scholarly journals Study on Micro Displacement Mechanism of Hydraulic Fracturing by Oil Displacement Agent at High Pressure

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-11
Author(s):  
Fengjiao Wang ◽  
Xu Wang ◽  
Yikun Liu ◽  
Qingjun Deng ◽  
Jianan Hu ◽  
...  
Keyword(s):  
High Pressure ◽  
Hydraulic Fracturing ◽  
Point Contact ◽  
Rock Surface ◽  
Mineral Particle ◽  
Residual Oil ◽  
Pore Throat ◽  
Overburden Pressure ◽  
Recovery Method ◽  
Oil Displacement

The type-III oil formations in Daqing Oilfield are the representatives of medium-low permeability reservoirs in ultrahigh water cut oilfields of China, which is characterized by bad connectivity of pores and throats, dispersed residual oil distribution, and difficult to displace effectively. In order to produce the residual oil, we propose a new EOR (enhanced oil recovery) method which is hydraulic fracturing by an oil displacement agent at high pressure. In this paper, firstly, we have performed three sets of displacement experiments under different conditions to provide the basis for the analysis of changes in core pore structure and wettability. Next, overburden pressure porosity and permeability tests were used to analyze the effect of the injection of an oil displacement agent at high pressure on core physical properties. Correspondingly, the constant speed mercury injection tests were used to determine the radius distribution of pore throat and change of seepage resistance under different displacement conditions. Moreover, the scanning electron microscopy (SEM) tests of cores were carried out to observe and analyze changes in pore-throat size and connectivity, mineral particle accumulation, and cementation before and after hydraulic fracturing by an oil displacement agent at high pressure. Finally, core wettability tests were conducted to discuss and analyze the rule of core wettability change in hydraulic fracturing by an oil displacement agent at high pressure, and its mechanism of wettability changes. Research shows that increasing the formation energy is the most important mechanism of EOR by a fracturing-seepage-displacement method. Additionally, the type of an oil displacement agent has less effect. After an oil displacement agent at high pressure is injected to fracture the formation, it not only provides efficient flow channel and larger sweep volume for an oil displacement agent. Under the flushing action of high-pressure injection fluid, the original way of line or point contact between mineral particles gradually changes to free particles. Therefore, the pore throat size increases, some larger pores are formed, and the overall flow resistance decreases. After the injection of fluid at high pressure, the energy in formation has increased and the core wettability changes from oil-wet to weakly water-wet. This is not only because the residual oil on the pore surface is flushed by high pressure; in addition, the adsorption of an oil displacement agent on the rock surface reduces the liquid-solid interface energy and changes the wettability, thus improving the oil displacement efficiency.

Research on Number of High-Pressure Grouting of Hierarchical Multiple for Slope Based on Reliability Analysis

2014 ◽  
Vol 716-717 ◽  
pp. 363-369
Author(s):  
Zhen Hua Xie ◽  
Dong Yang ◽  
Sha Sha Liang ◽  
Zhi Yun Jia
Keyword(s):  
High Pressure ◽  
Rock Mass ◽  
System Analysis ◽  
Rock Surface ◽  
Rock Permeability ◽  
Iron Mine ◽  
Probability Calculation ◽  
Before And After ◽  
Pressure Grouting ◽  
First Time

The technology of hierarchical multiple high-pressure grouting is an effective approach to manage high and steep slope of broken rock mass. The number of grouting is one of the key parameters of this technology. By the analysis of mechanics and grouting theory, the anchoring effect mainly is affected by anchor slurry vein and the contact area with rock mass. Based on the system analysis of slurry vein development for first time and many times high-pressure grouting, the process flow for hierarchical multiple high-pressure grouting is put forward. Serve the rock permeability changes before and after grouting as an indicator measuring slurry and rock surface area, the method of determining grouting number based on the reliable probability is got. Combined with the engineering example of Shouyun Iron Mine, this paper puts forward the reliability criteria of working state of hierarchical multiple high-pressure grouting. Through the probability calculation, the best number of grouting is 4 times. The tests of permeability of rock mass and drawing force verify the accuracy of this determination method.

High Pressure, High Temperature Bioreactors as a Biocide Selection Tool for Hydraulically Fractured Reservoirs

2021 ◽  
Author(s):  
Joseph Ferrar ◽  
Philip Maun ◽  
Kenneth Wunch ◽  
Joseph Moore ◽  
Jana Rajan ◽  
...  
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Field Trials ◽  
Detectable Level ◽  
Program Optimization ◽  
Microbial Counts ◽  
Selection Tool ◽  
High Pressure High Temperature

Abstract We report the design, operation and biogenic souring data from a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors for hydraulically fractured shale reservoirs. These bioreactors vet the ability of microbial control technologies, such as biocides, to prevent the onset of microbial contamination and reservoir souring at larger experimental volumes and higher pressures and temperatures than have been previously possible outside of field trials. The bioreactors were charged with proppant, crushed Permian shale, and sterile simulated fracturing fluids (SSFF). Subsets of bioreactors were charged with SSFF dosed with either no biocide, tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), or 4,4-dimethyloxazolidine (DMO, a preservative biocide). The bioreactors were shut in under 1,000-2,500 psi and elevated temperatures for up to fifteen weeks; hydrogen sulfide (H2S) and microbial counts were measured approximately once per week, and additional microbes were introduced after weeks three and five. Across two separate studies, the bioreactors containing no biocide soured within the first week of shut-in and H2S concentrations increased rapidly beyond the maximum detectable level (343 ppm) within the first three to six weeks of shut-in. In the first study, the bioreactors treated with TTPC soured within two weeks of shut-in (prior to the first addition of fresh microbes), and H2S concentrations increased rapidly to nearly 200 ppm H2S within the first six weeks of shut-in and beyond the maximum detectable level after fifteen weeks of shut-in. The bioreactors containing DMO did not sour during either study until at least the first addition of fresh microbes, and higher levels of the preservative biocide continued to prevent the biogenic formation of H2S even during and after the addition of fresh microbes. Microbial counts correlate with the H2S readings across all bioreactor treatments. The differentiation in antimicrobial activity afforded by the different types of biocide treatments validates the use of these simulated laboratory reservoirs as a biocide selection tool. This first-of-its-kind suite of HPHT Bioreactors for hydraulic fracturing provides the most advanced biocide selection tool developed for the hydraulic fracturing industry to date. The bioreactors will guide completions and stimulation engineers in biocide program optimization under reservoir-relevant conditions prior to beginning lengthy and expensive field trials.

scholarly journals Effect of Surface Wettability on Immiscible Displacement in a Microfluidic Porous Media

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 664 ◽  
Author(s):  
Jorge Avendaño ◽  
Nicolle Lima ◽  
Antonio Quevedo ◽  
Marcio Carvalho
Keyword(s):  
Porous Media ◽  
Water Injection ◽  
Residual Oil ◽  
Strong Function ◽  
Fluid Displacement ◽  
Oil Displacement ◽  
Displacement Front ◽  
Final Volume ◽  
Displacement Experiments ◽  
Effect Of Surface

Wettability has a dramatic impact on fluid displacement in porous media. The pore level physics of one liquid being displaced by another is a strong function of the wetting characteristics of the channel walls. However, the quantification of the effect is still not clear. Conflicting data have shown that in some oil displacement experiments in rocks, the volume of trapped oil falls as the porous media becomes less water-wet, while in some microfluidic experiments the volume of residual oil is higher in oil-wet media. The reasons for this discrepancy are not fully understood. In this study, we analyzed oil displacement by water injection in two microfluidic porous media with different wettability characteristics that had capillaries with constrictions. The resulting oil ganglia size distribution at the end of water injection was quantified by image processing. The results show that in the oil-wet porous media, the displacement front was more uniform and the final volume of remaining oil was smaller, with a much smaller number of large oil ganglia and a larger number of small oil ganglia, when compared to the water-wet media.

scholarly journals Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

2020 ◽  
Author(s):  
Jing Wang ◽  
Hui-Qing Liu ◽  
Gen-Bao Qian ◽  
Yong-Can Peng
Keyword(s):  
High Pressure ◽  
Hydraulic Fracturing ◽  
Specific Surface ◽  
Surface Area ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Oil Viscosity ◽  
Soaking Time ◽  
Matrix Permeability ◽  
Shale Oil Reservoirs

Abstract Huff-n-puff by water has been conducted to enhance oil recovery after hydraulic fracturing in tight/shale oil reservoirs. However, the mechanisms and capacity are still unclear, which significantly limits the application of this technique. In order to figure out the mechanisms, the whole process of pressurizing, high-pressure soaking, and depressurizing was firstly discussed, and a mechanistic model was established. Subsequently, the simulation model was verified and employed to investigate the significances of high-pressure soaking, the contributions of different mechanisms, and the sensitivity analysis in different scenarios. The results show that high-pressure soaking plays an essential role in oil production by both imbibition and elasticity after hydraulic fracturing. The contribution of imbibition increases as the increase in bottom hole pressure (BHP), interfacial tension, and specific surface area, but slightly decreases as the oil viscosity increases. In addition, it first decreases and then slightly increases with the increase in matrix permeability. The optimal soaking time is linear with the increases of both oil viscosity and BHP and logarithmically declines with the increase in matrix permeability and specific surface area. Moreover, it shows a rising tendency as the interficial tension (IFT) increases. Overall, a general model was achieved to calculate the optimal soaking time.

scholarly journals Relationship between the Molecular Coil Dimension and the Energy Storage Modulus of Polymer Solution Configured with Oilfield-Produced Sewage

2020 ◽  
Vol 2020 ◽  
pp. 1-8
Author(s):  
Peng Wang ◽  
Wenguo Ma ◽  
Yunbao Zhang ◽  
Qiuyan Yan
Keyword(s):  
Polymer Solution ◽  
Water Flooding ◽  
Creep Recovery ◽  
Residual Oil ◽  
Pore Throat ◽  
Solution Composition ◽  
Pore Model ◽  
Polymer Molecules ◽  
Creep Time ◽  
Elasticity Characteristics

Polymer viscoelastic solution is the non-Newtonian fluid and widely used in oil production. In the process of seepage, the mechanism of the polymer solution with different molecular coil dimensions (Dh) flooding on remaining oil is unknown. By using the dynamic light scattering instrument, the molecular coil dimension of the polymer solution is tested. By using the HAAKE rheometer, the creep recovery test data of the polymer solution under the same creep time condition are obtained. The effects of polymer solutions with different Dh on residual oil are observed, by using the visible pore model. The results show that the higher the molecular weight (Mw) of the polymer, the larger the size of the molecular coil dimension. The elasticity characteristics of the polymer solution are sensitive to the molecular coil dimension. As Dh of polymer molecules becomes larger, the contribution of the elastic portion to the viscosity of the polymer solution increases. The higher the Mw of polymer is, the longer the molecular chain is and the size of Dh is larger. On the condition of the polymer solution with different Mw with 2.5 g/L, when Dh is between 320.0 nm and 327.8 nm, the ratio of the elastic part in the apparent viscosity exceeds the proportion of the viscous part, and the polymer solution composition after these data can be used as a comparative study of elasticity for residual oil use. In the visible pore model, the pore-throat ratio is 3.5, the ER of water flooding is 54.26%, the ER of the polymer solution with Dh = 159.7 nm is 75.28%, and the increase of ER is 21.02% than that of water flooding. With the increase of Dh to 327.8 nm, the final ER of the experimental polymer solution is 97.82%, and the increase of ER of the polymer solution than that of water flooding is 43.56%. However, in the model with a pore-throat ratio of 7.0 and the same polymer solution with Dh = 327.8 nm, the increase of ER of the polymer solution is only 10.44% higher than that of water flooding. The effect of the polymer solution with the same Dh is deteriorated with the increase of the pore-throat ratio.

scholarly journals Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant

Molecules ◽  
2020 ◽  
Vol 25 (13) ◽  
pp. 3030
Author(s):  
Amjed Hassan ◽  
Mohamed Mahmoud ◽  
Muhammad Shahzad Kamal ◽  
Syed Muhammad Shakil Hussain ◽  
Shirish Patil
Keyword(s):  
Hydraulic Fracturing ◽  
Phase Behavior ◽  
Relative Permeability ◽  
Gemini Surfactant ◽  
Injection Technique ◽  
Rock Surface ◽  
Hydrocarbon Production ◽  
Liquid Saturation ◽  
Salinity Levels ◽  
New Treatment

Condensate accumulation in the vicinity of the gas well is known to curtail hydrocarbon production by up to 80%. Numerous approaches are being employed to mitigate condensate damage and improve gas productivity. Chemical treatment, gas recycling, and hydraulic fracturing are the most effective techniques for combatting the condensate bank. However, the gas injection technique showed temporary condensate recovery and limited improvement in gas productivity. Hydraulic fracturing is considered to be an expensive approach for treating condensate banking problems. In this study, a newly synthesized gemini surfactant (GS) was developed to prevent the formation of condensate blockage in the gas condensate reservoirs. Flushing the near-wellbore area with GS will change the rock wettability and thereby reduce the capillary forces holding the condensate due to the strong adsorption capacity of GS on the rock surface. In this study, several measurements were conducted to assess the performance of GS in mitigating the condensate bank including coreflood, relative permeability, phase behavior, and nuclear magnetic resonance (NMR) measurements. The results show that GS can reduce the capillary pressure by as much as 40%, increase the condensate mobility by more than 80%, and thereby mitigate the condensate bank by up to 84%. Phase behavior measurements indicate that adding GS to the oil–brine system could not induce any emulsions at different salinity levels. Moreover, NMR and permeability measurements reveal that the gemini surfactant has no effect on the pore system and no changes were observed in the T2 relaxation profiles with and without the GS injection. Ultimately, this work introduces a novel and effective treatment for mitigating the condensate bank. The new treatment showed an attractive performance in reducing liquid saturation and increasing the condensate relative permeability.

Study on pore structure evaluation of shale gas reservoir-Taking the Lower Cambrian Niutitang Formation in the Cenggong Block, Guizhou Province as an example

2020 ◽  
pp. 1-25
Author(s):  
Fuqiang Lai ◽  
Haiyan Mao ◽  
Jianping Bai ◽  
Daijan Gong ◽  
Guotong Zhang ◽  
...  
Keyword(s):  
High Pressure ◽  
Pore Structure ◽  
Structure Parameters ◽  
Pore Throat ◽  
Throat Radius ◽  
Volume Percentage ◽  
Nmr Logging ◽  
Mercury Intrusion ◽  
Niutitang Formation ◽  
Structure Evaluation

The storage and seepage space of shale is mainly composed of pores and fractures, while the microscopic pore structure and fracture distribution are very complicated. The accuracy of calculation of pore structure parameters is related to whether the reservoir evaluation is correct and effective. Taking the Niutitang Formation in the Cengong area of Guizhou as the research object. Firstly, based on the Archie formula, the process of the wellbore mud intrusion is approximated as the process of the laboratory high pressure mercury intrusion, combined with conventional and nuclear magnetic resonance logging data. The formula deduces a new model for the T2 spectrum conversion pseudo-capillary pressure curve. Then the model is calibrated by the high pressure mercury intrusion experimental data, and the pore structure parameters such as reservoir pore size distribution curve and maximum pore throat radius are calculated. The results show that the maximum pore throat radius and total porosity data calculated by NMR logging are relatively reliable, the median radius error is general, and the displacement pressure and median pressure error are relatively large. The pore volume percentage of 1-10 μm is up to 60%, and the micro-cracks are relatively developed, which is beneficial to the fracturing of the reservoir. Therefore, the use of NMR logging data combined with conventional logging can better reflect the pore structure characteristics of reservoirs, which provides a strong support for complex reservoir identification and qualitative prediction of productivity, and has a good application prospect.

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