Reservoir Description Research Articles

High-Resolution Velocity Model Building Based on Common-Source Migration Images and Convolutional Neural Networks

Building a reliable velocity model plays a vital role in seismic imaging and quantitative reservoir description. However, the current data-driven deep-learning-based velocity model building (VMB) approaches directly reconstruct the velocity model of the subsurface from prestack seismic recordings, which are very sensitive to the noise and amplitude mismatch in the data domain. In this letter, we propose a novel VMB approach based on common-source migration image gathers (CSMIGs) and convolutional neural networks (CNNs). The proposed CNN architecture uses the CSMIGs reconstructed by the reverse time migration approach and migration velocity model as the input data. It aims to capture the nonlinear relationship between the amplitude and phase information of CSMIGs and the optimal subsurface reflectivity model. Trained with realistic subsurface models, it can determine that the VMB approach is a computationally efficient solution for a high-resolution velocity reconstruction. In addition, the proposed approach has a better reconstruction performance, antinoise ability, and can be generalized much more easily than the data-driven VMB approach.

Pore scale image analysis for petrophysical modelling

Sedimentary rocks are known for their complex pore system with varying morphology due to intricate diagenetic processes. The present study demonstrates the applicability of image analysis in analysing and defining reservoir rock properties. Conventional techniques provide quantitative results but fail to give information about the internal microstructure of the rock. On the other hand, digital image techniques reveal the micro and macro-pore types and their connectivity across multiple scales. Hence, we performed the digital image analysis on Field Emission Scanning Electron Microscopy (FESEM) images of sandstone and carbonate samples collected from the upper Assam and Bombay offshore basins. FESEM derived image analysis was used exclusively due to its several unique features over contemporary techniques involving lesser data acquisition, simulation time and performing analysis even on a rock chip obtained while drilling the borehole. Porosity was evaluated based on the percentage of pores available within the image, and permeability was evaluated using the Kozeny-Carman equation. Further, we developed statistical equations to understand the existence of coherence amongst these parameters. Our study shows that we could determine both open and closed porosities by this method. In addition, there is an agreement between the conventional porosity measurement and image-derived porosity for most rock samples, especially for very low and high porosity. Further, this study highlights the importance of thresholding, an essential component in evaluating porosity using digital images. We propose that the methodology developed can accurately characterise reservoirs based on pore networks using high-resolution imaging techniques. The developed methodology may be adopted to promote best practices. Since we used digital images obtained from small chip size rock samples, this method is advantageous to quickly calculate the porosity and permeability from rock chips retrieved from the sieve shaker while drilling. Digital datasets extracted from this analysis will be helpful for reservoir description and characterisation based on image-derived petrophysical parameters.

Improved gas sand facies classification and enhanced reservoir description based on calibrated rock physics modelling: A case study

Abstract Rock physics provides a dynamic tool for quantitative analysis by developing the basic relationship between fluid, lithological, and depositional environment of the reservoir. The elastic attributes such as impedance, density, velocity, V p/V s ratio, Mu-rho, and Lambda-rho are crucial parameters to characterize reservoir and non-reservoir facies. Rock physics modelling assists like a bridge to link the elastic properties to petrophysical properties such as porosity, facies distribution, fluid saturation, and clay/shale volume. A robust petro-elastic relationship obtained from rock physics models leads to more precise discrimination of pay and non-pay facies in the sand intervals of the study area. The Paleocene aged Lower Ranikot Formation and Pab sandstone of Cretaceous age are proven reservoirs of the Mehar gas field, Lower Indus Basin. These sands are widely distributed in the southwestern part of the basin and are enormously heterogeneous, which makes it difficult to distinguish facies and fluid content in the reservoir intervals. So, an attempt is made in this paper to separate the reservoir facies from non-reservoir facies by using an integrated approach of the petro-elastic domain in the targeted sand intervals. Furthermore, missing logs (S-sonic and P-sonic) were also synthesized in the wells and missing intervals along with improving the poor quality of the density log by captivating the washouts and other side effects. The calibrated rock physics model shows good consistency between measured and modelled logs. Petro-elastic models were predicted initially using petrophysical properties and incorporated at true reservoir conditions/parameters. Lithofacies were defined based on petrophysical cut-offs. Rock physics modelled elastic properties (Lambda-rho versus Mu-rho, impedance versus V p/V s ratio) were then cross-plotted by keeping lithofacies in the Z-axis. The cross-plots clearly separated and demarcated the litho-fluid classes (wet sand, gas sand, shale, and limestone) with specific orientation/patterns which were randomized in conventional petrophysical analysis.

Research on Understanding and Practice of Fine Reservoir Description in Liaohe Oilfield

Research on Understanding and Practice of Fine Reservoir Description in Liaohe Oilfield

Evaluation of Rock Properties Determined from Core and NMR Data; A Case Study on Asmari Carbonate Reservoir

Description of carbonate reservoir is an important in preparation of field development. An accurate determination of rock characteristics are key parameters in the carbonate reservoir description. The rock properties are traditionally obtained from different techniques, such as lab measurement, well logging, well test and so on. In this paper, data from core measurements and NMR measurements are analyzed to study petrophysical properties of Cretaceous carbonate rock from Asmari Formation. First the pore size, pore system, porosity and permeability are determined from the core measurements and NMR Analysis. Second, the results of core and NMR evaluations are compared and the reasons of differences are distinguished. In present study, initially, a comparison between the porosity values demonstrates that porosity from NMR and helium injection experiment are very similar in which He average porosity is 21.4 % and NMR porosity is 20.68%. Then, pore sizes received from the NMR model shows reliable results and acceptable match with pore size distribution determined from MICP experiment. The permeability value is modeled with NMR permeability predicting models namely Standard Kenyon and Timur-Coates. Adjusted NMR Permeability results are 17.7 (mD) and 18 (mD) for (SDR) and (TC) methods respectively and they are consistent with laboratory core permeability results (Kg=22, Kl=19.2, Kw=18.4). The pore throat distributions are also similar for two NMR and core measurement methods. This study shows how NMR analysis could be useful in determination of petrophysical parameters. Besides, the results quantitatively and qualitatively compared the reservoir characteristics of carbonate rock between core and NMR experiments.

Geological Modeling Technology and Application Based on Seismic Interpretation Results under the Background of Artificial Intelligence

The development of seismic technology has made seismic data to be widely used in the interpretation of stratigraphic sequence frames, reservoir identification, fluid detection, and other research fields involved in reservoir description. The 3D technology reservoirs have always been the focus, as well as difficulty, of research. With the rapid development of information technology and the continuous improvement of seismic exploration level, people have put forward higher requirements for the accuracy of seismic data interpretation results. Aiming at the large number of structural and unstructured data in seismic, logging, geology, and other disciplines involved in seismic interpretation, how to effectively organize and coordinate analysis to discover the hidden reservoir structure and oil and gas distribution information has always been a geological and important topic for information processing technicians. This thesis is aimed at the current high-water-phase development of Shengtuo Oilfield reservoir and the problems existing in geological research. Based on seismic structural interpretation and attribute analysis, this paper analyzes the reservoir structural characteristics, sedimentary characteristics, and reservoir physical parameter characteristics based on geology, logging interpretation, core analysis, drilling, and seismic interpretation. Using the kriging method with external drift can cooperate with seismic variables to establish a reservoir geological model to study the Shengtuo Oilfield reservoir. We combine artificial intelligence technology with geological modeling technology of seismic interpretation results to explore the best method for predicting earthquakes. The research results in this paper show that the relative error of the model established by the kriging method in the article is relatively small for thinning wells, mainly concentrated around 1%. Examination of the thinning wells of 45 wells shows that the model established is basically good and the example has high accuracy. The research results in this paper have a guiding study of distribution and tapping potentials in the study area, formulating reasonable development and adjustment plans and improving oil recovery.

Application of Micro-resistivity Scanning Imaging Logging Data in Reservoir Thickness Division

Reservoir parameter interpretation is one of the main contents of reservoir description, which affects the whole process of oilfield development. According to the characteristics of micro-resistivity scanning imaging logging, which can directly reflect the changes of lithology and physical properties of reservoirs, this paper compares the thickness and interbed division of reservoirs with conventional logging data, this paper finds out the shortcomings of the conventional logging data in the interpretation of thickness and the division of interlayers, and combines the core analysis data to examine the differences in the correlation on the coring wells, and obtains good results, it has laid the foundation for the establishment of new interpretation procedure.

Mathematical Modelling and Simulation for One Dimensional - Two-Phase Flow Equation in Petroleum Reservoir: A Matlab Algorithm Approach

The reservoir behaviors described by a set of differential equation those results from combining Darcy’s law and the law of mass conservation for each phase in the system. The one-dimensional two-phase flow equation is implicit in the pressure and saturation and explicit in relative permeability. A mathematical model of a physical system is a set of partial differential equations together with an appropriate set of boundary conditions, which describes the significant physical processes taking place in that system. The processes occurring in petroleum reservoirs are fluid flow and mass transfer. Two immiscible phases (water& oil) flow simultaneously while mass transfer may take place among the phases. Gravity, capillary, and viscous forces play a role in the fluid-flow process. The model equations must account for all these forces and should also take into account an arbitrary reservoir description with respect to heterogeneity and geometry. Finally, one-dimensional two-phase flow equation through porous media is formulated by considering above reservoir parameters and forces. A numerical method based on finite difference scheme is implemented to get the solutions of one-dimensional two-phase flow equation. A MATLAB algorithm is used to solve the equation with mathematical analysis resulting in upper and lower bounds for the ratio of time step to mesh. The MATLAB algorithm is modified as per the model with appropriate initial and boundary conditions. The algorithm is applied to two-phase water flooding problems in laboratory size cores, and resulting saturation and pressure distribution are presented graphically. The saturation and pressure distribution of two-phase flow model is in agreement with the prediction of the Buckley Leveret theory. The numerical solution is used as a base for evaluating the numerical methods with respect to machine time requirement and allowable tie step for fixed mesh spacing.

New Gas Tracer Convection-Diffusion Model between Wells in Heavy Oil Reservoirs.

Different from conventional oil and gas, the storage and seepage space of heavy oil reservoirs are extremely complicated, thereby making it difficult to describe reservoirs in detail over the heavy oil production process. Acquiring development results accurately in real time is still a demanding task, and it is also a challenge to predict the average remaining heavy oil saturation during the production process. Tracers are mostly used to monitor steam flooding to obtain the real-time dynamics during heavy oil production in fields. However, the flow pattern of gas tracers in heavy oil is still unclear, with very rare investigations. In this work, a new one-dimensional gas tracer convection–diffusion model that considered the retention and oil phase migration velocity was established using the percolation law of gas tracers. The reservoir description coefficient f was introduced to describe the relationship between the migration velocities of the oil and gas phases in the heavy oil reservoir. Subsequently, a new gas tracer well pattern flow model was also constructed based on the gas tracer linear flow model and verified simultaneously. The results revealed that at a larger partition coefficient, more amounts of gas tracers were distributed in the crude oil, the duration of stagnation was extended, and the start time of tracer production was moved backward. The injection velocity had a very minor effect on the tracer production performance. As the fluid injection rate increased, the duration of gas tracer production was extended; however, after the injection rate reached a certain level, the difference in the arrival time of the peak become minor. The effects of crude oil viscosity on the tracer production were reflected by the breakthrough time, production time, peak concentration, and peak arrival time of the tracer. Compared with the production curve of the crude oil viscosity, the peak of the production curve with high crude oil viscosity has a faster peak time and a large peak value. The reservoir description coefficient mainly affects the peak concentration of tracer production and has very minor effects on the production time and other parameters. The outcomes of this work can be applied in the field of heavy oil development, in particular, for the heavy oil reservoir description and dynamic monitoring.

Petrophysical evaluation of sandstone gas reservoir using integrated well logs and core data for the Lower Cretaceous Kharita formation, Western Desert, Egypt

This study aims to evaluate Kharita gas reservoir to enhance the production. The increase in water-cut ratio reduces the left hydrocarbons’ amount behind pipe. Accurate determination of pore throats, pores connectivity and fluid distribution are central elements in improved reservoir description. The integration of core and logging data responses is often used to draw inferences about lithology, depositional sequences, facies, and fluid content. These inferences are based on petrophysical models utilizing correlations among tools’ responses as well as rocks and fluids properties. Upper Kharita Formation produces gas and condensate from the clastic sandstone in Badr-3 field, western desert of Egypt. It consists mainly of sandstone with shale intercalations. It is subdivided into three sub-units Kharita A, Kharita B and Kharita C that are in pressure communication. Hence, a new further investigation and review for the previously calculated GIIP (gas initially in place) was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation; subsequently, a new unconventional petrophysical evaluation approach was performed. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. The sands thickness in Upper Kharita Formation varies between more than 9 up and more than 61 m with average porosity values range between 0.08 and 0.17 PU while the average permeability values range between 1.89 and 696.66 mD. The average hydrocarbon saturation values range between 46 and 97%. Reservoir shale cutoff of 55% by using cross-plot between shale volume and porosity (Toby Darling concept) was utilized to discriminate the reservoir from non-reservoir sections. The porosity model was used to calculate reservoir porosity, using the density log. The Archie and saturation/height function models were used to calculate the water saturation and used to calibrate the water saturation in the transition zone. The porosity–permeability (POR-PERM) transform equation was used to estimate the reservoir connectivity (absolute permeability) for the four petrophysical facies (High Quality Reservoir, Moderate Quality Reservoir, Low Quality Reservoir and Highly Shale Reservoir). Core data have shown variations in reservoir quality parameters (porosity and permeability) from one well to the other. Integration of all the reservoir pressures indicated that there are different fluid types (oil, gas and water) in the Upper Kharita Formation level. The saturation/height function model was used to calibrate the saturation in the transition zone. The integration of geological core and geophysical log data helped to conduct a comprehensive petrophysical assessment of Upper Kharita Formation for a better estimation of the reservoir and to achieve a better understanding of the water encroachment in the Upper Kharita reservoir. The big challenge is the determination of the most correct model for calculating porosity, permeability and water saturation in this reservoir of different quality sand. The new petrophysical evaluation resulted in doubling the volumes in Upper Kharita reservoir and so a perforation campaign was performed to confirm the new volumetric calculations, which showed a good match with the model results. Hence, a new well was drilled targeting the low quality sand and found them with high pressure almost near virgin pressure.

Research on Sedimentary Microfacies of an Oil Layer in a Block of Songliao Basin

This topic uses debris, core log, core description data, combines regional research results, determine that the oil layer in a block of the Songliao Basin is the most developed in the front subfacies and prodelta subfacies of delta underwater sediment. Microfacies include underwater distributary channels, underwater natural levees, distributary bays, estuary dams, distal bars, sheet sand, and prodelta mud. The contiguous distribution of dam sand is the main feature of this area. On the basis of single-well facies research, it is the first time that this topic has studied the features of the plane and profile distribution of the reservoir sedimentary facies belt in the study area, and finally builds the sedimentary facies model, and provides a solid geological basis for fine reservoir description and favorable area prediction.

Seismic description and fluid identification of thin reservoirs in Shengli Chengdao extra-shallow sea oilfield

The meandering channel deposit of the upper member of Neogene Guantao Formation in Shengli Chengdao extra-shallow sea oilfield is characterized by rapid change in sedimentary facies. In addition, affected by surface tides and sea water reverberation, the double sensor seismic data processed by conventional methods has low signal-to-noise ratio and low resolution, and thus cannot meet the needs of seismic description and oil-bearing fluid identification of thin reservoirs less than 10 meters thick in this area. The two-step high resolution frequency bandwidth expanding processing technology was used to improve the signal-to-noise ratio and resolution of the seismic data, as a result, the dominant frequency of the seismic data was enhanced from 30 Hz to 50 Hz, and the sand body thickness resolution was enhanced from 10 m to 6 m. On the basis of fine layer control by seismic data, three types of seismic facies models, floodplain, natural levee and point bar, were defined, and the intelligent horizon-facies controlled recognition technology was worked out, which had a prediction error of reservoir thickness of less than 1.5 m. Clearly, the description accuracy of meandering channel sand bodies has been improved. The probability semi-quantitative oiliness identification method of fluid by prestack multi-parameters has been worked out by integrating Poisson's ratio, fluid factor, product of Lame parameter and density, and other prestack elastic parameters, and the method has a coincidence rate of fluid identification of more than 90%, providing solid technical support for the exploration and development of thin reservoirs in Shengli Chengdao extra-shallow sea oilfield, which is expected to provide reference for the exploration and development of similar oilfields in China.

Construction of carbonate reservoir knowledge base and its application in fracture-cavity reservoir geological modeling

To improve the efficiency and accuracy of carbonate reservoir research, a unified reservoir knowledge base linking geological knowledge management with reservoir research is proposed. The reservoir knowledge base serves high-quality analysis, evaluation, description and geological modeling of reservoirs. The knowledge framework is divided into three categories: technical service standard, technical research method and professional knowledge and cases related to geological objects. In order to build a knowledge base, first of all, it is necessary to form a knowledge classification system and knowledge description standards; secondly, to sort out theoretical understandings and various technical methods for different geologic objects and work out a technical service standard package according to the technical standard; thirdly, to collect typical outcrop and reservoir cases, constantly expand the content of the knowledge base through systematic extraction, sorting and saving, and construct professional knowledge about geological objects. Through the use of encyclopedia based collaborative editing architecture, knowledge construction and sharing can be realized. Geological objects and related attribute parameters can be automatically extracted by using natural language processing (NLP) technology, and outcrop data can be collected by using modern fine measurement technology, to enhance the efficiency of knowledge acquisition, extraction and sorting. In this paper, the geological modeling of fracture-cavity reservoir in the Tarim Basin is taken as an example to illustrate the construction of knowledge base of carbonate reservoir and its application in geological modeling of fracture-cavity carbonate reservoir.

How genetic variability of hepatitis E virus (VHE) may impact its clinical relevance and transmission

Hepatitis E virus is the main cause of acute hepatitis worldwide. The dichotomy between waterborne human-restricted genotypes 1 and 2 circulating in developing countries and zoonotic genotypes 3 and 4 infecting human through consumption of contaminated meat in industrialized countries is currently discussed, with the detection of HEV in waters of industrialized nations. Chronic infections are described in immunocomprommised patients, as well as extra hepatic syndromes. In vivo and in vitro data have shown that HEV genetic variability can impact the bioclinical relevance of the infection, by highlighting mutations associated with severity. Genetic variability has also to be considered when exploring transmission ways, with the description of new animal reservoirs and new strains able to infect humans. HEV genetic variability is one of the keys to better control its transmission and to adapt diagnostic tools and strategies, with the aim to protect vulnerable populations.

Natural-Gas-Foam Fluid Reduces Water Needed for Fracture Stimulations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201450, “Reducing the Volume of Water Needed For Hydraulic Fracturing by Using Natural-Gas-Foamed Stimulation Fluid,” by Raj Malpani, SPE, Chris Daeffler, and Sandeep Verma, SPE, Schlumberger, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. NG-Foam Fluids Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits. The authors write that using NG foams is likely to provide long-term sustainable benefits in areas where water procurement and disposal costs are high, where natural gas may be available from a central processing facility through pipelines, and where the reservoir is relatively shallow and contains clay-bearing minerals. This work is inspired by a program sponsored by the US Department of Energy to investigate NG as an alternative to N2 and CO2 in foamed fracturing fluids. Initially, the project focused on identifying a thermodynamic path-way to use NG obtained from producing wells and processing plants. The study later extended into laboratory-scale experiments to measure NG-foam-fluid rheology, which was found to be comparable to foams based on N2 and CO2. The first step in the work flow is to build a static geological model to capture the reservoir description. The subsequent step is to use the rock characterization to simulate the induced hydraulic fractures. The hydraulic-fracture simulator also predicts the proppant distribution and its conductivity and treating pressure. The simulated treating pressure is matched with observed pressure during stimulation treatment to calibrate the hydraulic-fracture model. The hydraulic fractures are then gridded in the static geological model to generate the reservoir model for flow modeling. This is a critical step in the process because the static model is linked to the dynamic simulator without losing the details of the hydraulic fractures. The reservoir simulator is used to match the historical production performance to calibrate the reservoir model and forecast future production profiles. This hydraulic-fracture modeling, followed by the flow-modeling process, is repeated for various pumping schedules and recipes to perform a sensitivity analysis, which is detailed in the complete paper.

The characteristics of Carboniferous volcanic lithofacies and volcanic reservoirs of Ke‐Bai Fault Belt, northwestern Junggar Basin

The Ke‐Bai Fault Belt in northwestern Junggar Basin has gained robust insights and wide attention on large‐scale hydrocarbon discoveries in the Carboniferous volcanic rocks. The integrated analysis of wireline logs, image logs, core photographs, thin sections, and scanning electron microscope allows the description and interpretation of volcanic facies and volcanic reservoirs, as well as their responses to controlling factors. The results indicate that three types of lithology are identified based on cores, including volcanic rocks, followed by sedimentary rocks and metamorphic rocks. In addition, explosive facies, effusive facies, volcanic sedimentary facies, and sub‐volcanic facies are delineated according to spatial distribution, occurrence condition, and appearance characteristics of volcanic products. Furthermore, the characteristics of reservoir space (including pores and fractures) are analysed and described. Finally, the controls on the characteristics of volcanic reservoirs are revealed, including volcanic lithofacies, tectonic movements, and diagenesis.

Robust integrated optimization of well placement and control under field production constraints

Field development and control optimization aim to maximize the economic profit of oil and gas production while respecting various constraints such as production limits imposed by the available fluid processing capacity and/or reservoir management strategies. The limitations of the existing optimization workflows are 1) well locations or production/injection controls are optimized independently despite the fact that one affects another, and 2) forthcoming field production limits are ignored during at least one of these optimization stages. This paper presents a robust, multi-level framework for field development and control optimization under fluid processing capacity constraints while considering reservoir description uncertainty. The developed framework is based on sequential iterative optimization of control variables at different levels, where the loop of well placement followed by control optimization continues until no significant improvement is observed in the expected objective value. Simultaneous perturbation stochastic approximation (SPSA) algorithm is employed as the optimizer at all optimization levels. Field production constraints are imposed on the reservoir model using a simplified production network. Smart clustering techniques are applied to systematically select an ensemble of reservoir model realizations as the representative of all available realizations at each optimization level. The developed framework is tested on the Brugge benchmark field case study with a maximum field liquid production limit imposed via the production network. A comparative analysis is performed for each case to investigate the impact of field liquid production constraints on optimal well placement and control strategy. Results demonstrate that ignoring fluid processing capacity constraints, in one or multiple levels of optimization, results in a sub-optimal scenario, highlighting the significance of the proposed optimization framework in robust field development and management. • A robust, integrated framework is presented for field development and control under field production constraints while considering reservoir uncertainty. • Clustering techniques are developed to systematically select representative reservoir model realizations at each optimization level. • Ignoring field production constraints in one or multiple levels of optimization results in sub-optimal scenarios, showing the significance of developed framework in robust field development and control.

Study of fine tapping potential of poor reservoirs in late stage of high water cut

At present, the oilfield development has entered the late stage of high water cut, and the exploitation objects have been changed to the second and third types of oil layers. The distribution of remaining oil is highly fragmented and complex, and the exploitation difficulty is gradually increasing. In view of a series of geological characteristics of Development Zone A, such as “numerous layers, complex reservoirs, severe phase transition and high viscosity”, the potential tapping technologies of Class II and Class III reservoirs, such as combination of two and three and ASP flooding, have been carried out one after another. In order to further enhance oil recovery and increase recoverable reserves, a large number of fracturing measures have been implemented to increase oil production. In view of the fact that it is more and more difficult to select wells and layers by this measure, we combine the results of fine reservoir description with dynamic data, take Block B as the investigation object, establish the potential pool of sedimentary unit-level measures, recognize the potential distribution of 82 different sedimentary units, clarify the target units of potential tapping measures, and finally explore relatively perfect ways and means to optimize fracturing well layers, and strive to achieve targeted adjustment and accurately tap potential. At present, in the early stage of fracturing in this area, the average daily oil increase of a single well is 7.9 tons, and the above practices also provide empirical reference and guidance for other similar blocks.

Research and application of profile control and water shutoff technology in fractured sandstone reservoir based on system analysis method

Huoshaoshan Oilfield is a sandstone reservoir with severe heterogeneity. After years of enhanced water flooding, the reservoir conditions have changed greatly. Based on the research results of fine reservoir description, the key to successful industrial application of large-scale water shutoff and profile control is to select suitable water shutoff and profile control agents and improve injection technology and evaluation technology. This technology has become a leading technology for improving water flooding recovery in the development of extra-high water cut stage in Huoshaoshan Oilfield, with remarkable economic benefits. In this paper, the main factors affecting the performance of pre-gel system and the flow experiment used to test its performance index are described by systematic analysis method, and the construction effect of well group H1194 is briefly introduced.

Reef–shoal combinations and reservoir characteristics of the Changxing–Feixianguan Formation in the eastern Kaijiang–Liangping trough, Sichuan Basin, China

Reef–shoal reservoirs are important reservoir types of the Changxing–Feixianguan Formation located in the eastern Kaijiang–Liangping trough, Sichuan Basin, China. Understanding the reef–shoal combinations and the reservoirs characteristics are significant for oil and gas exploration in this area. According to field profiles, drilling and seismic data, the reef–shoal development state of Changxing-Feixianguan Formation was sorted out and counted, two main types of complete reef–shoal combination and incomplete reef–shoal combination had been identified based on whether reef or shoal development in the Changxing Formation and shoal development in the Feixianguan Formation, Ten secondary combination models were identified within these main combinations. To analyze the reservoir characteristics, core observations and descriptions, thin section identifications, and physical property testing were selected to match reef–shoal combinations, results show the favorable combination was mainly represented by the complete combination, of which the reservoir performance was relatively good. The platform margin reef facies and platform margin shoal facies constituted the most favorable reservoir facies zone, wherein reef–shoal reservoirs were mainly developed in the high-stand system tract within the sequence, and strong dolomitization was mostly developed at the top of the reef–shoal reservoirs. The formation of high-quality reservoirs was often controlled by the dual factors of sedimentation and diagenesis.