Daqing Oilfield of CNPC

ABSTRACT Through tectonostratigraphic analysis of the nonmarine, intracontinental Songliao basin in northeast China, four episodes of deformation are recognized: mantle upwelling, rift, postrift thermal subsidence and structural inversion. The episodes are related to regional geodynamics and plate motions. Each episode is associated with a specific stratigraphic signature. The first period of deformation occurred during the Middle and Late Jurassic when asthenospheric upwelling heated, thinned and stretched the lithosphere. These events may have been caused by the narrowing of the Okhotsk Sea through subduction. This deformation is characterized by doming, extension, widespread volcanism and intrusion, and erosion. Volcanics interfinger with alluvial fan and alluvial plain facies systems tracts. The second rifting episode began in the latest Jurassic and continued into the Early Cretaceous. It resulted in the formation of a large number of isolated, NNE‐trending fault blocks of ‘basin‐and‐range’ style. Rifting may have been caused by the formation and subduction of the Izanagi and Pacific Plates. Coal‐bearing fluvial, floodplain, lacustrine and fan‐delta strata and widespread volcanic rocks filled the fault‐block basins. Volcanic strata hundreds to several thousand meters thick in the Huoshiling and Yingcheng Formations record multiple intrusive events during the rifting stage in the basin. These events were concurrent with episodes of intrusion and volcanic eruption in northeast China. The third phase of regional postrift deformation and subsidence, which began with the Lower Cretaceous Denglouku Formation, was caused by lithospheric cooling and extension, modulated by multiple compressional events. Subsidence in the Songliao basin permitted accumulation of thick postrift deposits, in contrast with other Cretaceous basins in Mongolia and northeast Asia. Three compressional episodes, which episodically interrupted the long‐term cooling subsidence, originated from development of the Okhotsk suture and subduction of the Pacific plate. In the Early Cretaceous, pronounced compression originated from closure of Okhotsk Sea, forming the mountain ranges of Daxinganling, which provided sediment to the northern part of the basin. In the Late Cretaceous, the intensity of compression from the Pacific margin increased through time, causing westward migration of depocentres and uplift in the east until the end of Cretaceous. Postrift strata, typically 3000–4000 m thick with a maximum thickness of 6000 m, extend beyond the rift blocks and onlap the basin margins to form a large uniform basin. Early thermal subsidence strata include alluvial fan, fluvial, floodplain, shallow lacustrine and delta facies tracts, overlain by large deltaic and lacustrine facies. Late postrift environments featured by large lakes in the basin centre rimmed by delta, fluvial and floodplain environments. Reflection seismic profiles show that strong structural inversion, including folding and uplift, began at the end of the Nenjiang Formation and culminated at the end of the Cretaceous. The main compressional stress field changed from NW to NWW at the end of the Cretaceous, which caused changes in the direction of folding. During the rifting stage, several sets of gas‐bearing reservoirs formed in association with coal‐bearing source rocks in fluvial and deltaic strata with reservoir‐quality volcanics and fluvial and fan‐delta sandstone. Thick, widespread mudstone deposited in deep lakes during the postrift stage contains abundant organic matter, and is an important source rock and regional cap rock. Good reservoirs occur in deltaic and fluvial strata. Because of the episodic compressional events that alternately caused subsidence and uplift, reservoirs are sandwiched between source rocks, providing direct fluid communication from source to reservoir.

ABSTRACT The lacustrine shale of the Upper Cretaceous Qingshankou Formation is the principal prospective unconventional target lithology, acting as source, reservoir, and seal. Lithofacies and associated storage capacity are two significant factors in shale oil prospectivity. This paper describes an investigation of the lower Qingshankou Formation lacustrine shale based on detailed description and analysis of cores, shale lithofacies characteristics, depositional setting, and stacking patterns. Seven lithofacies are recognized based on organic matter content, sedimentary structure, and mineralogy, all exhibiting rapid vertical and lateral changes controlled by the depositional setting and basin evolution. An overall trend from shallow-water to deep-water depositional environments is interpreted from the characteristics of the infilling sequences, characterized by increasing total organic carbon (TOC) and total clay content and decreasing layer thickness (i.e., from bedded to laminated then to massive sedimentary structures). Periods of deposition during shallowing cycles show a reverse trend in the sedimentary characteristics described above. The sedimentary rocks in the studied interval show three complete short-term cycles, each one containing progressive and regressive system tracts. Massive siliceous mudstones with both high and moderate TOC are considered to have the best hydrocarbon generation potential. Laminated siliceous mudstones, bedded siltstones, and calcareous mudstones with moderate and low TOC could have the same high hydrocarbon saturations as the high-TOC massive siliceous mudstones, but these lithologies contain more brittle minerals than the massive mudstones. Several siltstone samples show low or zero saturation of in situ hydrocarbons; this is considered to be related to a combination of fair to poor hydrocarbon generation potential and extremely low permeability, limiting migration. Moderate-TOC laminated siliceous mudstones were also observed to have connective pore-fracture networks. It can be demonstrated that successive thick sequences of moderate-TOC laminated siliceous mudstones, showing high volumes of hydrocarbon in situ, a high mineral brittleness index, and good permeability, combine to form shale oil exploration “sweet spots.”

Through reviewing the development history of tight oil and gas in China, summarizing theoretical understandings in exploration and development, and comparing the geological conditions and development technologies objectively in China and the United States, we clarified the progress and stage of tight oil and gas exploration and development in China, and envisaged the future development orientation of theory and technology, process methods and development policy. In nearly a decade, relying on the exploration and development practice, science and technology research and management innovation, huge breakthroughs have been made. The laws of formation, distribution and accumulation of tight oil and gas have been researched, the development theories such as “multi-stage pressure drop” and “man-made reservoirs” have been established, and several technology series have been innovated and integrated. These technology series include enrichment regions selection, well pattern deployment, single well production and recovery factor enhancement, and low cost development. As a result, both of reserves and production of tight oil and gas increase rapidly. However, limited by the sedimentary environment and tectonic background, compared with North America, China's tight oil and gas reservoirs are worse in continuity, more difficult to develop and poorer in economic efficiency. Moreover, there are still some gaps in reservoir identification accuracy and stimulating technology between China and North America. In the future, Chinese oil and gas companies should further improve the resource evaluation method, tackle key technologies such as high-precision 3D seismic interpretation, man-made reservoir, and intelligent engineering, innovate theories and technologies to enhance single well production and recovery rate, and actively endeavor to get the finance and tax subsidy on tight oil and gas.

Summary At elevated temperatures in aqueous solution, partially hydrolyzed polyacrylamides (HPAMs) experience hydrolysis of amide side groups. However, in the absence of dissolved oxygen and divalent cations, the polymer backbone can remain stable so that HPAM solutions were projected to maintain at least half their original viscosity for more than 8 years at 100°C and for approximately 2 years at 120°C. Within our experimental error, HPAM stability was the same with and without oil (decane). An acrylamide-AMPS copolymer [with 25% 2-acrylamido-2-methylpropane sulphonic acid (AMPS)] showed similar stability to that for HPAM. Stability results were similar in brines with 0.3% NaCl, 3% NaCl, or 0.2% NaCl plus 0.1% NaHCO3. At temperatures of 160°C and greater, the polymers were more stable in brine with 2% NaCl plus 1% NaHCO3 than in the other brines. Even though no chemical oxygen scavengers or antioxidants were used in our study, we observed the highest level of thermal stability reported to date for these polymers. Our results provide considerable hope for the use of HPAM polymers in enhanced oil recovery (EOR) at temperatures up to 120°C if contact with dissolved oxygen and divalent cations can be minimized. Calculations performed considering oxygen reaction with oil and pyrite revealed that dissolved oxygen will be removed quickly from injected waters and will not propagate very far into porous reservoir rock. These findings have two positive implications with respect to polymer floods in high-temperature reservoirs. First, dissolved oxygen that entered the reservoir before polymer injection will have been consumed and will not aggravate polymer degradation. Second, if an oxygen leak (in the surface facilities or piping) develops during the course of polymer injection, that oxygen will not compromise the stability of the polymer that was injected before the leak developed or the polymer that is injected after the leak is fixed. Of course, the polymer that is injected while the leak is active will be susceptible to oxidative degradation. Maintaining dissolved oxygen at undetectable levels is necessary to maximize polymer stability. This can be accomplished readily without the use of chemical oxygen scavengers or antioxidants.

Recent ICDP drilling and deep basin volcanic exploration of 3000 m below the surface in the Songliao Basin (SB) have highlighted the 3-D delineation of the basin. The integrated new data led us to reevaluate the basin tectonics, for which the basin type, basin evolution and a number of geodynamic aspects have been controversial topics. We outline the position of a main lithospheric scale detachment fault beneath the SB, based on apparent crustal scale displacements, Moho breaks, the thinning of the Moho transition zone beneath the SB and the changing mantle thickness. This fault interpretation is consistent with simple shear as the rift mechanism. Based on a comprehensive analysis of the tectonic setting, underlying crust, structural style, sequence stratigraphy, subsidence history and volcanism, we propose an active continental margin model for the SB which shows some similarities to aulacogens but also notable differences. Situated between two Late Mesozoic active continental margins, the northern/northwestern Mongol–Okhotsk and the eastern Sikhote-Alin orogenic belts, the Cretaceous basin evolved on a pre-Triassic structurally weak basement mosaic. Its development began with regional mega-rifting from 150 to 105 Ma, followed by significant sagging between 105 and 79.1 Ma and ended with regional uplift and basin inversion from 79.1 to 64 Ma. Three regional angular unconformities separate the basin fill into three respective tectono-stratigraphic sequences. (1) The syn-rift stage is characterized by widespread fault-bounded grabens and volcanogenic successions, corresponding upward to the Huoshiling, Shahezi and Yingcheng Formations. (2) The post-rift stage includes the Denglouku, Quantou, Qignshankou, Yaojia and Nenjiang Formations. It is a special feature that the subsidence rate is abnormally high (mean of 103 m/Ma), and that flood basalt erupted along an axial wrench fault zone, associated with several marine intervals from the mid-Turonian to early Campanian (K2qn to K2n), possibly (not certainly) indicating incipient sea floor spreading characterized by Moho breaks along the basin axis in the SB around 88 Ma. Stretching stopped abruptly at approximately 79.1 Ma and was followed by uplift and rapid erosion (− 145 m/Ma). (3) Recorded by the Sifangtai and Mingshui Formations the structural inversion stage included a continuous depocenter migration to the northwest. The basin was shrinking to demise as a result of changing subduction parameters of the Pacific subduction zone. In addition to the three tectonic basin cycles, a cyclic basin fill pattern exists with three volcanic basin fill intervals of Huoshiling, Yingcheng, and upper Qingshankou Formations that alternate with sedimentary basin fill intervals of Shahezi, Dengloukou-Quantou, and Yaojia-Nenjiang Formations. When determining the subsidence rates, we observed not only anomalously fast subsidence but also found an intricate link between the subsidence rate and type of basin fill. After each volcanic interval, the subsidence rates increased in a cyclic fashion during the sedimentary intervals. Thus, there is a system of three different types of important, basin-wide geological cycles that controlled the evolution of the SB. The subsidence rate was especially high (up to 199 m/Ma) after the last volcanic episode at 88 Ma. In addition to thermal subsidence and loading by the basin fill as causative processes, we also consider magmatic processes related to asthenospheric upwelling beneath the SB. They involve the roof collapse of shallow, depleted magma chambers, the igneous accretion of initially hot, dense, basic rocks, and lithospheric delamination beneath the SB. The difference in the subsidence rates during the volcanic and sedimentary intervals may in part also have been due to heating-related uplift during the volcanic intervals. The particularly high subsidence during the Late Cretaceous sedimentary cycles was partly increased by transtension. We put forward a general model for active continental margin basins. They are generally similar to aulacogens but display the following differences. In active continental margin basins, rifting depends on the subduction parameters that may cause strong to mild extension in the giant marginal region. The geochemical composition of the volcanic rocks is more calc-alkaline in nature because they are suprasubduction-related. These basins will eventually enter a post-rift sag stage that involves thermal subsidence. However, the basin will still be near an active continental margin, and, thus, some dip- and/or strike-slip faulting may occur coevally, depending on the subduction parameters. Sag cycles in active continental margin basins will likely include volcanism. Basin inversion will after all affect active continental margin basins. Such basins strike parallel to the respective continental margin. Thus, basin inversion by subduction/collision may be more intense than in the case of aulacogens, which do not tend to strike parallel to the continental margin. Basin inversion may also precede a collision due to changing subduction parameters. Subsidence behavior may also differ because many aspects of subsidence may be at work. Subsidence curves in active continental margin basins may be fairly individual. The application of our model only requires settings with the presence of one Pacific margin type.

Summary This paper describes successful practices applied during polymer flooding at Daqing that will be of considerable value to future chemical floods, both in China and elsewhere. On the basis of laboratory findings, new concepts have been developed that expand conventional ideas concerning favorable conditions for mobility improvement by polymer flooding. Particular advances integrate reservoir-engineering approaches and technology that is basic for successful application of polymer flooding. These include the following: (1) Proper consideration must be given to the permeability contrast among the oil zones and to interwell continuity involving the optimum combination of oil strata during flooding and well-pattern design, respectively; (2) Higher polymer molecular weights, a broader range of polymer molecular weights, and higher polymer concentrations are desirable in the injected slugs; (3) The entire polymer-flooding process should be characterized in five stages—with its dynamic behavior distinguished by water-cut changes; (4) Additional techniques should be considered, such as dynamic monitoring using well logging, well testing, and tracers; effective techniques are also needed for surface mixing, injection facilities, oil production, and produced-water treatment; and (5) Continuous innovation must be a priority during polymer flooding.

Abstract Emulsification plays an important role in enhancing oil recovery. Experiments and field applications of alkali/surfactant/polymer ( ASP ) flooding indicated that the amount of oil recovery in liquids with emulsions is 5% higher than that in liquids with no emulsions. Therefore, it is of great significance to study emulsion and its field application for enhanced oil recovery. This paper discusses the current status of emulsion for enhanced oil recovery, including the formation mechanism of emulsions in chemical flooding, rheological properties, stability, seepage characteristics, emulsion improving sweep volume, and displacement efficiency, along with future development plans of emulsion for enhanced oil recovery, especially surfactants for chemical flooding. In addition, the Pickering emulsion for application in enhanced oil recovery is also discussed. The development effects of emulsion flooding have been discussed for the Midway‐Sunset Oilfield, the emulsification characteristics of ASP flooding have been analyzed in Xing‐V and Xing‐ II of the Daqing Oilfield, and the experiences regarding emulsion for enhanced oil recovery have been summarized. The key research directions of emulsion for enhanced oil recovery are indicated.

Taking organic-rich shale in the first member of Cretaceous Qingshankou Formation in the Gulong Sag, northern Songliao Basin as an example, this study examined the lithofacies classification, petrological characteristics, pore size distribution and their implications on the enrichment of shale oil of lacustrine detrital fine-grained shale. The spatial variation of lithofacies, controlled by Milankovitch cycle and influenced by sediment provenance, has an obvious sequence. The fine-grained sedimentary rocks of studied section could be classified into seven lithofacies according to a three-step classification criterion that consists of total organic carbon (TOC), sedimentary structure and mineral composition. Among them, the laminated siliceous mudstone lithofacies with moderate TOC has high hydrocarbon generation potential and abundant reservoir space, making it the most favorable lithofacies for the enrichment of matrix shale oil. Under the background of abnormally high pressure, the laminated siliceous mudstone lithofacies with moderate TOC deposited between the top of SSC2 and the bottom of SSC3 is stable in lateral distribution in the delta-lacustrine transition zone, with continuous thickness greater than 30 m. The massive siliceous mudstone lithofacies with high and moderate TOC developed in the middle of the these two cycles can act as the roof and floor seal for shale oil, therefore, the study area has good conditions for forming matrix type shale oil reservoirs.

Deep learning has been successfully applied to image denoising. In this study, we take one step forward by using deep learning to suppress random noise in poststack seismic data from the aspects of network architecture and training samples. On the one hand, poststack seismic data denoising mainly aims at 3-D seismic data. We designed an end-to-end 3-D denoising convolutional neural network (3-D-DnCNN) that takes raw 3-D cubes as input in order to better extract the features of the 3-D spatial structure of poststack seismic data. On the other hand, denoising images with deep learning require noisy-clean sample pairs for training. In the field of seismic data processing, researchers usually try their best to suppress noise by using complex processes that combine different methods, but clean labels of seismic data are not available. In addition, building training samples in field seismic data has become an interesting but challenging problem. Therefore, we propose a training sample selection method that contains a complex workflow to produce comparatively ideal training samples. Experiments in this study demonstrate that deep learning can directly learn the ability to denoise field seismic data from selected samples. Although the building of the training samples may occur through a complex process, the experimental results of synthetic seismic data and field seismic data show that the 3-D-DnCNN has learned the ability to suppress the Gaussian noise and super-Gaussian noise from different training samples. Moreover, the 3-D-DnCNN network has better denoising performance toward arc-like imaging noise. In addition, we adopt residual learning and batch normalization in order to accelerate the training speed. After network training is satisfactorily completed, its processing efficiency can be significantly higher than that of conventional denoising methods.

Summary Chemical combination flooding techniques, particularly alkali/surfactant/polymer (ASP) flooding, have proved to be effective in enhanced oil recovery (EOR). The development of this flooding technique in the Daqing Oil Field (China) shows that it can prevent production declines and help oil companies increase profits. However, ASP chemical loss and the resulting chromatographic separation in sandstone formations remain as limitations in the practice of ASP flooding. Laboratory investigations have analyzed the behavior and characteristics of chemical loss in sandstone reservoirs recently subjected to strong-base [sodium hydroxide (NaOH)] and weak-base [sodium carbonate (Na2CO3)] ASP flooding. A set of experiments were reasonably designed to study how formulation compositions, slug combination patterns, and heterogeneity affected the chromatographic separation and consumption loss characteristics of chemicals in sandstone reservoirs subjected to ASP flooding. Our investigations determined chemical-loss ratios through various experiments, described the underlying mechanism behind the discovered consumption loss characteristics, and discussed the effects of comparative ASP flooding processes. Furthermore, the incremental oil recovery factor and degree of permeability damage in heterogeneous sandstone reservoirs subjected to strong-base and weak-base ASP flooding processes were assessed and compared. Then, the role of alkali type in chemical loss, EOR efficiency, and reservoir flow assurance in sandstone formations were ascertained for the first time. The results indicated that chemical-loss behaviors and chemical chromatographic separation could be alleviated in a weak-base ASP flooding. In particular, in heterogeneous sandstone reservoirs, the average loss ratios of alkalis and surfactants could be reduced by 9.61% and 15.67%, respectively, compared to the strong-base ASP flooding. A profitable EOR of 20% or more could also be obtained with a weak-base ASP flooding. Moreover, a reduction of approximately 15% in the permeability-damage ratio could be realized in weak-base ASP flooding compared with the strong-base system, and the reservoir flow-assurance issues related to chemical loss could be addressed. The optimal designs for ASP formulations and slug combination patterns could technically and sustainably achieve high oil recovery in sandstone reservoirs with a weak-base ASP flooding. The results help illustrate the chemical combination flooding mechanism and can contribute to the existing knowledge regarding the additive effects of chemicals during the EOR process. Moreover, they are significant for further improving oil displacement efficiency and reducing the injection cost in heterogeneous sandstone reservoirs subjected to the weak-base ASP-flooding process.

Abstract Seismic velocity and attenuation anisotropy are ubiquitous in the crust and upper mantle, significantly modulating the characteristics of seismic wave propagation in the Earth's interior. Accurate seismic wave modeling of velocity and attenuation anisotropy is essential for the understanding of wave propagation in the Earth's interior as well as constructing global and region‐scale seismic full waveform tomography. Here, we derive a decoupled fractional Laplacian (DFL) viscoelastic wave equation to characterize the Earth's frequency‐independent Q behavior in the vertical transversely isotropic (VTI) media. We verify the accuracy of the proposed viscoelastic wave equation by 2D synthetic examples; to show its applicability in crustal‐scale seismic modeling, we present an example of 3D seismic wave propagation in the realistic Salton Trough model. Through extensive numerical tests, we conclude that the proposed viscoelastic wave equation is superior in four aspects. First, the viscoelastic wave equation takes VTI anisotropy of both velocity and attenuation into account and can describe the strong direction‐dependent attenuation. Second, our derivation contains spatially independent Laplacians, and thus the proposed wave equation enjoys higher simulation accuracy for heterogeneous Q media. Third, the new viscoelastic wave equation can decouple the amplitude decay and the phase distortion, which is appealing for improving the resolution in seismic imaging and inversion. Lastly, compared to viscoelastic wave equations with time‐fractional operators, our scheme has higher computational efficiency by avoiding substantial wavefield storage.

ABSTRACT Major reservoirs in the Songliao Basin (SB) are composed of volcanic rocks below 3000 m (9843 ft) of buried depth. Gas accumulations are mostly found in the buried volcanic highs, which in general correspond to paleovolcanic centers. Porosity in the volcanic rocks depends on both primary and secondary processes. The best porosity is preferentially developed in a proximal facies near the central part of each volcanic edifice. Porosity and permeability decrease with depth of burial for both volcanic and nonvolcanic sections, but their porosity-depth trends differ. Lava and welded ignimbrite slowly lose porosity with burial depth because they solidified by cooling, and their groundmasses (≥75%) are poor in quartz and calcite precipitation, thus preserving porous space. In contrast, the associated sandstone, conglomerate, tuff, and tuffite are more sensitive to overburden pressure, suffering more intense compaction and cementation. As a result, porosity and permeability of lava and ignimbrite exceed that of the other rocks, and thus, they are the best reservoir rocks below burial depths of ca. 3000 m (9843 ft) in the SB. The paleovolcanic domes are rich in both lava rocks and fractures of diverse origin, and the topographic highs provide favorable locations for gas migration and accumulation.

Abstract Hydrophobic association hydrogels (HA‐gels) with almost ideal properties were successfully prepared by micellar copolymerization, and the associated micelles acted as physical cross‐linking points in the network of HA‐gels. HA‐gels exhibit exceptional mechanical properties and transparency. However, the most striking properties are that HA‐gels possess the capability of self‐healing and remolding, which is mainly due to the dissociation and re‐association process of the associated micelles. Dried‐gels, which were prepared by stretching HA‐gels to a certain elongation for a period of time in the air, can be used as shrinkable or thermal sensitivity materials. HA‐gels have a broad selectivity for components, so we have synthesized HA‐gels with variously available properties by changing a corresponding component: thermoresponsive HA‐gels, nanosphere‐composite HA‐gels, and fluorescent HA‐gels. Therefore, we are sure that HA‐gels will be widely used in various fields, such as biology, medication, sensors, optics, and oil exploitation. magnified image

Summary The objective of this work was to explore the dynamic imbibition effect of a surfactant solution in the microcracks of a reservoir at high temperature (83.3°C) and low permeability (2 × 10−3 µm2), as well as the relative influencing factors. This study considered Fuyu Reservoir of the Toutai Oil Field in Daqing, China, which has high-temperature and low-permeability characteristics, as a research platform. First, the optimal surfactant type and concentration were selected by evaluating the imbibition recovery through a study of the adhesion-work-reduction factor and the ratio of the capillary force and gravity (NB−1), under the conditions of a spontaneous-imbibition experiment. Then, through a dynamic imbibition experiment, this study investigated the effects of the injection velocity, wettability, and saturation of the matrix on the dynamic imbibition recovery. Both the experimental results and practical application showed that the surfactant could effectively improve the imbibition recovery. However, in the process of choosing a surfactant, one must consider the influence of interfacial tension (IFT) on the capillary force when reducing the adhesion work to improve the displacement efficiency. A suitable injection velocity should be chosen to take full advantage of the ability of the capillary force to “absorb water and discharge oil,” as well as the “displacement function” of the viscous force and “improved wettability” provided by the surfactant, to obtain a higher imbibition recovery. Enhancing the water-wet state of matrix blocks can help to improve the seepage flow between the matrix and microcracks, which assists in increasing the imbibition recovery. Thus, a surfactant with an appropriate concentration or other chemical agents can be selected to enhance the water-wet state of matrix blocks. When a surfactant solution is used to develop a similar reservoir, earlier imbibition construction assists the capillary force to provide the function of “absorbing water and discharging oil,” which is helpful to enhance the imbibition recovery. The practical application of a surfactant solution in Well M38-S64 in the Mao 8 area showed that adding a surfactant to a water solution assists in improving the imbibition recovery.

Abstract The displacement efficiency (De) in porous media is usually analyzed by the ratio of the macro pressure gradient driving force and interfacial tension (IFT) between the driving fluid and residual oil. However, when the pressure gradient is constant, macro forces cannot explain the increase in De by driving fluids with elastic properties. Therefore, the change of micro forces acting on residual oil between driving fluids with and without elastic properties is analyzed. This paper shows the influence of viscoelasticity on De; the difference in the stress of non elastic fluids and fluids with elastic properties when flowing is analyzed; the effect of this stress difference on the micro flow lines in pores is mathematically simulated; the affect of the changes in micro forces caused by the change in micro flow lines on residual oil is shown; this enhanced micro force (without changing the macro pressure gradient) mainly acts on the protruding portion of different types of residual oil in pore(s), causing the protruding portion to change shape and move (mobilize); results on visualization core models confirm the above calculation and analysis; the displacement results on cores by fluids with different elastic properties in the lab are shown; the results of considering the phenomena that elasticity increases the De in numerical simulation are shown and compared with field results; large scale field results on polymer flooding and pressure coring are also shown. The above mathematical simulation, analysis, lab tests and field results all show that the micro forces acting on residual oil is different when the elastic properties of the displacing fluid varies, resulting in an increase in De for viscoelastic displacing fluids at constant pressure gradient conditions. This method of micro flow line and force analysis and its conclusions should be useful to further understand the mechanism of De in porous media; should be useful in designing, screening and developing better chemical flooding products, methods and projects to further increase oil recovery; should be useful in the analysis of phenomena associated with injecting non Newtonian fluids and gels.

This study summarizes the research experiences of non-marine seismic sedimentology in recent years in China and uses Qijia area, Songliao Basin, as a template to establish general guidelines for seismic sedimentology. Basic data sets include stacked 3D seismic volumes, 2D regional seismic lines, data for regional geologic settings, and well data. The workflow emphasizes the integration of seismic and geologic interpretations and balanced use of seismic sedimentology, sequence stratigraphy and seismic stratigraphy. Basic steps include well-to-seismic tie for the establishment of sequence framework, wavelet-phase adjustment, picking of geologic-time parallel seismic events, seismic resolution analysis, petrophysical analysis, selection of seismic attributes, stratal slicing, seismic depositional facies analysis, and applications to exploration and development. Expected maps range from key interpreted well-seismic sections, flattened relative geologic-time sections, stratal slices, and depositional facies maps, etc. The workflow is applied in the study of the Cretaceous Qingshankou Formation in the Qijia area, Songliao Basin, which can be used as a reference for seismic sedimentologic study in non-marine basins, especially in postrift depression-type basins in China.

Oxidized sodium alginate is a handily modifiable polysaccharide owing to the pendant aldehyde groups which can form dynamic covalent bonds with amines, acylhydrazines, etc., providing oxidized sodium alginate-based hydrogels with stimuli-responsive properties. However, due to the stiffness and, in particular, the hydrophobicity of sodium alginate dialdehyde at low pH, the mechanical performance and pH stimuli responsiveness of oxidized sodium alginate-based hydrogels are still strictly limited. Herein, we report a new strategy to build an injectable, dual responsive, and self-healing hydrogel based on oxidized sodium alginate and hydrazide-modified poly(ethyleneglycol) (PEG). The hydrazide-modified PEG, referred to as PEG-DTP, acts as a macromolecule crosslinker. We found that the presence of PEG-DTP reduces the hydrophobicity of oxidized sodium alginate at low pH so effectively that even a pH-induced reversible sol-gel transitions can be realized. Meanwhile, the disulfide bonds in PEG-DTP endows the hydrogel with the other reversible sol-gel transitions by redox stimuli. In particular, due to the softness of PEG-DTP chains, mechanical performance was also enhanced significantly. Our results indicate we can easily integrate multi-stimuli responsiveness, injectability, and self-healing behavior together into an oxidized sodium alginate-based hydrogel merely by mixing an oxidized sodium alginate solution with PEG-DTP solution in certain proportions.

The geological characteristics and production practices of the major middle- and high-maturity shale oil exploration areas in China are analyzed. Combined with laboratory results, it is clear that three essential conditions, i.e. economic initial production, commercial cumulative oil production of single well, and large-scale recoverable reserves confirmed by the testing production, determine whether the continental shale oil can be put into large-scale commercial development. The quantity and quality of movable hydrocarbons are confirmed to be crucial to economic development of shale oil, and focuses in evaluation of shale oil enrichment area/interval. The evaluation indexes of movable hydrocarbon enrichment include: (1) the material basis for forming retained hydrocarbon, including TOC>2% (preferentially 3%–4%), and type I–II1 kerogens; (2) the mobility of retained hydrocarbon, which is closely related to the hydrocarbon composition and flow behaviors of light/heavy components, and can be evaluated from the perspectives of thermal maturity (Ro), gas-oil ratio (GOR), crude oil density, quality of hydrocarbon components, preservation conditions; and (3) the reservoir characteristics associated with the engineering reconstruction, including the main pore throat distribution zone, reservoir physical properties (including fractures), lamellation feature and diagenetic stage, etc. Accordingly, 13 evaluation indexes in three categories and their reference values are established. The evaluation indicates that the light shale oil zones in the Gulong Sag of Songliao Basin have the most favorable enrichment conditions of movable hydrocarbons, followed by light oil and black oil zones, containing 20.8×108 t light oil resources in reservoirs with Ro>1.2%, pressure coefficient greater than 1.4, effective porosity greater than 6%, crude oil density less than 0.82 g/cm3, and GOR>100 m3/m3. The shale oil in the Gulong Sag can be explored and developed separately by the categories (resource sweet spot, engineering sweet spot, and tight oil sweet spot) depending on shale oil flowability. The Gulong Sag is the most promising area to achieve large-scale breakthrough and production of continental shale oil in China.

The emulsion process in reservoirs was simulated by core displacement experiment, and the formation mechanisms of emulsion were studied by visualization core displacement experiment. The particle size distribution of formed emulsion at different transport distances, emulsifier concentrations or injection rates was measured, and the condition of forming stable emulsion of pore-throat scale were analyzed. By measuring the viscosity, the storage modulus and the loss modulus of the formed emulsion, viscoelasticity of emulsion was studied. The study shows that the formation mechanisms are mainly the snapping action of residual oil and the shearing action of emulsifier solution. When the migration distance is greater than 1/3 times the injector-producer spacing, the emulsifier concentration is between 0.4% and 0.5% and the injection rate is between 0.3 mL/min and 0.4 mL/min, the pore-throat scale emulsion with favorably stability can be formed. The viscosity is between 48.6 mP·s and 70.3 mP·s when the shear rate is 7.34 s−1 and the emulsifier concentration is between 0.4% and 0.5%. The storage modulus and loss modulus of emulsion increase with the emulsifier concentration increasing, and the viscoelasticity of emulsion is more favorably.

Two novel strains, SL014B61A(T) and SL014B11A, were isolated from an oil-polluted saline soil from Gudao in the coastal Shengli Oilfield, eastern China. Cells of strains SL014B61A(T) and SL014B11A were motile, Gram-negative and rod-shaped. Growth occurred at NaCl concentrations of between 0 and 15 % and at temperatures of between 10 and 45 degrees C. Strain SL014B61A(T) had Q9 as the major respiratory quinone and C16 : 0 (21.2 %), C18 : 1omega9c (20.3 %), C16 : 1omega7c (7.3 %) and C16 : 1omega9c (6.4 %) as predominant fatty acids. The G+C content of the DNA was 57.9 mol%. Phylogenetic analysis based on 16S rRNA gene sequences indicated that strain SL014B61A(T) belonged to the genus Marinobacter in the class Gammaproteobacteria. Strain SL014B61A(T) showed the highest 16S rRNA gene sequence similarity with Marinobacter bryozoorum (97.9 %) and showed 97.8 % sequence similarity to Marinobacter lipolyticus. DNA-DNA relatedness to the reference strains Marinobacter bryozoorum and Marinobacter lipolyticus was 35.5 % and 33.8 %, respectively. On the basis of these data, it is proposed that strains SL014B61A(T) and SL014B11A represent a novel species, Marinobacter gudaonensis sp. nov. The type strain is strain SL014B61A(T) (=DSM 18066(T)=LMG 23509(T)=CGMCC 1.6294(T)).