3 + CaCl2 type oilfield water with mainly feldspar dissolution diagenesis, porosity usually greater than 9% and high formation pressure coefficients (average 1.53); and (4) zone IV: CaCl2 type water, mainly compacted diagenesis with a few intergranular and feldspar dissolved pores, and high formation pressure coefficients (average 1.58). The mineralization degrees of the oilfield water in zone II, III, and IV are relatively high. The appearance of NaHCO3 type water in the deeply buried areas is usually related to oil and gas charging. Therefore, within the strata, deeply-buried areas (e.g., zone III), where NaHCO3 type water has been developed, are favorable targets for oil and gas exploration.

Gravel roundness quantitative analysis for sedimentary microfacies of fan delta deposition, Baikouquan Formation, Mahu Depression, Northwestern China

AbstractGravel roundness is one of the simple but crucial parameters in particle shape, which is related to the transportation and deposition of sediments. Based on the digital images of underground drilling cores, this study attempted to characterize and distinguish sedimentary microfacies by quantitatively test gravel roundness trends in the fan delta deposition of the Early Triassic Baikouquan Formation in Mahu Depression, Juggar Basin of China. By the new proposed de-flat roundness measurement, two major parameters are recorded to manifest the rounding degree, which is de-flat roundness value (Rdn) and the corresponding variance value. In the case study, roundness characteristics of four microfacies in the fan delta deposits are displayed and compared. Results show that braided channels and submerged distributary channels are characterized by better rounding (Rdn0.379 to 0.603, and 0.366 to 0.591, respectively) and smaller variance, while debris flow and submerged debris flow are characterized by worse rounding (Rdn0.333 to 0.405 and 0.256 to 0.391, respectively) and larger variance. In vertical of the roundness curves, channels deposits and gravity flow deposits reveal notable distinction in terms of the numeric ranges, fluctuation amplitude, and fluctuate frequency. It is interpreted to represent the different sedimentary processes during particle transport and deposit, as well as new clastics mixed in from other sources. Therefore, roundness could be a useful complementary data to provide quantitative sedimentological evidence and theoretical support for the study of coarse clastic depositional system.

Characteristics and origin of the Fengcheng Formation water in Mahu depression and its significance to hydrocarbon migration and accumulation

Formation water is the power and carrier of oil and gas generation, migration and accumulation, which has important significance for oil and gas migration, accumulation and preservation. The groundwater characteristics and genetic mechanism of the Permian Fengcheng Formation in Mahu sag are mainly studied through the chemical composition, isotope test, inclusion temperature measurement and salinity analysis. The study shows that the formation water of Fengcheng Formation in Mahu sag has special hydrochemical characteristics of high salinity, high HCO3 − concentration, low Ca2+, Mg2+ concentration and high pH value NaHCO3 water type. The characteristics of inclusion temperature measurement, carbon and oxygen isotope, strontium isotope and boron isotope show that the Fengcheng Formation fluid has deep hydrothermal source, and volcanism contributes significantly to its CO2 source. The source of deep hydrothermal solution, volcanism and a large amount of hydrocarbon generation and expulsion from source rocks may be the main reasons for high HCO3 − content in formation water. The Fengcheng Formation in Mahu sag is an alkalized lake deposit. The highest alkalization degree of water in the study area may be distributed in the southwest slope of Mahu lake. From the evolution stage of the alkali lake, the first member of the wind is the initial stage of the formation of the alkali lake, corresponding to the late stage of the high water level of the lake, and the water salinity is low; the second member of the wind is the strong alkali forming stage, corresponding to the Lake recession period, the water surface drops, the water body is strongly concentrated, and the salinity is high; the third member of the wind is the fading period of the alkali lake, corresponding to the early stage of the lake advance, the water salinity gradually decreases. On the whole, the groundwater mineralization degree of Fengcheng Formation in Mahu depression is high, and the formation sealing property is relatively good. The side near the edge of the basin is affected by the infiltration of atmospheric water, which results in the decrease of mineralization degree and the appearance of Na2SO4 type water. The water head decreases gradually from Mahu sag to northwest margin, and the gradient of water head near Wuerhe in the north section is relatively strong, which is not conducive to hydrocarbon accumulation and preservation. Baikouquan and Karamay areas are low potential areas, and the water head gradient becomes gentle, which is conducive to oil and gas accumulation.

A grain size auto-classification of Baikouquan Formation, Mahu Depression, Junggar Basin, China

Abstract The borehole electrical imaging log offers general visual borehole wall, leaving no doubt that the conductivity contrast is sufficient to obtain a qualitative gain-size distribution of rocks. In this study, an automatic grain-size classification method is proposed using gray values of borehole electrical images from Baikouquan Formation in Mahu Depression. The first stage is comparing electrical images with cores. Gravels, sands, silts and clays are all discovered in the cores. The gravels are “mottled” in electrical images, and the bigger the spots, the coarser the gravels. The images of sands are homogeneous bright colored, and the coarser the sandy grains, the brighter the images. The electrical images of silts and clays are homogeneous brown and dark-brown colored. The second stage is auto-discriminating four categories of grain sizes roughly using averages and variances of gray values. The variances of gray values of gravels are high, whereas those of sands are medium. The gray averages of silts are between 160 and 220, whereas those of clays are larger than 200. The third stage is auto-classifying three kinds of gravels or sands finely using frequency distribution of gray values. The gray values of frequency peaks of cobbles are less than 50 and frequencies are larger than 15%, whereas those of pebbles are less than 50 or larger than 200 and frequencies are between 10% and 20%; almost gray frequencies of granules are less than 10%. The dominated gray values of coarse sandstones, medium sandstones and fine sandstones are less than 50, between 50 and 160 and ranged from 160 to 240, respectively. The proposed method is demonstrated to be useful and fast to auto-classify grain size of various rocks in conglomeratic environments.