Block Reservoir Research Articles

Productivity Prediction Model of Tight Oil Reservoir Based on Particle Swarm Optimization–Back Propagation Neural Network

Single-well productivity is a crucial metric for assessing the effectiveness of petroleum reservoir development. The accurate prediction of productivity is essential for achieving the efficient and economical development of oil–gas reservoirs. Traditional productivity prediction methods (empirical formulae and numerical simulation) are limited to specific reservoir types. There are few influencing factors, and a large number of ideal assumptions are made for the assumed conditions when predicting productivity. The application scenario is ideal. However, in tight oil reservoirs, numerous factors affect productivity, and their interactions exhibit significant complexity. Continuing to use traditional reservoir productivity prediction methods may result in significant calculation errors and lead to economic losses in oilfield development. To enhance the accuracy of tight reservoir productivity predictions and achieve economical and efficient development, this paper investigates the tight reservoir in the WZ block of the Beibuwan area, considering the impact of geological and engineering factors on productivity; the random forest tree and Spearman correlation coefficient are used to analyze the main influencing factors of productivity. The back propagation neural network optimized by particle swarm optimization was employed to develop a productivity prediction model (PSO-BP model) for offshore deep and ultra-deep tight reservoirs. The actual test well data of the oilfield are substituted into this model. The analysis results of the example application yielded an RMSE of 0.032, an MAE of 1.209, and an R2 value of 0.919. Compared with traditional productivity prediction methods, this study concludes that the model is both reasonable and practical. The calculation speed is faster and the calculation result is more accurate, which can greatly reduce productivity errors. The model constructed in this paper is well suited for predicting the productivity of tight reservoirs within the WZ block. It offers substantial guidance for predicting the productivity of similar reservoirs and supports the economical and efficient development of petroleum reservoirs.

A Study on Effect Analysis and Process Parameter Optimization of Viscous Acid Acidification in a Porous Heterogeneous Carbonate Reservoir

The homogeneous acid etching of conventional acid in porous heterogeneous carbonate reservoirs leads to a large amount of consumption in the near-wellbore area, which makes the acidification effect often not ideal. In order to improve the acidizing effect of porous heterogeneous carbonate reservoirs, viscous acid is used to increase the stimulation of the target block in this paper. Through systematic experiments, the adaptability of the viscous acid in the four layers of the M reservoir in the target block was evaluated, and the MD and ME layers suitable for acidizing stimulation were determined in combination with physical property analysis. Finally, based on the geological characteristics and experimental data of the preferred layers, a two-scale acid wormhole growth radial model was established, and the construction parameters of acidizing stimulation were optimized. The results show that (1) The preferred viscous acid system has a dissolution rate of more than 95% for the rock powder in the four layers. When the matrix permeability is high, the effect of the acid wormhole is obvious and the permeability increase is higher. (2) The steel sheet corrosion and residual acid damage experiments showed that the acid system was not corrosive to the wellbore, and the reservoir damage rate of the residual acid after the reaction was low. (3) Based on the relationship between reservoir porosity and permeability and the position of edge and bottom water, the MD and ME layers with more potential for acidizing stimulation are selected. (4) The results of the numerical simulation show that the optimal acid pump rate of the MD and ME layers is 1.4 bpm and 1.0 bpm, and the acidizing fluid volume is 255 bbl, which can form effective acid wormholes, and the range of reservoir permeability transformation is the largest. The field application results show that the optimization scheme effectively improves the production of oil wells, verifies the practicability of the scheme, and provides a reference for the process optimization of viscous acid in the same type of porous heterogeneous carbonate reservoir stimulation.

Integrated Technique Provides Effective Water Diagnostics in Tight Sand

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864145, “Evaluating the Hydraulic Fracture Through Acoustic Reflection Imaging and Production Logging for Water Diagnostic Beyond the Wellbore: A Case Study From Chang 8 Tight Sand in the Ordos Basin, China,” by Guangsheng Liu, Dajian Li, and Gang Zheng, PetroChina, et al. The paper has not been peer reviewed. _ The Triassic Chang 8 tight sand reservoir in the Xifeng block of the Ordos Basin features low permeability, which means that hydraulic fracturing and subsequent waterflooding were performed during its development phase. Water breakthrough was encountered after a short period of oil production. A solution of borehole acoustic reflection imaging combined with production logging was proposed in a horizontal well suffering from high water cut. The objective was to determine which stages contributed most to water production, understand the cause, and, ultimately, create a water shutoff plan. Introduction The Ordos Basin, with an area of approximately 2.5×105 km2, is in North China. The Upper Triassic Yanchang formation is subdivided into the Chang 1 to 10 members, from top to bottom. It contains significant oil reserves in siltstone and sandstone reservoirs, especially in Chang 6 through Chang 8, that have been the major oil-producing resources in recent years. In the Triassic Chang 8 tight sand reservoir, horizontal well drilling and multiple-stage hydraulic fracturing have become common practice. In the study block, the well of interest was hydraulically fractured by coiled tubing with sand-jet perforation and fracturing operations in one run with a retrievable packer in the bottomhole assembly of the coiled tubing. In the study block, when some producing wells encountered water breakthrough, traditional water diagnostics using production logging was not enough; a survey to detect hydraulic fractures beyond the wellbore was needed. Theory and Methods Borehole Acoustic Reflection Imaging. The processing workflow for acoustic reflected waves mainly consists of two parts. The first is a filtering process to suppress the borehole mode and noise in order to preserve the reflected wave. The second is to migrate the reflected wave to the true position of a reflector. The conventional migration method used for acoustic reflection imaging normally requests previous information relating to reflector dip and produces 2D images, which show the reflector shape but have hard-to-extract precise quantitative information. A trial reflector-migration method covered in the literature was introduced in 2016 that does not require input of structure dip and is of high resolution. A 3D slowness-time-coherence method was developed in 2018, also covered in the literature, that could determine the true dip, azimuth, and distance of a reflector.

Depositional architecture of the tide-dominated late Oligocene hydrocarbon reservoirs in the Tapti-Daman block, Mumbai Offshore basin, India

The intricate interaction between tidal and river currents across a gently sloping shelf area complicates the geological interpretation of sedimentary deposits in subsurface sections. This study comprehensively analyzes the depositional framework and facies architecture in the late Oligocene siliciclastic succession of the Daman Formation, Mumbai Offshore Basin, which shows subtle changes in depositional stacking pattern in response to shoreline shifts. The late Oligocene siliciclastic succession being a major hydrocarbon producer in the Mumbai Offshore Basin; this research also aims to enhance the optimization of reserve exploitation and prospectivity evaluation. A detailed analysis was conducted using well-logs and seismic data integrated with available geological data. The Oligo-Miocene sequence demonstrates a coarsening-upward facies trend until the late Oligocene, followed by a fining-upward facies trend during the early Miocene and characterized by numerous stacked sandstone layers. The facies distribution pattern, sedimentary characteristics, and progradational geometry suggest a deltaic system dominated by tides for the late Oligocene succession and the latter part of the early Oligocene succession. The early Miocene succession shows a reversal in depositional trend with a retrogradation pattern. The late Oligocene deltaic deposits show a very high sediment load deposited during the peak river discharge from the Narmada-Tapti River system. The gentle depositional slope allowed redistribution of sediments by tidal currents. The deltaic system was further resolved into subaqueous mouth bar, delta front, and prodelta facies associations based on facies modeling. The correlation of the facies model with the regional depositional setup indicates that the late Oligocene succession corresponds to a third-order highstand system tract (HST) cycle.

Study on the Mechanism of Carbon Dioxide Miscible Fracturing Fluid Huff and Puff in Enhanced Oil Recovery

Carbon dioxide (CO2) miscible fracturing huff-and-puff technology now plays a pivotal role in enhancing crude oil recovery rates, particularly in reservoirs with challenging physical properties, strong water sensitivity, high injection pressure, and complex water-injection dynamics. In this study, the oil-increasing mechanism and huff-and-puff effect of CO2 miscible fracturing fluid are investigated through a comprehensive experimental approach. Specifically, experiments on PVT gas injection expansion, minimum miscible pressure, and CO2 miscible fracturing fluid huff and puff are conducted on the G fault block reservoir of the J Oilfield. The experimental findings demonstrate that injecting CO2 into reservoirs leads to an expansion in oil volume, a reduction in viscosity, and an increase in saturation pressure. Crude oil extraction is further enhanced by the addition of solubilizers and viscosity reducers. The use of solubilizers not only increases oil recovery rates but also reduces the minimum miscible pressure required for effective CO2 dispersion. We also found that shut-in times, permeability, and the huff-and-puff method used all have considerable impacts on huff-and-puff recovery rates. This study offers valuable technical insights, supporting the application of CO2 miscible fracturing huff-and-puff technology to enhance oil recovery rates in low-permeability reservoirs.

Evaluating and study of natural gas injecting in Shunbei-1 block fault-controlled fractured-cavity type reservoir

The fault cavern type reservoir in Block 1 of Shunbei area is located in the ultra-deep layer and is classified as a volatile oil reservoir. The reservoir is characterized by very deep burial with an oil/gas ratio between 250 and 500 m3/tone and a saturation pressure range of 28–36 MPa. As of March 2021, the formation pressure has dropped to 30.5 MPa and the pressure retention rate is 35.8%. In order to effectively develop this reservoir, it was decided to use a water injection development method with a planned transition to natural gas injection in March 2022 to further enhance recovery and maintain formation pressure. Through evaluation and research, the pressure distribution, production capacity change and reservoir dynamic response during the water injection development stage were analyzed with respect to the characteristics of fracture-controlled fracture-cave type reservoir in Shunbei-1 block. On this basis, the necessity, feasibility, and expected effects of conversion to natural gas injection are explored, including improvement of displacement efficiency, reduction of fluid output, and enhancement of formation energy replenishment. In addition, this study also carries out in-depth research and prediction on the optimization of natural gas injection parameters, the selection of injection methods and possible problems, aiming to provide scientific basis and technical support for the efficient and sustainable development of this block. In order to smoothly promote the implementation of natural gas injection development, a special reservoir description technique applicable to fault cavern type reservoirs was adopted. Based on this foundation, an in-depth study was conducted on the mechanism of natural gas displacement, so as to optimize the layout of the well network and the setting of injection and extraction parameters. In addition, a set of evaluation system for natural gas injection effect in fault cavern type reservoirs was constructed. By adopting the natural gas injection development method and combining the corresponding supporting technology development and optimization measures, the reservoir development efficiency and oil (gas) production rate have been effectively improved, and the risk of gas flaring has been reduced at the same time. These research results are of great significance for ensuring the comprehensive development and effective utilization of oil and gas resources, and provide strong technical support for future development work.

Study on Key Technologies of Geosteering for Shale Gas Horizontal Wells in the Complex Structural Area of Block H in Western Hubei-Eastern Chongqing.

Block H, located in western Hubei-eastern Chongqing, remains at a low exploration degree. Characterized by its complex structural attributes, the area presents adverse conditions such as a thin thickness of high-quality shale reservoir, rapid lateral formation occurrence, and poor stratigraphic correlation, challenging conventional geosteering methods. The primary shale gas reservoir in Block H corresponds to the Upper Permian Wujiaping Formation. To ensure that the shale gas horizontal wells in this block effectively penetrate high-quality gas reservoirs, this study delves into the geological characteristics of this stratigraphic unit, identifies principal challenges faced by current geosteering techniques, and introduces a tailored technical solution. This solution encompasses the application of real-time 3D geological modeling to track while drilling, identification of steering marker layers, optimization of steerable tools, and optimization of the steering trajectory while drilling. In the technology of optimization of the steering trajectory while drilling, a trajectory control calculation model based on the average angle technique was established for the first time. Additionally, a sectional control chart for marker layers and well inclination under different deflecting constraints was established. These methods have solved the problems of large error in target prediction and poor trajectory control effects by using the equal thickness method alone. The findings from this study can significantly enhance target prediction and trajectory control accuracy in complex structural areas, offering pivotal insights for the proficient development of analogous shale gas reservoirs in the future.

Fracture identification and characterization of Ordovician carbonate rock reservoir in block B of the Tahe oilfield

Fracture identification and characterization of Ordovician carbonate rock reservoir in block B of the Tahe oilfield

MultiURNet for 3D seismic fault attributes fusion detection combined with PCA

Identifying faults and fractures in complex block reservoirs is critical for recovering residual oil-gas. It has been found that improving the identification accuracy of neural networks and enhancing their ability to learn multiple fault features are key to accurately identifying complex faults, including low-order and hidden faults. In this study, we developed a U-shaped residual network (URNet) that intelligently identifies seismic faults using principal component analysis (PCA). Numerous synthetic seismic records were generated using convolution method. Multiple seismic attributes were generated based on amplitude attributes and preferred attribute bodies. PCA is used to pre-process the features of multi-attribute bodies, downscale and preserve the original data information and reduce data complexity and storage space. A residual block was added to the deep coding and decoding network structure to improve the expression capability of the neural network while preventing gradient vanishing. Naming the network structure as MultiURNet and the network model was applied to the generated data and actual data, and the identification of the high-order and low-order faults were both significantly improved with the clarity of the fault lines. The results confirm the feasibility and efficiency of the proposed method, which has significant potential for future exploration in shallow and medium-shallow oil and gas fields.

A Case Study on the CO2 Sequestration in Shenhua Block Reservoir: The Impacts of Injection Rates and Modes

Carbon capture and storage (CCS) is the most promising method of curbing atmospheric carbon dioxide levels from 2020 to 2050. Accurate predictions of geology and sealing capabilities play a key role in the safe execution of CCS projects. However, popular forecasting methods often oversimplify the process and fail to guide actual CCS projects in the right direction. This study takes a specific block in Shenhua, China as an example. The relative permeability of CO2 and brine is measured experimentally, and a multi-field coupling CO2 storage prediction model is constructed, focusing on analyzing the sealing ability of the block from the perspective of injection modes. The results show that when injected at a constant speed, the average formation pressure and wellbore pressure are positively correlated with the CO2 injection rate and time; when the injection rate is 0.5 kg/s for 50 years, the average formation pressure increases by 38% and the wellbore pressure increases by 68%. For different injection modes, the average formation pressures of various injection methods are similar during injection. Among them, the pressure increases around the well in the decreasing injection mode is the smallest. The CO2 concentration around the wellbore is the largest, and the CO2 diffusion range continues to expand with injection time. In summary, formation pressure increases with the increase in injection rate and injection time, and the decreasing injection mode has the least impact on the increase in formation pressure. The CO2 concentration is the largest around the well, and the CO2 concentration gradually decreases. The conclusion helps determine the geological carrying capacity of injection volumes and provides insights into the selection of more appropriate injection modes. Accurate predictions of CO2 storage capacity are critical to ensuring project safety and monitoring potentially hazardous sites based on reservoir characteristics.

Numerical Simulation Study on Optimization of Injection-Production Coupling Parameters in Complex Fault Block Reservoirs

Taking complex fault-block reservoir in Biyang Depression as the research object, the influence of different factors on the coupling development mode of injection-production was studied. The numerical simulation method was used to evaluate the influence of intervention timing, injection intensity, periodic injection volume and production strength on the coupling implementation effect of the fault-block reservoir, and the coupling development parameters were optimized.The main knowledge obtained is that the timing and intensity of intervention are the main controlling factors of injection-production coupling in fault block reservoirs. The earlier the intervention time, that is, the lower the water cut, the better the injection and production coupling development effect. There is an optimal injection intensity, and the coupling injection and production effect is the best when the injection and production ratio is kept at 1:1. When the pressure is restored to 100%-120%, the coupling injection and production development effect is the best, and the periodic water injection volume is 2400-3200m3. The higher the strength of liquid production, the faster the oil recovery rate.

Wygd Study on prediction method of drilling pressure in low permeability oilfield

During the high water cut development stage of low permeability in M block, the overall recovery degree is low, there has 100 infilling wells been drilled since 2020 to improve the development effect. Before drilling, in order to avoid the risk of pressure safety, it is necessary to shut down the peripheral water injection wells to relieve the pressure, at the same time.Since the M Block reservoir is a low permeability reservoir, the pressure relief time after drilling off is long, which increases the impact on the production of developing wells and increases the fluid transportation and the related production costs, while there is no uniform standard for the time, pressure and distance of drilling off. In order to control the production loss of developing wells and save the shut-in cost. This paper applies numerical simulation and reservoir engineering method, by establishing fine geological model, optimizing simulation technology, considering the influence of start-up pressure gradient, establishing theoretical formula and mathematical model of drilling pressure, clarifying the law of drilling-off pressure relief and pressure drop, calculating the formation pressure of single well in the whole area, forming the drilling-off limit and rapid pressure prediction method, through comparison and verification, the overall deviation is 3.8%, and the method is accurate and reliable.

Screening and field application of microbial-flooding activator systems

This study aims to further enhance the oil recovery of reservoirs in the Zhong-2 Block of the Gudao Oilfield by identifying the most effective microbial-flooding activator systems and applying them in the field. We began by analyzing the structure of the reservoirs' endogenous microbial communities to understand the potential impact of microbial flooding. This was followed by determining commonly used activator systems based on their abilities to stimulate oil-displacement functional bacteria. Through laboratory experiments on oil displacement efficiency and sweep characteristics, we determined the optimal activator injection method (injection ratio) and the requisite bacterial concentration for maximal microbial-flooding efficacy. Finally, we selected the optimal activator systems and applied them to field tests. Our findings suggest the target block is highly receptive to microbial-flooding. In terms of performance, the activator systems ranked as No. 3 > No. 4 > No. 1 > No. 2. Interestingly, a deep activator system, when compared to the top-performing No. 3 system, exhibited a higher bacterial concentration peak and longer peaking duration. Optimal oil displacement effects were observed at a 1:4 vol ratio between the No. 3 activator and deep activator systems, with bacterial concentrations of up to 106 cells/mL or above. Field tests with the selected activator systems, following a specific injection protocol, demonstrated a notable increase in oil production and a reduction in water cut.

Characteristics of Chaotic Weak Reflection in Carbonate Fracture-Cavity Reservoirs: A Case Study of Ordovician Reservoirs in Block 10 of the Tahe Oilfield, Tarim Basin, China.

The identification of carbonate reservoirs is a critical task in oil and gas exploration. Chaotic weak reflection is an important type of reflection characteristic in carbonate reservoirs. Widespread distribution of chaotic weak reflection has been observed in the Ordovician Yijianfang Formation in the Tahe area. However, there is still a lack of systematic research on the distribution, characteristics, reservoir space, and reservoir types of chaotic weak reflection in the Tahe area. To address this issue, this study conducted a comprehensive analysis of multiscale data and found that chaotic weak reflections are distributed within 100 ms below the top interface of the Middle Ordovician. Seismic profiles exhibit a "string of pearls" with a "tail" or "pearl-like" widening feature. On well logs, all three porosity curves exhibit localized peaks, with increases in acoustic (AC) and compensated neutron (CNL) and decreases in density (DEN), while the deep and shallow lateral resistivity (RD, RS) curves show positive amplitude differences. In the FMI, they are represented by dark sinusoidal curves and dark small patches. Based on these response characteristics, two types of reservoir spaces are identified for chaotic weak reflections: high-angle vertical fractures and caves with heights less than 7 m, which can form independent reservoirs or fracture-cavity complexes. Three types of reservoirs are distinguished: fracture, cavity, and cavity-fracture types.

Geochemical characteristics of the braided river reservoir in block 19 of the sulige gas field

The sand body structure and geochemical characteristics of braided river reservoirs are the key geological factors affecting gas production and development effects. The Sulige gas field in the Ordos Basin is an important large-scale gas-producing layer. Owing to the control of sedimentary facies, the geological structure of the sand body changes greatly and its connectivity is poor. The geological characteristics have not yet been elucidated, and this is an important problem restricting the development of the Sulige Gas Field. To solve this problem, this study focuses on the braided river reservoir of the Shihezi Formation in Block 19 of the Sulige Gas Field, conducts geological surveys in the study area, analyzes the geological and geochemical characteristics of the reservoir, and obtains samples through drilling. Through a thin-section test, gas-water two-phase experiment, and simulation test, the braided river reservoir configuration and pore and gas-water characteristics are obtained. The results show that the reservoir lithology in the study area is mainly composed of quartz sandstone, lithic sandstone, and quartzy lithic sandstone, with a porosity of 3%–13% and a permeability of (0.05–0.7) × 10−3 m2. The reservoir has low porosity and low permeability. After drilling samples were obtained, 32 thin-section rock samples were selected. The pore types of the block reservoir mainly (82.9%) consisted of intragranular and intergranular dissolved pores. The difference in pore structure was mainly reflected by the size and distribution of the throat. The distribution of physical properties was 6%–10%, the gas saturation was 61%, the NMR effective porosity was 7.49%, the permeability was 4.08 × 102 μm2, and the physical properties were relatively good. In terms of the study area, the average thickness of the single braided channel in the lower section of He 8 was 4.7 m, the average width of the channel was 963 m, and the composite channel was distributed in a potato shape, parallel to the direction of the main flow. The average length of the channel was 2,147 m and the average width was 844 m. As the porosity increased, the efficiency of gas-driven water also increased, and there was a linear positive correlation between porosity and gas-driven water efficiency. With the increase in movable water saturation, the water-air ratio became larger and water production was greater. In low-amplitude structures and under low-permeability background conditions, for reservoirs with good local pore structure and physical properties, the water remaining at the bottom of the reservoir or sand body was controlled by the accumulation conditions or the weak structural differentiation after accumulation. In terms of the gas and water produced simultaneously in the study area, gas production was less than 2 × 104 m3/d and water production was relatively large at more than 10 m3/d; gas and water were mainly distributed in the downdip part of the main channel structure or in the island lens-shaped permeable sand bodies trapped by the surrounding tight layers. The study results provide theoretical data support for the exploration and production of the Sulige Gas Field.

Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

Study on the Variation Law of Reservoir Physical Properties in High Water Cut Stage

Difficulty in water injection during the water injection development (water injection production refers to the injection of water into the reservoir from injection wells during the development process of an oil field; due to its good economic efficiency and high feasibility, it has become the main method of oil field development) process of the G block reservoir is an important problem to solve. Three cores of the G block are used as the object of this study, and the laser particle size test is conducted on the target core to obtain the particle size distribution of the core. X-ray diffraction mineral content analysis is used to obtain the proportion of different mineral contents. On this basis, online nuclear magnetic technology is used to carry out the research on the change of reservoir physical properties during the high-magnification water injection process. The experiment shows that three cores (cores 8-2, 16-1, and 9) are identified as medium sandy fine sandstone with silt (the three-level naming method was adopted and the name has been changed to medium sandy fine sandstone containing silt, because the proportion of fine sand is greater than 50%, the content of medium sand is between 25%~50%, and the content of silt is between 10%~25%), medium sandy fin sandstone containing silt, and silt fine sandstone, by laser particle size testing. Their clay mineral contents are 2.47%, 2.51%, and 4.76%, respectively; the permeability (water) of the three cores continues to decrease with the increase in water injection, but the nuclear magnetic porosity and the signal intensity of different fluids in the nuclear magnetic T2 and nuclear magnetic two-dimensional spectrum show different variation patterns with the increase in water injection. The clay minerals of core 8-2 and core 16-1 are relatively small. The nuclear magnetic porosity increases rapidly to the maximum value and then decreases slowly with the increase in water injection. The right peak signal intensity in the T2 spectrum rises first and then drops, while the clay mineral content of core 9 is relatively high. The change trend of nuclear magnetic porosity is firstly decreasing and then increasing, and the signal intensity of the right peak in the T2 spectrum decreases first and then increases. The research concludes that in the early stage of water injection, clay minerals undergo hydration and a small amount of particle migration; in the later stage of water injection, due to the scouring effect of water, the fine silt and clay minerals in the cement easily fall off and migrate to the pore throat to the block. Some damage to the pore throat leads to a decrease in permeability, thus affecting the development effect.

Detecting Shallow Gas Reservoir in the F3 Block, the Netherlands, Using Offshore Seismic Data and High-Resolution Multi-Synchrosqueezing Transform

Detecting Shallow Gas Reservoir in the F3 Block, the Netherlands, Using Offshore Seismic Data and High-Resolution Multi-Synchrosqueezing Transform

N2 Foam Flooding Combined with Gel Plugging for Enhanced Oil Recovery in High-Temperature Reservoirs: Laboratory Experiments and Numerical Simulations.

The high-temperature reservoir (105 °C) in the Liubei block of Jidong Oilfield, with severe longitudinal heterogeneity, has entered a high water-cut stage. After a preliminary profile control, the water management of the oilfield still faces serious water channeling problems. To strengthen water management, N2 foam flooding combined with gel plugging for enhanced oil recovery was studied. In this work, considering a high-temperature reservoir of 105 °C, a composite foam system and starch graft gel system with high temperature resistance were screened out, and displacement experiments in one-dimensional heterogeneous cores were carried out. Through the three-dimensional experimental model and numerical model of a 5-spot well pattern, physical experiments and numerical simulations were carried out respectively to study water control and oil increase. The experimental results showed that the foam composite system had good temperature resistance up to 140 °C and oil resistance up to 50% oil saturation and was helpful to adjust the heterogeneous profile in a high temperature of 105 °C. The starch graft gel system had good injection performance, with a solution viscosity of 18.15 mPa·s, and its gel strength could effectively seal the high-permeability layer, with a gel viscosity of 34950.92 mPa·s. The displacement test results showed that after a preliminary implementation of N2 foam flooding, N2 foam flooding combined with gel plugging could still improve oil recovery by 5.26%. Compared with preliminary N2 foam flooding, gel plugging could control the water channeling in the high-permeability zone near the production wells. The combination of foam and gel made N2 foam flooding and subsequent waterflooding divert to flow mainly along the low-permeability layer, which was conducive to enhance water management and improve oil recovery. This method can be used as an effective technology to manage similar heterogeneous reservoirs.

Research on Microscopic Pore Structure Characteristics and Producibility of the Chang 9 Reservoir in the Wucangpu Block

The pore structure can affect the storage and flow properties of rock, which is an important research content in the study of unconventional tight reservoirs. This research hopes to clarify the reservoir characteristics and fluid seepage mechanism of the Chang 9 reservoir in the Wucangpu block and provide technical support for the development of horizontal wells with staged fracturing in this block. In this paper, the microscopic pore structure characteristics and producibility of the reservoir in the study area are analyzed in detail by means of constant-rate mercury intrusion and nuclear magnetic resonance. The research results show that the reservoir with permeability less than 0.076 mD is mainly composed of microthroat, the reservoir with permeability of 0.208-0.633 mD has a larger proportion of microthin throat, and the reservoir with permeability of 2.722-3.998 mD has a larger proportion of fine-middle throats. The results show that the oil/gas in the rock sample reservoirs with permeability greater than 1.0 mD is easy to produce.