Jilin Oilfield Research Articles

Mechanism of Subsurface Deformation Transmission and Geomechanical Response Inversion in Carbon Capture and Storage Project: Integrating Small Baseline Subset-Interferometric Synthetic Aperture Radar, Mechanical Experiments, and Numerical Simulation

Summary In the context of carbon capture and storage (CCS) engineering, ensuring the stability of the caprock is paramount to mitigating CO2 leakage, thus constituting a pivotal engineering challenge in CO2 geological sequestration. With the injection of CO2, pore pressure accumulates within the reservoir, bringing forth risks including diminished effective stress within the formation, surface deformation, occurrence of microseismic events, and potential caprock failure. Therefore, it is necessary to explore the geomechanical issues in CCS projects. This study focuses on the Daqingzijing in the Jilin Oilfield as the study area, utilizing the small baseline subset (SBAS)-interferometric synthetic aperture radar (InSAR) method to conduct a deformation time-series analysis in the well group area under injection and production conditions. The results reveal variations in deformation sensitivity among the sites, with surface displacements correlated to fluid injection and production, demonstrating temporal delays. At the H79 North block, the time effect is relatively minimal, with rapid propagation of formation deformation. Surface displacement in the H46 block appeared 4 months later than behind cumulative fluid volume changes. By conducting triaxial creep tests on shallow mudstone samples from the Songliao Basin under various triaxial stress states, a constitutive creep equation for caprock rocks was obtained. The numerical models of elastic and creep constitutive equations were established. The results show that the creep model exhibits superior accuracy by comparing with InSAR monitoring data (the root mean square error values of elastic and creep constitutive geomechanical models were 6.7 mm and 1.7 mm, respectively). Additionally, based on the experimental and simulation results, this study explores the transfer mechanisms of formation deformation and the inverse relationship between deformation and pore pressure. This study provides theoretical support for the geomechanical safety analysis in corresponding CCS projects.

Miscibility Evaluation for Reinjection of CO2 Flooding Associated Gas in Jilin Oilfield

Abstract In view of large amounts of associated gas produced in the late stage of CO2 flooding in Jilin Oilfield, the production characteristics of CO2 flooding associated gas are divided into three stages (i.e. before injected gas breakthrough, during injected gas breakthrough and after injected gas breakthrough). Taking the formation pressure as miscibility evaluation criteria, the miscibility effect of the produced CO2 flooding associated gas from different stages is evaluated. According to different gas production stages, the reinjection method of mixing the associated gas with pure CO2 under different proportions is proposed to elevate the utilization degree of the produced associated gas. The results indicate that at the very beginning of gas production process, produced gas is mainly composed of CH4 (58%) and C2~C3 (29%) with small amounts of N2 and C4~C6. During this stage, the associated gas can not reach miscibility with the oil by direct reinjection. It needs to be mixed with pure CO2, also the blending ratio of the associated gas should not exceed 6%. In the second stage, the compositions of the produced gas are mainly CH4 (34%) and CO2 (40%). During this stage, the blending ratio should not exceed 11%. At the final stage, the main composition of the produced gas is CO2 (94%). The associated gas can be directly reinjected into the reservoir during this stage.

Drilling Technology of Large Plumb Ratio Shallow Shale Gas Well

Abstract SY1H is the first shallow shale horizontal well deployed in Jilin Oilfield, with a depth of 1,150m in Qing1 section of the target layer, a designed horizontal section length of 2,000m, and a water-drag ratio of nearly 2:1, so the well is characterised by the difficulty of pressurising with a large digit-drag ratio, the high friction between the drilling and the lower casing, and the shale wall being easy to be destabilised and collapsed. There are no horizontal wells in the neighbouring wells with a section of green as the destination layer, and there is a lack of reference materials, and the stability of the shallow shale is not clear. In order to ensure that the well can be reached and drilled for a long time, a technical route was formulated with the objectives of effectively reducing drilling resistance, increasing drilling pressure, and rapid drilling and completion within the collapse cycle, and technical measures such as equipping with a top drive and a high-grade drilling rig to increase the drilling pressure, oil-based drilling fluids and rotary guiding to reduce drilling resistance and the ability to deal with complex situations, and floating casing process to ensure that casing can be smoothly lowered in place, etc., so as to achieve safe and rapid construction of SY1H and achieve a horizontal section of 2,000m. construction and achieve the geological target of 2000m horizontal section.

Optimization of co-injecting CH4 with CO2 to enhanced oil recovery and carbon storage: A machine-learning based case study on H59 block of Jilin Oilfield, China

During CO2-EOR implementation, CH4 in the reproduced CO2-rich mixture are included in the recycle injection gas. However, improper injection gas composition and operation parameters can reduce the flooding performance.In this study, a machine-learning assisted framework combining Convolutional Neural Networks-Gate Recurrent Unit (CNN-GRU) and Non-dominated Sorting Genetic Algorithm II (NSGA-II) was proposed to obtain the optimal parameters for simultaneous maximum oil production, carbon storage efficiency, and net present value. A case study from the CO2-EOR project in the H59 block of Jilin oilfield, China, was carried out. Base cases were established to evaluate the effects of reinjection CH4 on flooding performance.Results show that the built CNN-GRU model has high prediction accuracy and computational efficiency, and thus can be used as an alternative tool to the reservoir simulator. The proposed framework can find the optimum parameters to improve oil recovery, carbon storage and net present value. The co-injection of CH4 and CO2 improves oil production, and carbon storage performance, but reduces the net present value. This work provides engineers with multiple strategies for decision-making to simultaneously promote flooding performance with CH4 being a co-injectant in CO2-EOR projects.

Numerical Simulation Study on Optimizing the Conical Cutter Bit to Break Deep Strata

Background: Methods that are used to obtain oil and gas resources by penetrating deep strata are gradually being developed. The complex lithology of deep strata causes difficulties for traditional drill bits to cut into the rock effectively, which affects the drilling efficiency. Objective: The goal of this work is to optimize the bit structure and design a patented drill bit for more efficient rock breaking. Methods: Through a series of tests, the rock mechanics parameters of deep strata in a block of Jilin Oilfield were measured, and the drill bit model XFXR5195 was selected to best match the lithology of the formation by using the Virtual Strength Index and the Technique for Order Preference by Similarity to an Ideal Solution. Simulation of the rock breaking process of the conical PDC cutter and cylindrical PDC cutter with the finite element method. Results: The simulation results show that the pre-crushing of the conical cutter can effectively reduce the difficulty of the subsequent cylindrical cutter in breaking and cutting rocks under 100 MPa compressive strength rocks; under 50 MPa compressive strength rocks, the combination of the conical cutter and cylindrical cutter are not effective with regards to drilling. Conclusion: The conical PDC cutter has a more uniform force range and more concentrated stress on the rock than the cylindrical PDC cutter. The rock-breaking ability of the conical PDC cutter is higher than that of the cylindrical PDC cutter under different compressive strength rocks and especially in high compressive strength rocks.

Preparation and performance evaluation of a novel temperature-resistant anionic/nonionic surfactant

Aiming at oil extraction from a tight reservoir, the Jilin oil field was selected as the research object of this study. Based on the molecular structures of conventional long-chain alkyl anionic surfactants, a new temperature-resistant anionic/nonionic surfactant (C8P10E5C) was prepared by introducing polyoxyethylene and polyoxypropylene units into double-chain alcohols. The resulting structures were characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (1H-NMR), and electrospray ionization mass spectrometry (ESI–MS). Then, based on surface tension, interfacial tension, adsorption resistance, wettability, and emulsification performance tests, the performance of C8P10E5C was evaluated. The FT-IR, ESI–MS, and NMR spectra confirmed that C8P10E5C was successfully prepared. The critical micelle concentration (CMC) of C8P10E5C in water was 2.9510 × 10−4 mol/L (the corresponding mass concentration is 0.26%), and the surface tension of the aqueous C8P10E5C solution at this concentration was 30.5728 mN/m. At 0.3% concentration, the contact angle of the C8P10E5C solution was 31.4°, which is 60.75% lower than the initial contact angle. Under high-temperature conditions, C8P10E5C can still reduce the oil–water interfacial tension to 10−2 mN/m, exhibiting good temperature resistance. At 110 °C, upon adsorption to oil sand, the C8P10E5C solution could reduce the oil–water interfacial tension to 0.0276 mN/m, and the interfacial tension can still reach the order of 10−2 mN/m, indicating that C8P10E5C has strong anti-adsorption capability. Additionally, it has good emulsifying performance; upon forming an emulsion with crude oil, the highest drainage rate was only 50%. The forced imbibition oil recovery of C8P10E5C is 65.8%, which is 38.54, 24.22, and 27.25% higher than those of sodium dodecyl benzene sulfonate, alkyl polyoxyethylene ether carboxylate, and alkyl ether carboxylate, respectively.

Metabolic profiling of petroleum-degrading microbial communities incubated under high-pressure conditions.

While pressure is a significant characteristic of petroleum reservoirs, it is often overlooked in laboratory studies. To clarify the composition and metabolic properties of microbial communities under high-pressure conditions, we established methanogenic and sulfate-reducing enrichment cultures under high-pressure conditions using production water from the Jilin Oilfield in China. We utilized a metagenomics approach to analyze the microbial community after a 90-day incubation period. Under methanogenic conditions, Firmicutes, Deferribacteres, Ignavibacteriae, Thermotogae, and Nitrospirae, in association with the hydrogenotrophic methanogen Archaeoglobaceae and acetoclastic Methanosaeta, were highly represented. Genomes for Ca. Odinarchaeota and the hydrogen-dependent methylotrophic Ca. Methanosuratus were also recovered from the methanogenic culture. The sulfate-reducing community was dominated by Firmicutes, Thermotogae, Nitrospirae, Archaeoglobus, and several candidate taxa including Ca. Bipolaricaulota, Ca. Aminicenantes, and Candidate division WOR-3. These candidate taxa were key pantothenate producers for other community members. The study expands present knowledge of the metabolic roles of petroleum-degrading microbial communities under high-pressure conditions. Our results also indicate that microbial community interactions were shaped by syntrophic metabolism and the exchange of amino acids and cofactors among members. Furthermore, incubation under in situ pressure conditions has the potential to reveal the roles of microbial dark matter.

Carbon emission reduction accounting method for a CCUS-EOR project

It is difficult to quantify and certify the greenhouse gas (GHG) emission reduction in the entire process of a project of carbon capture, utilization and storage (CCUS)-enhanced oil recovery (EOR). Under the methodological framework for GHG voluntary emission reduction project, the carbon emission reduction accounting method for CCUS-EOR project was established after examining the accounting boundaries in process links, the baseline emission and project emission accounting methods, and the emission and leakage quantification and prediction models, in order to provide a certification basis for the quantification of GHG emission reduction in the CCUS-EOR project. Based on the data of energy consumption, emission and leakage monitoring of the CCUS-EOR industrial demonstration project in Jilin Oilfield, the net emission reduction efficiency is determined to be about 91.1% at the current storage efficiency of 80%. The accounting and prediction of carbon emission reduction for CCUS-EOR projects with different concentrations and scales indicate that within the project accounting boundary, the certified net emission reduction efficiency of the low-concentration gas source CCUS-EOR projects represented by coal-fired power plants is about 37.1%, and the certified net emission reduction efficiency of the high-concentration gas source CCUS-EOR projects represented by natural gas hydrogen production is about 88.9%. The proposed method is applicable to the carbon emission reduction accounting for CCUS-EOR projects under multiple baseline scenarios during the certification period, which can provide decision-making basis for the planning and deployment of CCUS-EOR projects.

Key Problems and Countermeasures in CO2 Flooding and Storage

AbstractBased on literature research in combination with the practice of CO2 flooding and storage in Jilin Oilfield, this study assesses the key problems in CO2 flooding and storage, proposing the corresponding countermeasures from five aspects of CO2 gas source condition, namely geological condition evaluation, scheme design incoordination with other production methods, economic and effectiveness evaluation, together with dynamic monitoring and safety evaluation. The results show that CO2 flooding is the most economic and effective CO2 storage method. In eastern China, inorganic origin CO2 gas reservoirs are widely developed and are especially the most enriched in the Paleozoic carbonate rock strata and the Cenozoic Paleogene–Neogene system, which provide a rich resource base for CO2 flooding and storage. In the future, CO2 generated in the industrial field will become the main gas source of CO2 flooding and storage. The evaluation of geological conditions of oil and gas reservoirs is the basis for the potential evaluation, planning scheme design and implementation of CO2 flooding and storage. CO2 storage should be below the depth of 800 m, the CO2 flooding and storage effects in low‐permeability oil reservoirs being the best. CO2 geological storage mechanisms primarily consist of tectonic geological storage, bound gas storage, dissolution storage, mineralization storage, hydrodynamic storage and coalbed adsorption storage. The practice of CO2 flooding and storage in Jilin Oilfield demonstratesthat the oil increment by CO2 flooding is at least 24% higher than by conventional water flooding. The most critical factor determining the success or failure of CO2 flooding and storage is economic effectiveness, which needs to be explored from two aspects: the method and technology innovation along with the carbon peaking and carbon neutrality policy support. After CO2 is injected into the reservoir, it will react with the reservoir and fluid, the problem of CO2 recovery or overflow will occur, so the dynamic monitoring and safety evaluation of CO2 flooding and storage are very important. This study is of great significance to the expansion of the application scope of CO2 flooding and storage and future scientific planning and deployment.

Carbon dioxide capture, enhanced-oil recovery and storage technology and engineering practice in Jilin Oilfield, NE China

This paper systematically presents the established technologies and field applications with respect to research and engineering practice of CO2 capture, enhanced oil recovery (EOR), and storage technology in Jilin Oilfield, NE China, and depicts the available series of supporting technologies across the industry chain. Through simulation calculation + pilot test + field application, the adaptability of the technology for capturing CO2 with different concentrations in oilfields was confirmed. The low energy-consumption, activated N-methyl diethanolamine (MDEA) decarburization technology based on a new activator was developed, and the operation mode of CO2 gas-phase transportation through trunk pipeline network, supercritical injection at wellhead, and produced gas-liquid separated transportation was established. According to different gas source conditions, liquid, supercritical phase, high-pressure dense phase pressurization technologies and facilities were applied to form the downhole injection processes (e.g. gas-tight tubing and coiled tubing) and supporting anti-corrosion and anti-blocking techniques. In the practice of oil displacement, the oil recovery technologies (e.g. conical water-alternating-gas injection, CO2 foam flooding, and high gas-oil ratio CO2 flooding) and produced fluid processing technologies were developed. Through numerical simulation and field tests, three kinds of CO2 cyclic injection technologies (i.e. direct injection, injection after separation and purification, and hybrid injection) were formed, and a 10×104 m3/d cyclic injection station was constructed to achieve “zero emission” of associated gas. The CO2 storage safety monitoring technology of carbon flux, fluid composition and carbon isotopic composition was formed. The whole-process anti-corrosion technology with anticorrosive agents supplemented by anticorrosive materials was established. An integrated demonstration area of CO2 capture, flooding and storage with high efficiency and low energy-consumption has been built, with a cumulative oil increment of 32×104 t and a CO2 storage volume of 250×104 t.

Discussion on the limit recovery factor of carbon dioxide flooding in a permanent sequestration scenario

Based on practices of CO2 flooding tests in China and abroad, the recovery factor of carbon dioxide capture, utilization in displacing oil and storage (CCUS-EOR) in permanent sequestration scenario has been investigated in this work. Under the background of carbon neutrality, carbon dioxide injection into geological bodies should pursue the goal of permanent sequestration for effective carbon emission reduction. Hence, CCUS-EOR is an ultimate development method for oil reservoirs to maximize oil recovery. The limit recovery factor of CCUS-EOR development mode is put forward, the connotation differences between it and ultimate recovery factor and economically reasonable recovery factor are clarified. It is concluded that limit recovery factor is achievable with mature supporting technical base for the whole process of CCUS-EOR. Based on statistics of practical data of CO2 flooding projects in China and abroad such as North H79 block CO2 flooding pilot test at small well spacing in Jilin Oilfield etc., the empirical relationship between the oil recovery factor of miscible CO2 flooding and cumulative CO2 volume injected is obtained by regression. Combined with the concept of “oil production rate multiplier of gas flooding, a reservoir engineering method calculating CO2 flooding recovery factor under any miscible degree is established by derivation. It is found that when the cumulative CO2 volume injected is 1.5 times the hydrocarbon pore volume (HCPV), the relative deviation and the absolute difference between the recovery percentage and the limit recovery factor are less than 5% and less than 2.0 percentage points respectively. The limit recovery factor of CCUS-EOR can only be approached by large pore volume (PV) injection based on the technology of expanding swept volume. It needs to be realized from three aspects: large PV injection scheme design, enhancing miscibility degree and continuously expanding swept volume of injected CO2.

Integrated numerical simulation of CO2 flooding、heat recovery and storage in high temperature reservoir

High temperature reservoir is extensively disseminated over the world. in order to make efficient use of diverse resources in high temperature reservoir, including underused geothermal resources in high temperature reservoir development. By combining CO2 displacement mechanism, CO2 thermal recovery mechanism, and CO2 geological storage mechanism, a comprehensive numerical model of CO2 storage and displacement in high-temperature reservoir is created using the high-temperature reservoir in Jilin Oilfield as the research object. Under high temperature and high pressure, the interaction between CO2 injection and crude oil, hot water, and rock minerals in the formation is investigated. The effects of different development methods and gas injection rate on oil recovery, CO2 heat recovery and CO2 storage capacity were compared. The findings reveal that continuous CO2 infusion miscible flooding provides the best development effect, and that the optimal injection rate should be chosen after taking into account all development effects and economic benefits. The integrated numerical simulation of CO2 flooding, thermal recovery, and storage can not only effectively develop crude oil and geothermal resources in high temperature reservoirs, but also realize CO2 geological storage, realizing the multi-purpose of CO2 and the efficient and cost-effective development of high temperature reservoirs.

Study Describes Challenges, Opportunities of CO2 EOR in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209468, “CCUS In China: Challenges and Opportunities,” by Hu Guo, China University of Petroleum; Xiuqin Lyu, Sinopac Northwest Oil Field Company; and En Meng, China University of Petroleum, et al. The paper has not been peer reviewed. One of the most attractive carbon capture, usage, and storage (CCUS) applications in China is that of carbon dioxide (CO2) enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 presents an important path for China. The complete paper reviews the progress of CCUS technology in China. The current challenges of CCS EOR include high capture costs, small scale, low incremental oil recovery, and huge capital input. The costs can be significantly reduced when the scale is enlarged to the commercial level and transportation costs are further reduced by pipelines or trains. Importance of CCUS At the time of writing, 49 CCUS pilots or field tests had been conducted or were under construction in China. CCUS demonstration projects were small-scale, and no projects involving more than 1.0 million tons of CO2 per year (mtpa) were conducted. 1.3 million tons of CO2 were estimated to be injected in 2020 for EOR use. The authors reference a study that mentions nine CO2 EOR projects. Among these, the Jilin oilfield project was notable for its size of 2.0 million cumulative tons of CO2 injected. CO2-enhanced coalbed methane was also an attractive option for China, and several field tests were conducted by CNOOC and its partners. Another notable CCUS demonstration project involved the Shaanxi Jinjie power plant. This was the largest coal-fired power postcombustion (PC) CO2-capture project, with a capture capacity of 0.15 mtpa. The project began in November 2019. In January 2021, equipment installation was completed. By June of 2021, 168 trial operations had been passed. The captured CO2 will be used for EOR. This demonstration project will gain knowledge to reduce PC CO2 emissions, a great challenge for China because the majority of electricity is based on coal combustion. Gas processing and power plants rank first for the US in terms of CCUS project numbers. Power plants also rank first in the number of CCUS projects for China, but the number of natural-gas-processing projects was much less.

A circuit design framework of electromagnetic wave resistivity logging while drilling instrument

Abstract Formation resistivity is an important geological parameter necessary for geosteering drilling and oilfield formation evaluation. At present, the mainstream resistivity measurement methods mainly include current measurement and electromagnetic wave measurement. Current resistivity measurement is difficult to be applied in drilling fluids with poor conductivity or non-conductivity, while electromagnetic wave resistivity measurement is suitable for various types of conductive and non-conductive drilling fluids. Nowadays, the most important geological guiding tool for Sichuan-Chongqing Shale Gas, Xinjiang Oilfield, Jilin Oilfield, Daqing Oilfield and Qinghai Oilfield Company rely on electromagnetic wave resistivity measurement, and the market demand is about 90 million yuan per year. Western Drilling, Chuanqing Drilling and Bohai Drilling have more than 100 branches of electromagnetic wave resistivity logging while drilling instrument, and the market demand is about 21 ∼30 million yuan per year. Domestic electromagnetic wave resistivity logging while drilling instrument mainly rely on imports. At the same time, after field application, it needs to be sent back to the original factory for maintenance. Therefore, it is very necessary to design an electromagnetic wave resistivity logging while drilling instrument with independent intellectual property rights.

Modular zonal fluid sampling and pressure testing technology for production well

To accurately obtain development dynamic data such as zonal pressure and fluid parameters of each oil layer in the late development stage of a high water-cut old oilfield, a modular zonal sampling and testing technology with the characteristics of modularization, full electronic control and rapidity was proposed and developed. Lab testing and on-site testing was carried out. The modular zonal sampling and testing system is composed of 10 functional modules, namely ground control system, downhole power supply module, drainage pump, electronically controlled anchor, electronically controlled packer, electronically controlled sampler, magnetic positioning sub, terminal sub, adapter cable, and quick connector. Indoor tests have confirmed that the performance parameters of each module meet the design requirements. The downhole function modules of the system can withstand pressures up to 35 MPa and temperatures up to 85 °C. The rubber cylinder of the electronically controlled packer can withstand a pressure difference of more than 10 MPa. The electronically controlled anchor has an anchoring force of greater than 6.9 t, and can be forcibly detached in the event of an accident. The discharge pump has a displacement of 0.8 m3/d and a head of 500 m. The electronically controlled sampler can meet the requirement of taking 500 mL of sample in each of the 3 chambers. Field tests in Jilin Oilfield show that the system can realize rapid isolation and self-check of isolation of a certain production interval downhole, as well as layer-by layer pressure build-up test. The drainage pump can be used to discharge the mixed liquid between the upper and lower packers and near the wellbore to obtain real fluid samples of the tested formation interval. The data obtained give us better understanding on the pay zones in old oilfields, and provide important basis for development plan adjustment, reservoir stimulation, and EOR measures.

Mechanism of Improving Water Flooding Using the Nanofluid Permeation Flooding System for Tight Reservoirs in Jilin Oilfield

Mechanism of Improving Water Flooding Using the Nanofluid Permeation Flooding System for Tight Reservoirs in Jilin Oilfield

Volcanic lithology identification based on parameter-optimized GBDT algorithm: A case study in the Jilin Oilfield, Songliao Basin, NE China

The reservoir rocks in the volcanic strata of the Jilin oil field are characterized by great complexity and diversity in composition and structure of lithology. To enhance the rate of lithology identification in subsurface is very laborious. However, lithology identification is often ignored in quantitative studies, though it is the basis for reservoir characterization. In this paper, an ensemble learning algorithm named gradient boosting decision tree (GBDT) was used to establish the classification model for the volcanic lithology identification of the Lower Cretaceous Yingcheng Formation in the Songliao Basin, NE China. At the same time, support vector machine (SVM), logistic regression (LR) and decision tree (DT) classification models were also adopted in contrast with the classification accuracy of GBDT model. Subsequently, the optimal key parameters for each model were determined by employing validation curves and GridSearchCv. These results indicate that the GBDT model is superior to the single classifier and can accurately distinguish the lithologic interface of breccia tuff and rhyolite. Moreover, it also has better recognition ability for thin layer. It was concluded that the ensemble learning algorithm GBDT has significantly enhanced the accuracy of lithology identification and can be used as a lithologic identification technology.

Comprehensive evaluation of waterflooding front in low‐permeability reservoir

AbstractDue to the development characteristics of low‐permeability reservoirs such as weak water absorption, slow development of water injection, and strong pressure sensitivity, the effect of water injection in low‐permeability reservoirs is quite different from that in medium and high‐permeability reservoirs. Therefore, in oilfield development, it is important to study the movement law of the waterflooding front in low‐permeability reservoirs. In this paper, taking the Jilin oilfield as an example, a geological model of Xinmin 23 Block was established for the numerical simulation analysis considering the heterogeneity of low‐permeability reservoirs. In addition, artificial cores were manufactured to conduct the physical experiment of the waterflood front advance of cores with different physical properties under the influence of various factors such as the fracture and the range by the constant‐velocity flooding. Based on the numerical simulation and the physical experiment, the movement law of the waterflood front was analyzed and a basic method for evaluating the waterflooding development in low‐permeability reservoirs was established to provide feasible insights for the waterflooding development in low‐permeability reservoirs. In this paper, numerical simulation and experimental studies were performed on the effect of the waterflooding development of Xinmin 23 Block in the Jilin oilfield. The evaluation results obtained were consistent with the actual oil production providing a theoretical basis for judging the accurate advance time from the waterflood front to the production well in actual oil production.

Risk assessment on the CCUS project using risk breakdown structure methodology: A case study on Jilin oilfield CO2‐EOR Hei‐79 block

AbstractThe risk potential matrix method can be used as a reference for the optimization of the traditional risk matrix in geological CO2 storage. This study used monitoring data for environmentally sensitive receptors in the Jilin Oilfield CO2‐enhanced oil recovery (CO2‐EOR) Hei‐79 block in conjunction with a hazard event store to create an updated risk assessment of CO2 capture, use, and storage (CCUS) as a guide for risk management. The assessment built upon the overall project operation status to evaluate six and five sub‐categories of hazard and sensitivity, respectively. The environmental sensitivity threshold integrated ecosystems and secondary geological disasters to amplify potential risks. The results of the risk assessment of the CO2‐EOR Hei‐79 block in the Jilin Oilfield showed that despite an overall risk level of Ⅱ, the hazard level resulted in an unacceptable increase in overall risk. Formations are usually stimulated by fracturing in Jilin Oilfield, particularly for oil and gas production. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

N,S-Heterocycles biodegradation and biosurfactantproduction under CO2/N2 conditions by Pseudomonas and its application on heavy oil recovery

Great challenge of the ultra-heavy oil recovery via cold approaches is attracting the increasing worldwide efforts. Here, we reported a microbial strategy with using the heterocycles-degrading and biosurfactant-producing Pseudomonas strain for heavy oil recovery without thermal energy input. To validate it, we initiated the bacterial evaluation of anaerobically heterocycles degradation and biosurfactant production under CO2 and N2 conditions. Results demonstrated that the CO2 can significantly facilitate the anerobic degradation and influence the yield and diversity of biosurfactant. Structural identification of the biosurfactants by HPLC-MS showed that the di-rhamnolipids and lipopeptides (iturin and fengycin) were respectively accounted for more than 80% and 60% under CO2 condition when fed with carbazole and dibenzothiophene. Degradation of heavy oil under CO2 condition made the better performance on the oil viscosity reducing, the surface tension reducing, emulsification, and oil degrading rate than that under N2 condition. Huff-puff field trials in Jilin oilfield successfully demonstrated that the cumulative oil production was increased from 48 tons to 566 tons with the effective period of more than 9 months, and the viscosity of the produced oil was significantly decreased by 50–65%. These results suggested that this green strategy was promising and economical to the oil recovery for the ultra-heavy reservoir where is easily accessible to CO2.