Similarity-based laboratory study of CO_(2) huff-n-puff in tight conglomerate cores

Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs,owing to its advantages in reducing oil viscosity,improving mobility ratio,quickly replenishing formation pressure,and potentially achieving a miscible state.However,reliable inhouse laboratory evaluation of CO_(2) huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure.In this study,we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO_(2) injection in a tight conglomerate reservoir.The impacts of depletion degree,pore volume injection of CO_(2) and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure.Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency(first increased and then decreased)with increased CO_(2) injection volume and soaking time.The lower oil recoveries under excess CO_(2) injection and soaking time were attributed to limited CO_(2) dissolution and asphaltene precipitation.This work guides secure and reliable laboratory design of CO_(2) huff-n-puff in tight reservoirs with high formation pressure.

Origin and depositional characteristics of supported conglomerates

The origin and depositional characteristics of supported conglomerates in the Mahu Sag, Junggar Basin, Xinjiang, China, are examined. Based on the terminological comparison, modern sedimentary survey and core description, the initial connotation and similarities and differences in definition between supported conglomerates and other similar concepts are discussed, the modern sedimentary environment in which supported conglomerates develop is analyzed, and the sedimentological characteristics of supported conglomerates formed in different depositional environments revealed by the cores of Mahu conglomerate oil field in the Junggar Basin are described. The supported conglomerate is similar in texture to grain supported conglomerate and openwork conglomerate but has differences from them, so it is suggested to keep the term "supported conglomerate", but the formation mechanism of supported conglomerate needs to be re-examined. Through field survey of modern sediments in Baiyanghe alluvial fan, Huangyangquan alluvial fan, and Wulungu Lake in Xinjiang, it is found that supported gravels not only formed by flooding events but also by sieving, avalanching, fluvial sorting as well as wind and wave reworking in the depositional environments such as inter-mountain creek, colluvium fan, gravel channel on gobi and the fan surface, lake beach, delta front, subaerial debris flow and subwater grain-flow etc. Supported gravels could form supported conglomerate after being buried. Supported conglomerates of seven different origins have been recognized in the cores of the Triassic and Permian stratum of Mahu Depression, Junggar Basin, namely, supported conglomerates in gravel channel deposits, in wind reworked channel deposits, in gravel beach bar deposits, in wave reworked delta front deposits, in mouth bar deposits and in debris flow deposits respectively. The study shows the supported conglomerates may be formed by a single depositional event or by multi-events during the post-depositional sedimentary reworking and even in diagenesis stage. Through flume experiment, numerical simulation, empirical model and modern sediment survey, infiltration process of gravelly channel can be reconstructed and the primary pore structure of supported gravel can be estimated. Statistics on physical properties of various types of reservoirs in Triassic Baikouquan Formation of Mahu oilfield show that granule conglomerate and pebbly conglomerate have higher porosity and permeability, while the cobble and coarse pebble conglomerate have lower permeability, which indicates that the supported gravels are easy to be reworked by post depositional filtration and diagenesis, and thus decrease in porosity and permeability.

Influence of gravel content and cement on conglomerate fracture

Tight reservoirs are typically developed by horizontal wells and multi-stage hydraulic fracturing.The conglomerate reservoir is one type of tight reservoirs,which is different from homogeneous rock,such as tight sandstone.This is because that the existence of gravels makes conglomerate have strong hetero-geneity.Thus,it is difficult to grasp the fracture mechanism and the law of fracture propagation of conglomerate,which limits the efficient development of the conglomerate reservoir.In this paper,the fracture characteristics and factors influencing the fracturing of Mahu conglomerate were studied by uniaxial compression,acoustic emission monitoring and X-ray computed tomography(CT)scanning experiments.The results show that the fracture characteristics of conglomerates are influenced by the gravel content and cement.The conglomerate in the study area is mainly divided into carbonate cemented conglomerate and clay cemented conglomerate.The fracture complexity of carbonate cemented conglomerate first increases and then decreases with increasing gravel content.However,for clay cemented conglomerates,the fracture complexity increases over the gravel content.The crack development stress is a significant parameter in the crack assessment of conglomerates.This study is useful to understand the influence of meso-fabric characteristics of conglomerates on their fracturing and crack evolution and guides the design of hydraulic fracturing.

Experimental modeling of sanding fracturing and conductivity of propped fractures in conglomerate:A case study of tight conglomerate of Mahu sag in Junggar Basin,NW China

True tri-axial sanding fracturing experiments are carried out on conglomerate samples from the Permian Wuerhe Formation of Mahu sag,Junggar Basin,to study hydraulic fracture propagation geometry and quartz sand transport in ma-trix-supported fine conglomerate and grain-supported medium conglomerate.The effect of rough fracture surface on conduc-tivity is analyzed using the 3D-printing technology to reconstruct the rough surface formed in the fractured conglomerate.The hydraulic fractures formed in the matrix-supported fine conglomerate are fairly straight,and only more tortuous when en-countering large gravels at local parts;thus,proppants can get into the fractures easily with transport distance about 70%–90%of the fracture length.By contrast,in the grain-supported medium conglomerate,hydraulic fractures tend to bypass the gravels to propagate in tortuous paths and frequently change in width;therefore,proppants are difficult to transport in these fractures and only move less than 30%of the fracture length.As the ma trix-supported fine conglomerate has high matrix content and low hardness,proppants embed in the fracture surface severely.In contrast,the grain-supported medium conglomerate has higher gravel content and hardness,so the quartz sand is crushed more severely.Under the high proppant concentration of 5 kg/m^(2),when the closure stress is increased(above 60 MPa),fractures formed in both matrix-supported fine conglomerate and grain-supported medium conglomerate decrease in width significantly,and drop 88%and 92%in conductivity respectively compared with the case under the low closure stress of 20 MPa.The field tests prove that under high closure stress above 60 MPa,using a high proportion of fine proppants with high concentration allow the proppant to move further in the fracture;meanwhile proppant places more uniformly in the ro ugh fracture,resulting in a higher fracture conductivity and an improved well per-formance.

基于Conglomerate的核心网域(站)确定方法

介绍了Conglomerate概念,推导了基于Conglomerate概念的核心集构建方法,并将这一方法应用于核心网域的测定,最后对该方法存在的问题进行了剖析,提出了改进的办法。

Quantitative evaluation methods for waterflooded layers of conglomerate reservoir based on well logging data

The rapid changing near source, multi-stream depositional environment of conglomerate reservoirs leads to severe heterogeneity, complex lithology and physical properties, and large changes of oil layer resistivity. Quantitative evaluation of water-flooded layers has become an important but difficult focus for secondary development of oilfields. In this paper, based on the analysis of current problems in quantitative evaluation of water-flooded layers, the Kexia Group conglomerate reservoir of the Sixth District in the Karamay Oilfield was studied. Eight types of conglomerate reservoir lithology were identified effectively by a data mining method combined with the data from sealed coring wells, and then a multi-parameter model for quantitative evaluation of the water-flooded layers of the main oil-bearing lithology was developed. Water production rate, oil saturation and oil productivity index were selected as the characteristic parameters for quantitative evaluation of water-flooded layers of conglomerate reservoirs. Finally, quantitative evaluation criteria and identification rules for water-flooded layers of main oil-bearing lithology formed by integration of the three characteristic parameters of water-flooded layer and undisturbed formation resistivity. This method has been used in evaluation of the water-flooded layers of a conglomerate reservoir in the Karamay Oilfield and achieved good results, improving the interpretation accuracy and compliance rate. It will provide technical support for avoiding perforation of high water-bearing layers and for adjustment of developmental programs.

U-Pb Zircon Dating of the Granitic Conglomerates of the Hutuo Group:Affinities to the Wutai Granitoids and Significance to the Tectonic Evolution of the Trans-North China Orogen

The Wutai Complex associated with the adjacent Fuping and Hengshan Complexes represents the best and dassical cross-section in the middle segment of the Trans-North China Orogen, generally divided into Eastern and Western Blocks. Unconformably overlying the Wutai and Fuping Complexes is the Hutuo Group considered as the youngest lithostratigraphic unit in the region and important both for interpreting Precambrian history as well as the overall evolution of the Trans-North China Orogen. Lack of knowledge about provenance of the sedimentary rocks in this group has hindered understanding of the depositional environments and tectonic significance. LA-ICP-MS was applied to obtain U-Pb zircon ages for the granitic pebbles, the lowest lithostratigraphic rock of the Hutuo Group, which, combined with previous lithostratigraphic, geochronological, structural and metamorphic data, provides new constraints on the sedimentary provenance and tectonic evolution of the region. The sequence of the Hutuo Group ranges upward from lower basal conglomerates and volcaniclastic rocks （Doucun Subgroup）, through clastic sediments, slates, dolomites and marbles （Dongye Subgroup）, to sandstones and conglomerates at the top （Guojiazhai Subgroup）. Zircons from granitic pebbles preserved in the Doucun Subgroup basal conglomerates give weighted mean ^207pb/^206pb ages between 2517 Ma and 2566 Ma, which are the same as those for the late Archean Wutai Granitoids, indicating that the pebbles were derived from the Wutai granitic intrusions （2566-2515 Ma）. Based on the new data and previous studies, combined with an igneous zircon crystallization age of 2087±9 Ma obtained for volcanics in the Hutuo Group, the Hutuo Group was deposited in a subduction-related retro-arc foreland basin environment that developed behind the Wutai arc during the eastward-directed subduction of the Western Block beneath the western margin of the Eastern Block. This basin underwent long-lived sedimentation and finally closed during the -1850 Ma collisional event that resulted in the final amalgamation of the North China Craton.

Lithological and environmental controls on large tafoni along conglomerate cliffs in subtropic humid Danxiashan UNESCO Global Geopark

Tafoni are a type of cavernous weathering features widespread in different climate zones around the world,but their origin has not been fully understood.Little attention was paid on tafoni in conglomerates.Danxiashan UNESCO Global Geopark,located within the subtropic humid region of South China,has a landscape of large tafoni that occur on cliffs of red conglomerates.Both the Dinosaur Rock and Pagoda Peak of the geopark were selected to investigate the formation mechanisms of tafoni in conglomerates.During the field investigation,the size,rock hardness,and the external and internal meteorology of tafoni were measured and tested.The texture and composition of rock samples were observed,and the ion chromatography experiments were performed as well.Results show that tafoni have well ellipsoidal openings.Clasts of the conglomerates are largely sub-rounded and poorly sorted,and the cement is dominantly composed of calcite and iron oxide.The hardness of the lips is almost equal to that of the columns,and both are slightly higher than the backwalls.Compared with the external intense environmental changes,the interior of the tafoni is characterized by smaller temperature and relative humidity ranges and windless condition.Therefore,the porous and permeable conglomerates provide favorable lithology for tafoni development,and the micro-environment within the caverns is conducive to improving water utilization efficiency and enhancing salt weathering.The salts mainly consist of sulfates and nitrates,which might be derived from frequent raining,water evaporation and red beds as well.Consequently,tafoni are the result of the synergistic effects by multiple factors,rather than a single mechanism.

Theoretical understandings, key technologies and practices of tight conglomerate oilfield efficient development: A case study of the Mahu oilfield, Junggar Basin, NW China

A series of theoretical explorations and field tests have been carried out to efficiently develop the Mahu tight conglomerate oilfield in the Junggar Basin.Concepts of steered-by-edge fracturing and proactive fracturing interference were proposed.A series of innovative technologies were developed and implemented including optimization of 3-D staggered well pattern,proactive control and utilization of spatial stress field,and synergetic integration of multiple elements.Different from shale,the unique rock fabric and strong heterogeneities of tight conglomerate formation are favorable factors for forming complex fractures,small space well pattern can proactively control and make use of interwell interference to increase the complexity of fracture network,and the"optimum-size and distribution"hydraulic fracturing can be achieved through synergetic optimization.During pilot phase of this field,both depletion with hydraulically fractured vertical wells and volume fracturing in horizontal wells were tested after water injection through vertical wells,then the multi-stage fracturing with horizontal well was taken as the primary development technology.A series of engineering methods were tested,and key development parameters were evaluated such as well spacing,lateral length,fractures spacing,fracturing size,and fracturing operation process.According to geoengineering approach,the 100 m/150 m tridimensional tight-spacing staggered development method was established with systematic integration of big well clusters,multiple stacked pay zones,small well spacing,long lateral length,fine perforation clustering,zipper fracturing and factory operation.According to half-year production performance,100 m/150 m small spacing wells outperformed 500 m/400 m/300 m spacing wells.Its average estimated ultimate recovery(EUR)of wells was identical with those best wells from large-spacing area.Compared with the overall performance of Mahu oilfield,the drainage efficiency and estimated recovery factor of this pilot were significantly boosted with improved economics.

Pore Structure Characterization of Clay Minerals in the Lower Karamay Formation Conglomerate Reservoir in the Junggar Basin and its Impact on Hydrocarbon Storage and Seepage

The micro-nano pore structure of conglomerate in the Lower Karamay Formation of the Xinjiang Oilfield,Junggar Basin,northern China is characterized to predict its impact on fluid reserves and seepage.Authigenic clay minerals are mainly kaolinite(67%),followed by an illite/smectite mixed layer(18%),illite(10%),and chlorite(5%).For kaolinite,pore throats between 0–200 nm are dominant,accounting for 90%of the total pore throats.For illite/smectite mixed layer,pore throats also between 0–200 nm account for nearly 80%,while pore throats between 200-500 nm only account for 15%.For illite,pore throats below 100 nm account for about 80%,while pore throats in the range of 100–500 nm only account for 20%.For chlorite,most throats are below 200 nm.The pore roundness of illite is the highest,while the pore roundness of chlorite is relatively lower.The lower limits of the dynamic and static pore throat radii are 42.128 nm and 72.42 nm,respectively.The theoretical contribution rates of the illite/smectite mixed layer,kaolinite,illite and chlorite to storage/seepage are 60%/45.86%,52.72%/38.18%,37.07%/28.78%and 32.97%/26.3%,respectively.Therefore,the contribution rates of clay minerals in the study area are as follows:illite/smectite mixed layer,kaolinite,illite and chlorite.

The World＇s Largest Conglomerate Type Oilfield Has Been Discovered in the Junggar Basin of China

The Junggar Basin in the northern part of Xinjiang is the second largest inland basin in China. It is located between the Altai and Tianshan Mountains, which is bounded by the Junggar bounded Mountain in the northwest, the Altai Mountains in the northeast and the North Tianshan Mountains in the south. It belongs to a triangular close inland basin, and extends 700 km in EW and 370 km in NS, covering an area of 38x104 km2. The elevation is about 400 m, high in the east （about 1000 m） and low in the west. The central basin is the Guerbantonggute desert, which accounts for 36.9% of the total basin area.

Factors influencing oil recovery by surfactant-polymer flooding in conglomerate reservoirs and its quantitative calculation method

This study aims to clarify the factors influencing oil recovery of surfactant-polymer(SP)flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flooding to SP flooding.The conglomerate reservoir of the Badaowan Formation in the seventh block of the Karamay Oilfield is selected as the research object to reveal the start-up mechanism of residual oil and determine the controlling factors of oil recovery through SP flooding experiments of natural cores and microetching models.The experimental results are used to identify four types of residual oil after water flooding in this conglomerate reservoir with a complex pore structure:oil droplets retained in pore throats by capillary forces,oil cluster trapped at the junction of pores and throats,oil film on the rock surface,isolated oil in dead-ends of flow channel.For the four types of residual oil identified,the SP solution can enhance oil recovery by enlarging the sweep volume and improving the oil displacement efficiency.First,the viscosity-increasing effect of the polymer can effectively reduce the permeability of the displacement liquid phase,change the oil-water mobility ratio,and increase the water absorption.Furthermore,the stronger the shear drag force of the SP solution,the more the crude oil in a porous medium is displaced.Second,the surfactant can change the rock wettability and reduce the absorption capacity of residual oil by lowering interfacial tension.At the same time,the emulsification further increases the viscosity of the SP solution,and the residual oil is recovered effectively under the combined effect of the above two factors.For the four start-up mechanisms of residual oil identified after water flooding,enlarging the sweep volume and improving the oil displacement efficiency are interdependent,but their contribution to enhanced oil recovery are different.The SP flooding system primarily enlarges the sweep volume by increasing viscosity of solution to start two kinds of residual oil such as oil droplet retained in pore throats and isolated oil in dead-ends of flow channel,and primarily improves the oil displacement efficiency by lowing interfacial tension of oil phase to start two kinds of residual oil such as oil cluster trapped at the junction of pores and oil film on the rock surface.On this basis,the experimental results of the oil displacement from seven natural cores show that the pore structure of the reservoir is the main factor influencing water flooding recovery,while the physical properties and original oil saturation have relatively little influence.The main factor influencing SP flooding recovery is the physical and chemical properties of the solution itself,which primarily control the interfacial tension and solution viscosity in the reservoir.The residual oil saturation after water flooding is the material basis of SP flooding,and it is the second-most dominant factor controlling oil recovery.Combined with the analysis results of the influencing factors and reservoir parameters,the water flooding recovery index and SP flooding recovery index are defined to further establish quantitative calculation models of oil recovery under different displacement modes.The average relative errors of the two models are 4.4%and 2.5%,respectively;thus,they can accurately predict the oil recovery of different displacement stages and the ultimate reservoir oil recovery.

Effects of pore structure on surfactant/polymer floodingbased enhanced oil recovery in conglomerate reservoirs

To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer(SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher;the SP flooding can enhance the producing degree of oil in 1-3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations.

An analysis of the uniformity of multi-fracture initiation based on downhole video imaging technology: A case study of Mahu tight conglomerate in Junggar Basin, NW China

To solve the problem that the production of Mahu conglomerate reservoir is not up to expectation after the multi-cluster plus temporary plugging fracturing technology is applied in horizontal wells, stages 2–6 in the test well MaHW6285 are selected to carry out erosion tests with different pumping parameters. The downhole video imaging technology is used to monitor the degree of perforations erosion, and then the fracture initiation and proppant distribution of each cluster are analyzed. The results showed that proppant entered 76.7% of the perforations. The proppant was mainly distributed in a few perforation clusters, and the amount of proppant entered in most of the clusters was limited. The proppant distribution in Stage 4 was relatively uniform, and the fracture initiation of each cluster in the stage is more uniform. The proppant distribution in stages 2, 3, 5, and 6 was significantly uneven, and the uniform degree of fracture initiation in each cluster is low. More than 70% of the proppant dose in the stage entered clusters near the heel end, so the addition of diverters did not promote the uniform initiation of hydraulic fractures. There was a positive correlation between the amount of proppant added and the degree of perforations erosion, and the degree of perforations erosion ranged from 15% to 352%, with an average value of 74.5%, which was far higher than the statistical results of shale reservoir tests in North America. The use of 180° phase perforation(horizontal direction) can reduce the “Phase Bias” of perforations erosion, promote uniform perforations erosion and fluid inflow. The research results provide the basis for optimizing the pumping procedure, reducing the perforation erosion and improving the success rate of diversion.

Overpressure origin and its effects on petroleum accumulation in the conglomerate oil province in Mahu Sag, Junggar Basin, NW China

The origin of overpressure and its effect on petroleum accumulation in the large Permian/Triassic conglomerate oil province in the Mahu Sag,Junggar Basin have been investigated based on comprehensive analysis of log curve combinations,loading-unloading curves,sonic velocity-density cross-plot,and porosity comparison data.The study results show that there are two kinds of normal compaction models in the study area,namely,two-stage linear model and exponent model;overpressure in the large conglomerate reservoirs including Lower Triassic Baikouquan Formation and Permian Upper and Lower Wu’erhe Formations is the result of pressure transfer,and the source of overpressure is the overpressure caused by hydrocarbon generation of Permian Fengcheng Formation major source rock.The petroleum migrated through faults under the driving of hydrocarbon generation overpressure into the reservoirs to accumulate,forming the Permian and Triassic overpressure oil and gas reservoirs.The occurrence and distribution of overpressure are controlled by the source rock maturity and strike-slip faults connecting the source rock and conglomerate reservoirs formed from Indosinian Movement to Himalayan Movement.As overpressure is the driving force for petroleum migration in the large Mahu oil province,the formation and distribution of petroleum reservoirs above the source rock in this area may have a close relationship with the occurrence of overpressure.

A Study on Identification of Conglomerate Reservoir Parameters and Oil/Water Beds in Ke82 Well Areas of Junggar Basin

This paper is mainly about the calculation of reservoir parameters and theinterpretation method for identifying oil/water beds in Ke82 well areas of Junggar basin. It isdifficult to determine the reservoir parameters with common logging methods such as core calibrationlog because of the diversity of minerals and rocks and the complexity of pore structures in theconglomerate reservoir of Junggar basin. Optimization logging exploration is a good method todetermine the porosity by establishing the multi-mineral model with logging curves based on theintegration of geological, core and well testing data. Permeability is identified by BP algorithm ofneural network. Hydrocarbon saturation is determined by correlating Archie's and Simandouxformulas. Comparing the exploratory result and core data, we can see that these methods areeffective for conglomerate logging exploration. We processed and explained six wells in the Ke82well areas. And actual interpretation has had very good results, 85 % of which conform to welltesting data. Therefore, this technique will be effective for identifying conglomerate parameters.

Experimental Study of the Main Influencing Factors in Mechanical Properties of Conglomerate

In recent years,with the success of exploration and development of conglomerate reservoirs in Mahu Depression,Junggar Basin,China,it is urgent to study the mechanical properties and its influencing factors of conglomerate which is considered as a new oil and gas reservoir.Based on the investigations of petrologic characteristics,heterogeneity and mechanical properties of conglomerate in Baikouquan formation,the content and geometric characteristics of gravel in conglomerate,the main factors in heterogeneity and the mechanical behavior in the triaxial compression experiment of conglomerate are analyzed in this paper.The results show that the size and content of gravel in conglomerate varies greatly,and conglomerate has strong heterogeneity under the influence of gravel content and size.An analysis of mechanical properties of conglomerate shows that conglomerate is characterized by plasticity.Besides,the sphericity is negatively correlated to the gravel content,while the heterogeneity increases with the increase of conglomerate plasticity.Due to the existence of heterogeneous gravel,local stress may concentrate in conglomerate when the stress is loaded.Consequently,a large number of micro-cracks appear at the edge of gravel,demonstrating the strong plasticity of conglomerate.This paper is of referential significance to the study of rock mechanical properties and the evaluation of engineering properties in conglomerate development.

Water-sensitive damage mechanism and the injection water source optimization of low permeability sandy conglomerate reservoirs

The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities.The results of scanning electron microscopy,X diffraction of clay minerals,nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin,China.A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively,and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water.The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity.The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration.By increasing the content of cations(especially K+and Mg2+)in the injected water,the water-sensitive damage of the reservoir can be effectively inhibited.The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region.

Petrology Characters of Conglomerates in Baikouquan Formation, Mahu Sag, Junggar Basin

Mahu Sag, one of the most oil and gas bearing sags in Junggar basin, is in the northwestern margin of the basin. On gentle slope region of the sag, a serial of large scale coarse fan delta deposits were developed in Triassic Baikouquan Formation. In order to understand the petrology characters of conglomerates in Baikouquan Formation, based on lots of cores, grain size analysis, normal thin sections, casting thin sections, scanning electron photomicrographs, mineral composition identifications, clay mineral and bulk composition identifications of X-ray diffraction, were comparatively studied for Xiazijie and Huangyangquan fan-delta in Mahu Sag. Mineral composition of conglomerates is main tuff, while eurite, dacite, rhyolite, andesite and granite are common. However, more tuff and granite, less eurite and andesite in Xiazijie fan-delta, there is no rhyolite in Huangyangquan fan-delta. Kaolinization and chloritization of conglomerates are ubiquitous in the formation. The content of chlorite and kaolinite is higher in Xiazijie fan-delta, with lower illite-smectite and illite. There is less feldspar of clastic and more calcite of cement in Xiazijie fan-delta.

Petrographic Studies on Hydrothermally Altered Conglomerates at Naer Creek, Sichuan Province, China

Based on analysing the wall rock alterations and related rocks which were used as a hint for mineral deposits and as a basis of mechanism research of fluid rock interaction, according to the results of petrographic analysis, the authors of this paper consider that the hydrothermally altered conglomerates have the following features. First, the conglomerates studied can be divided into two groups: Group A consists mainly of the gravels of granite and basalt; Group B is mainly composed of the gravels of basalt, limestone, mudstone and granite. Second, three distinct hydrothermal alterations or diagenesis were distinguished in Group A, that is, pre depositional hydrothermal alteration of the volcanic gravels (saussuritzation chloritization, epidotization chloritization, albitization and sericitization), mechanical diagenesis and post diagenetic hydrothermal alteration (epidote chlorite and prehnite calcite association). Third, the Group B is subjected mainly to pre depositional hydrothermal alteration; the alteration types are the same as of Type A. Last, the origin of the post diagenetic hydrothermal alteration of Group A is presumed to be related to the ascending of thermal water along the Naer Creek fault.