Formation Damage Prevention by Using an Oil-Based Fracturing Fluid in Partially Depleted Oil Reservoirs of Western Siberia

1998 ◽  
Author(s):  
Marin Cikes ◽  
Srecko Cubric ◽  
Mekhraly R. Moylashov
Keyword(s):  
Western Siberia ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Fracturing Fluid ◽  
Damage Prevention

scholarly journals Field Experiments of Different Fracturing Designs in Tight Conglomerate Oil Reservoirs

2021 ◽  
Author(s):  
Daiyan Zhang ◽  
Shiying Ma ◽  
Jing Zhang ◽  
Yue Zhu ◽  
Bin Wang ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Field Experiments ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Formation Damage ◽  
Fracturing Fluid ◽  
Fracture Spacing ◽  
The Poor ◽  
The World ◽  
The Cost

Abstract Mahu oilfield is currently the largest tight conglomerate reservoir in the world, where Ma-131 and Ma-18 plays are the first two commercially developed reservoirs. In order to reduce the cost and explore the best fracturing parameters, field experiments have been conducted in these two plays since 2017. The types of proppant and fracturing fluid, the slickwater ratio, and the fracture spacing are mainly changed for comparison, and fracturing effects are evaluated to establish a reference for developing the neighboring plays in Mahu oilfield. This paper summarizes the fracturing parameters and production histories of 74 wells in Ma-131 and Ma-18 plays during four years of field operations. Firstly, results indicate that silica sands perform similar to ceramics in the Ma-131 play where the reservoir depth is smaller than 3300 m; however, in the Ma-18 play where the reservoir is deeper than 3500m, increasing the sand volume by 1.1 times still cannot reach the production in wells using ceramics. Secondly, when the fracture spacing is reduced, both oil production and water flowback become even smaller in wells using sands than those using ceramics; this is due to the increase of closure pressure and decrease of fluid volume per cluster respectively. Thirdly, when the crosslinked guar is replaced by the slickwater, no obvious change in oil production is noticed even though the volume of fracturing fluid is almost doubled; limited lengths of propped fractures due to the poor proppant-carrying ability of slickwater likely offset the production enhancement from the decrease of formation damage by slickwater. This paper summarizes learnings from the field experiments during four years of development in Mahu oilfield, and help guide the optimization of hydraulic fracturing parameters for future wells.

Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs

2021 ◽  
Author(s):  
Mingjun Chen ◽  
Peisong Li ◽  
Yili Kang ◽  
Xinping Gao ◽  
Dongsheng Yang ◽  
...  
Keyword(s):  
Heat Treatment ◽  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Gas Transport ◽  
Formation Damage ◽  
Transport Capacity ◽  
Fracturing Fluid ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
The Matrix

Abstract The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.

scholarly journals PROBLEMS OF COMPATIBILITY OF FORMATION WATER AND INJECTED WATER IN THE OIL FIELDS OF WESTERN SIBERIA

2017 ◽  
pp. 34-37 ◽  
Author(s):  
T. V. Semenova
Keyword(s):  
Industrial Wastewater ◽  
Western Siberia ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Oil Reservoir ◽  
Formation Water ◽  
Formation Pressure ◽  
Wide Spread ◽  
Calculation Methods ◽  
Almost All

A method of maintaining reservoir pressure using a system for formation pressure maintenance of oil reservoirs in the oil fields of Western Siberia is extremely wide-spread. In oil fields as a system for formation pressure maintenance are widely used almost all types of water resources including surface water, groundwater and industrial wastewater. Different calculation methods for predicting the formation and precipitation of salts based on quantitative criteria are used to forecast possible precipitation of calcium carbonate in the flooded oil reservoir areas.

scholarly journals A Novel Hydraulic Fracturing Method Based on the Coupled CFD-DEM Numerical Simulation Study

2020 ◽  
Vol 10 (9) ◽  
pp. 3027
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Zhili Li ◽  
Fenglan Huang ◽  
Chuhao Huang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Hydraulic Fracturing ◽  
Variable Viscosity ◽  
Oil Reservoirs ◽  
Fluid Viscosity ◽  
Low Density ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Fracturing Fluids ◽  
Transport Experiment

For the development of tight oil reservoirs, hydraulic fracturing employing variable fluid viscosity and proppant density is essential for addressing the problems of uneven placement of proppants in fractures and low propping efficiency. However, the influence mechanisms of fracturing fluid viscosity and proppant density on proppant transport in fractures remain unclear. Based on computational fluid dynamics (CFD) and the discrete element method (DEM), a proppant transport model with fluid–particle two-phase coupling is established in this study. In addition, a novel large-scale visual fracture simulation device was developed to realize the online visual monitoring of proppant transport, and a proppant transport experiment under the condition of variable viscosity fracturing fluid and proppant density was conducted. By comparing the experimental results and the numerical simulation results, the accuracy of the proppant transport numerical model was verified. Subsequently, through a proppant transport numerical simulation, the effects of fracturing fluid viscosity and proppant density on proppant transport were analyzed. The results show that as the viscosity of the fracturing fluid increases, the length of the “no proppant zone” at the front end of the fracture increases, and proppant particles can be transported further. When alternately injecting fracturing fluids of different viscosities, the viscosity ratio of the fracturing fluids should be adjusted between 2 and 5 to form optimal proppant placement. During the process of variable proppant density fracturing, when high-density proppant was pumped after low-density proppant, proppants of different densities laid fractures evenly and vertically. Conversely, when low-density proppant was pumped after high-density proppant, the low-density proppant could be transported farther into the fracture to form a longer sandbank. Based on the abovementioned observations, a novel hydraulic fracturing method is proposed to optimize the placement of proppants in fractures by adjusting the fracturing fluid viscosity and proppant density. This method has been successfully applied to more than 10 oil wells of the Bohai Bay Basin in Eastern China, and the average daily oil production per well increased by 7.4 t, significantly improving the functioning of fracturing. The proppant settlement and transport laws of proppant in fractures during variable viscosity and density fracturing can be efficiently revealed through a visualized proppant transport experiment and numerical simulation study. The novel fracturing method proposed in this study can significantly improve the hydraulic fracturing effect in tight oil reservoirs.

Flowback Stimulation of Frac Fluid in Tight Oil Reservoirs Through Supercritical Condition

2021 ◽  
Author(s):  
Ying Li ◽  
Ying Ai ◽  
Haitao Li ◽  
Mingjun Chen
Keyword(s):  
Molecular Weight ◽  
Hydraulic Fracturing ◽  
Supercritical Water ◽  
Oil Recovery ◽  
Oil Reservoirs ◽  
Fracturing Fluid ◽  
Tight Sandstone ◽  
Water Condition ◽  
Water Hydraulic ◽  
Oil Components

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.

Sign in / Sign up

Export Citation Format

Share Document