bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research on Plugging Mechanism and Optimisation of Plug Removal Measure of Polymer Flooding Response Well in Bohai Oilfield
Authors: Chen Huaxing , Wang Yufei , Pang Ming , Fang Tao , Zhao Shunchao , Wang Zhiyuan , Zhou Yugang 
Published: March 2021

Abstract
Since the field test of polymer flooding technology was carried out in the Bohai Oilfield in 2003, problems such as plugging of polymer-response wells have become increasingly worse, and conventional acidizing and plugging removal measures have had poor results. Therefore, this paper carries out research to provide a basis for effective plug removal in oil wells, to improve the productivity of polymer flooding oil wells.
In this paper, the component analysis of the plug samples from the benefit injection wells in the field was carried out. The clogging mechanism was studied through X-ray diffraction, scanning electron microscopy, energy spectrum analysis, infrared spectroscopy, and chromatography, as well as through dynamic simulation evaluation of plugs and dynamic displacement experiments of long cores. Through simulation experiments, the clogging mechanism is clarified and the blockage radius range was obtained by various methods such as inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation.
The analysis results of the plugs show that the inorganic components of the plugs are calcium and magnesium carbonate scales, clay minerals and iron salt precipitation, and the organic components are the micelles formed by the crosslinking of trivalent metal ions. The greater the concentration of polymer produced, the greater the strength of calcium-magnesium scale aggregates and aluminum-iron-colloid elastomer, the greater the degree and depth of reservoir pore throat clogging, the larger the screen clogging area, which will even block the inlet of electric submersible pump. This will result in poor acidizing plugging effect and rapid decline in oil well productivity. Through various methods such as the inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation, the blockage radius of polymer flooding response wells is greater than 4 meters. Based on this understanding, in the five wells plug removal measures, the unblocking radius and unblocking chemical agent system were adjusted and optimized. On-site application effect tracking shows that the plug removal measures have achieved good oil incremental effects, and the measures are all effective.
Through the classification and comparison of oil well productivity characteristics, formation water composition, output polymer properties and other characteristics, this paper established the identification mark of plugging of polymer-response wells. In addition, an analysis method for clogging was established to clarify the composition and formation mechanism of the clogging. Finally, the plug radius calculation method was established by means of backstepping the effects of plug removal measures and well test interpretation analysis.
Investigation on Insulated Tubing Corrosion in Nanbu 35-2 Multi-Thermal Fluid Project
Authors: Hao Tongchun , Zhong Liguo , Wang Cheng , Zhu Tianyin , Liu Jianbin , Sun Hongyu 
Published: March 2021

Abstract
Multi-thermal fluid simulation was conducted for offshore heavy oil reservoir such as Nanbu 35-2 in Bohai Bay Oilfield since 2008. Field well integrity testing result shows that Insulated tubing corrosion is found in many multi-thermal fluid injection wells. Insulated tubing corrosion has become one of the largest problems in the multi-thermal fluid project. It will negatively affect the development performance and also indeed a risky operation under high temperature and high pressure. In order to effectively prevent the corrosion problem of insulated tubing, the principles of insulated tubing corrosion and preventive measures are investigated. At first, temperature-pressure measurement and gas analysis were carried out in the multi-thermal fluid injection wells in Nanbu 35-2 heavy oilfield. Secondly, the corrosion laws of N80 and P110 steel in high temperature and high pressure CO2/O2 system were studied. At last, the corrosion mitigation effect of imidazoline corrosion inhibitor was evaluated through dynamic coupon test method. The results indicated that temperature, oxygen partial pressure and carbon dioxide partial pressure have effect on corrosion rate. Two peaks of corrosion rate of N80 and P110 steel appeared at 60°C and 180°C respectively, in the CO2/O2 system, even a little amount of O2 (partial pressure of 0.02MPa) could remarkably speed up corrosion. The corrosion rate drastically increased when carbon dioxide partial pressure exceeded 2MPa. The imidazoline corrosion inhibitor could lower the corrosion rate to 0.11 mm/a when the concentration was set at 750mg/L, and corrosion inhibition rate was high up 94.17%. The performance of the imidazoline corrosion inhibitor has been tested in field and results showed that the insulated tubing wasn’t corroded after using the corrosion inhibitor, which indicated that the corrosion inhibitor could meet the corrosion protection requirement of P110 steel in high temperature CO2/O2 system. The principles of insulated tubing corrosion in multi-thermal fluid injection wells is complicate because of multicomponent of multi-thermal fluid and high temperature and high pressure during its injection process. This study can provide basis for the design of insulated tubing in multi-thermal fluid project.
The Feasibility Appraisal for CO2 Enhanced Gas Recovery of Tight Gas Reservoir: Case Analysis and Economic Evaluation
Authors: Jia Ying , Shi Yunqing , Yan Jin 
Published: March 2021

Abstract
Tight gas reservoirs are widely distributed in China, which occupies one-third of the total resources of natural gas. The typical development method is under primary depletion. However, the recovery of tight gas is only around 20%. It is necessary to explore a new technique to improve tight gas recovery.
Injecting CO2 into tight gas reservoirs is a novel trial to enhance gas recovery. The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery of tight gas reservoir.
Taken DND tight sandstone gas reservoir in North China as an example, 34 wells of DK13 wellblock were chosen as CO2 Enhanced gas recovery pilot area with 10-year production history. Six injection scenarios were studied. Numerical simulation indicated that the recovery of the gas reservoir of DK13 well area was improved by 8-9.5 percent when CO2 content of producers reaches 10 percent. The annual CO2 Storage would be 62 million cubic meters (110 thousand tons) and the total CO2 storage would be around 800million cubic meters (1.5 million tons). After the environmental parameter evaluation of injectors and producers, the anticorrosion schemes were put forward and the feasibility evaluation and schemes of facilities were presented. The analysis results indicated that DK13 wellblock was suitable for CO2 enhanced gas recovery no matter geologic condition, injection & production technology and facilities. However, under the current economic conditions, DK13 wellblock was not suitable for CO2to enhance gas recovery. However, if gas price rise or low carbon strategy implement, the pilot test could be carried out.
In brief, CO2 could be an attractive option to successfully displace natural gas and decrease CO2 emissions, which is a promising technology for reducing greenhouse gas emission and increasing the ultimate gas recovery of tight gas reservoirs.
This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
Adsorption Modeling of CO2 and CH4 in Nanopores Using Simplified Local Density Model: Application in Enhanced Hydrocarbon Recovery in Unconventional Reservoirs
Authors: Haghshenas Alireza , Hamedpour Mohammad 
Published: March 2021

Abstract
Adsorption isotherms of methane and carbon dioxide adsorption isotherms on shale samples are measured and the simplified local density (SLD) model is used to match the experimental data. The SLD equation also has the generic modeling capabilities to draw the deviation from bulk properties as a function of fluid-solid interaction energies. Still, compared to other available techniques such as molecular simulation, SLD has an advantage of mathematical simplicity and being run at shorter time interval. The model also has satisfactory potential to paint the underlying mechanisms for adsorption preference of one fluid component over the other.
The higher adsorption preference of carbon dioxide is reflected in the measurement data and the adsorption model is successfully used to fit the data. In addition to different critical properties of carbon dioxide compared to methane, the main important factor that may describe the high adsorption affinity of carbon dioxide is the fluid-solid potential energy. As shown in this work, the potential energy function shows deeper well depth, the deeper the well depth, the stronger the interaction between the fluid particles and solid surface.
By storing gas in high density, liquid like adsorbed phase, the adsorption mechanism can enhance the overall storage capacity of CO2 in deep reservoir rock relative to if there were a free phase alone.
Zero-Flaring Mudcake Removal: New Techniques for Efficient Natural Cleanup of Horizontal/Multilateral Open-Hole Wells
Authors: Alrabaei Rayan , Albarghouti Akram , Balto Abdulelah , Alkhaldi Mohammed 
Published: March 2021

AbstractEffective mudcake removal is essential to restore the optimal well productivity/injectivity after different drilling operations. Typically, this objective is achieved by using harsh chemical treatments such as hydrochloric acid (HCl), organic acids and oxidizers. However, these methods have been limited due to associated high corrosion rates, high operation cost, and un-even mudcake removal. This task becomes even more difficult and very challenging in horizontal/multilateral wells. Organic acids and acid precursors have been also used to clean long horizontal wells following drilling operations. However, in long multilateral horizontal wells, fluid placement is considered one of the main challenges with chemical mudcake removal treatments due to accessibility to each lateral and reaching its TD. Additionally, the use of these treatments has poor health, safety and environmental (HSE) footprints.This work provides a workflow and illustrates the use of an in-house designed zero-flaring flowback system to clean up recently drilled multilateral horizontal wells with water-based mud. The system consists of two upstream solid management systems, namely de-sander (cyclone), and sand catcher (filter). Downstream, the choke manifold, 4-phase separator, a downstream solid management equipment, and 3-phase separator are also included. Additionally, there is also a surge tank, as a backup flowback vessel to be used if needed to revive the well and offload any heavy fluids. This tank is used to initially help the well to gain the pressure momentum to naturally flow and offload heavy fluid present in production tubular. The cleanup campaign was successfully and safely completed for effective cleanup of more than 30 openhole horizontal multilateral wells without the use of any chemical treatments. The duration of cleanup operations was optimized using several techniques to effectively and efficiently remove existing mudcake.This paper provides the operational criteria to achieve effective and adequate mudcake removal for horizontal/multilateral wells and restore its optimal performance. Different design parameters and tailored flowback programs will be discussed, which led to effective drawdown pressure to reach optimized natural cleanup of each well. The well simulated flow model was also considered and used as input to design each well specific flowback program and minimize the risks of erosion, solids settlement in pipeline and downstream facilities. As a result, each well cleanup duration was reduced to an average of 1-2 day, while achieving the maximum potential production rate of each treated well.
Geologic Modelling Using Augmented Reality
Authors: Boonyasaknanon Phathompat , Pols Raymond , Schulze Katja , Rundle Robert 
Published: March 2021

Abstract
An augmented reality (AR) system is presented which enhances the real-time collaboration of domain experts involved in the geologic modeling of complex reservoirs. An evaluation of traditional techniques is compared with this new approach.
The objective of geologic modeling is to describe the subsurface as accurately and in as much detail as possible given the available data. This is necessarily an iterative process since as new wells are drilled more data becomes available which either validates current assumptions or forces a re-evaluation of the model. As the speed of reservoir development increases there is a need for expeditious updates of the subsurface model as working with an outdated model can lead to costly mistakes. Common practice is for a geologist to maintain the geologic model while working closely with other domain experts who are frequently not co-located with the geologist. Time-critical analysis can be hampered by the fact that reservoirs, which are inherently 3D objects, are traditionally viewed with 2D screens. The system presented here allows the geologic model to be rendered as a hologram in multiple locations to allow domain experts to collaborate and analyze the reservoir in real-time.
Collaboration on 3D models has not changed significantly in a generation. For co-located personnel the approach is to gather around a 2D screen. For remote personnel the approach has been sharing a model through a 2D screen along with video chat. These approaches are not optimal for many reasons. Over the years various attempts have been tried to enhance the collaboration experience and have all fallen short. In particular virtual reality (VR) has been seen as a solution to this problem. However, we have found that augmented reality (AR) is a much better solution for many subtle reasons which are explored in the paper.
AR has already acquired an impressive track record in various industries. AR will have applications in nearly all industries. For various historical reasons, the uptake for AR is much faster in some industries than others. It is too early to tell whether the use of augmented reality in geological applications will be transformative, however the results of this initial work are promising.
Flowback Stimulation of Frac Fluid in Tight Oil Reservoirs Through Supercritical Condition
Authors: Li Ying , Ai Ying , Li Haitao , Chen Mingjun 
Published: March 2021

Abstract
Tight sandstone reservoirs are an important petroleum resources in recent years. Hydraulic fracturing is widely used to stimulate development of tight sandstone oil reservoirs by creating underground fractures, but the low flowback rate of fracturing fluid leads to the water blocking damage and low oil recovery of tight sandstone oil reservoirs compared with those of conventional oil reservoirs. The object of this study is to experimentally investigate the possibility of improving flowback efficiency and oil recovery efficiency through achievement of the supercritical water condition. Self-developed reaction system is used to conduct hydraulic fracturing for tight sandstone samples under both regular and supercritical conditions. While comparing the oil recovery factor and flowback efficiency of the regular and supercritical water hydraulic fracturing, mechanisms behind these results are explored through examination of the change in oil components, the change in rock minerals and the change in pore-fracture distribution. Results show that the dynamic viscosity of the crude oil after the supercritical water hydraulic fracturing is significantly lower than that before hydraulic fracturing, with a decrease of 2.88 mPa·s under ambient condition and a decrease of 0.39 mPa·s under in situ condition. Lighter oil components occupy more percentage of the totoal oil components in the recovered oil from supercritical water hydraulic fracturing than that in the oil recovered from regular hydraulic fracturing, with an average increase of 16% for the oil components of molecular weight from 100 to 200. Heavier oil components of molecular weight larger than 300 have an average decrease of 15.5% after the supercritical water hydraulic fracturing. This indicate the visbreaking of the crude oil under the supercritical water condition. Oil recovery after supercritical water hydraulic fracturing is always higher than that after regular hydraulic fracturing, and the ultimate oil recovery after supercritical water hydraulic fracturing is 66.5% compared with 60% of regular hydraulic fracturing. Fracturing fluid after the supercritical water condition flows much quicker and smoothly than that after the regular hydraulic fracturing, and the ultimate flow back factor of the fracturing fluid is 63% after the supercritical water hydraulic fracturing compared with that of 49% after the regular hydraulic fracturing. Increase in percentage of larger pores/fractures after the supercritical water hydraulic fracturing is more significant than that after regular hydraulic fracturing. The percentage of interstratified illite-montmorillonite decreases an average of 15.2%, while that of kaolinite increase an average of 14.3% in the rock samples after supercritical water hydraulic fracturing compared with the original rock samples. This will benefit the recovery process when oil and water flows together into the well bore after the hydraulic fracturing.
A New Artificial Intelligence Method to Predict Water Flooding Performance in Layered Reservoir
Authors: Chen Cunliang , Han Xiaodong , Zhang Wei , Zhang Yanhui , Zhou Fengjun 
Published: March 2021

Abstract
The ultimate goal of oilfield development is to maximize the investment benefits. The reservoir performance prediction is directly related to oilfield investment and management. The traditional strategy based on numerical simulation has been widely used with the disadvantages of long run time and much information needed. It is necessary to form a fast and convenient method for the oil production prediction, especially for layered reservoir.
A new method is proposed to predict the development indexes of multi-layer reservoirs based on the injection-production data. The new method maintains the objectivity of the data and demonstrates the superiority of the intelligent algorithm. The layered reservoir is regarded as a series of single layer reservoirs on the vertical direction. Considering the starting pressure gradient of non-Newtonian fluid flow and the variation of water content in the oil production index, the injection-production response model for single-layer reservoirs is established. Based on that, a composite model for the multi-layer reservoir is established.
For model solution, particle swarm optimization is applied for optimization of the new model. A heterogeneous multi-layer model was established for validation of the new method. The results obtained from the new proposed model are in consistent with the numerical simulation results. It saves a lot of computing time with the incorporation of the artificial intelligence methods. It showed that this technique is valid and effective to predict oil performance in layered reservoir. These examples showed that the application of big data and artificial intelligence method is of great significance, which not only shortens the working time, but also obtains relatively higher accuracy.
Based on the objective data of the oil field and the artificial intelligence algorithm, the prediction of oil field development data can be realized. This technique has been used in nearly 100 wells of Bohai oilfields. The results showed in this paper reveals that it is possible to estimate the production performance of the water flooding reservoirs.
Downhole Sludge: Formation, Characterization and Removal
Authors: Al-Taq Ali , Al-Moajil Abdullah , Aldarweesh Sajjad , Al-Abbas Hussain 
Published: March 2021

AbstractSludge formed downhole in the production interval can be classified into crude oil-based or mud-based sludge. Sludge obstruction may result in partial or total loss of well productivity. Oil-based mud is commonly used in drilling of the pay zones in sandstone formations as a less/non damaging fluid. Oil-based mud typically contain emulsifier, viscosifer and other additives including polymer blend and calcium carbonate to serve different functions. Presence of emulsifier may increase emulsion tendency upon interaction with downhole environment. The resulting emulsion might be tight to an extent that a thick sludge is formed which can impair well productivity. Similarly, oil-based sludge may form from oil/water interaction in presence of emulsifiers, asphaltene, wax, solids, shear, etc. Identification of the sludge material will help in development of an effective chemical treatment to remove formation damage and restore well productivity.In this study, an extensive laboratory work was conducted to explore potential interactions of different downhole environment contaminants/factors on formation of oil-based and mud-based sludge. Typical mud-based and crude oil-based sludge samples were characterized using different analytical techniques including solvent extraction, XRD, TGA, ICP and viscosity. The results showed that the mud-based sludge sample contained calcium carbonate, dolomite quartz as the main components in the inorganic phase while the organic phase include polymers and oil. The oil-based sludge sample contained mainly water (82 wt%) with some solid particulates and asphaltene in the organic phase. Analysis of supernatants generated from solubility tests conducted for the mud-based and oil-based sludge samples revealed in addition to the high amount of calcium presence of iron in considerable amount (nearly 1,000 mg/L). Interaction of ferric chloride, quartz with an invert-emulsion mud was investigated. A significant increase in viscosity was observed upon incorporation of these contaminates with the mud sample. Iron ions in the aqueous phase tended to stabilized emulsion. This paper presents in detail mechanisms of mud-based and crude oil-based sludge formation upon interaction with environment. It also examined several chemical formulations for removal of mud-based and oil-based sludge samples.